Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Apr. 01, 2014 | Jul. 31, 2013 | |
Document And Entity Information [Abstract] | ' | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Jan-14 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Document Fiscal Year Focus | '2014 | ' | ' |
Entity Registrant Name | 'Triangle Petroleum Corp | ' | ' |
Entity Central Index Key | '0001281922 | ' | ' |
Trading Symbol | 'tplm | ' | ' |
Current Fiscal Year End Date | '--01-31 | ' | ' |
Entity Filer Category | 'Accelerated Filer | ' | ' |
Entity Well-known Seasoned Issuer | 'No | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Public Float | ' | ' | $328,585,579 |
Entity Common Stock, Shares Outstanding | ' | 85,941,961 | ' |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
In Thousands, unless otherwise specified | ||
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 |
Oil and 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 |
CURRENT LIABILITIES | ' | ' |
Accounts payable | 53,066 | 37,043 |
Accrued liabilities: | ' | ' |
Exploration and development | 68,192 | 30,433 |
Other | 25,926 | 7,486 |
Short-term borrowings on debt | 8,851 | ' |
Asset retirement obligations | 3,333 | 2,949 |
Total current liabilities | 159,368 | 77,911 |
LONG-TERM LIABILITIES | ' | ' |
Long-term borrowings on credit facilities | 196,065 | 25,000 |
5% convertible note | 129,290 | 123,023 |
Other notes payable | 9,002 | ' |
Asset retirement obligations | 1,296 | 473 |
Deferred tax liability | 8,262 | ' |
Derivative liability | ' | 292 |
Other | 1,139 | ' |
Total liabilities | 504,422 | 226,699 |
COMMITMENT AND CONTINGENCIES (Note 15) | ' | ' |
STOCKHOLDERS' EQUITY | ' | ' |
Common stock, $0.00001 par value, 140,000,000 shares authorized; 85,735,827 and 46,733,011 shares issued and outstanding at January 31, 2014 and January 31, 2013, respectively | ' | ' |
Additional paid-in capital | 571,702 | 323,642 |
Accumulated deficit | -48,540 | -122,020 |
Accumulated other comprehensive income | ' | ' |
Total stockholders' equity | 523,162 | 201,622 |
Total liabilities and stockholders' equity | $1,027,584 | $428,321 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
Consolidated Balance Sheets [Abstract] | ' | ' |
Convertible note, interest rate | 5.00% | 5.00% |
Common stock, par value | $0.00 | $0.00 |
Common stock, shares authorized | 140,000,000 | 140,000,000 |
Common stock, shares issued | 85,735,827 | 46,733,011 |
Common stock, shares outstanding | 85,735,827 | 46,733,011 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations and Comprehensive Income (Loss) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
REVENUES | ' | ' | ' |
Oil and natural gas sales | $160,548 | $39,614 | $8,136 |
Oilfield services | 98,199 | 20,747 | ' |
Other | ' | 340 | ' |
Total revenues | 258,747 | 60,701 | 8,136 |
EXPENSES: | ' | ' | ' |
Production taxes | 18,006 | 4,492 | 896 |
Lease operating expenses | 14,454 | 3,566 | 1,542 |
Gathering, transportation and processing | 4,302 | 150 | 22 |
Depreciation and amortization | 57,048 | 15,081 | 3,114 |
Impairment of oil and natural gas properties | ' | ' | 10,416 |
Accretion and other asset retirement obligation expenses | 1,018 | 184 | 167 |
Oilfield services | 82,327 | 16,606 | ' |
General and administrative: | ' | ' | ' |
Stock-based compensation | 7,830 | 6,466 | 7,567 |
Salaries and benefits | 17,299 | 14,922 | 4,628 |
Other general and administrative | 9,797 | 7,403 | 4,737 |
Foreign exchange loss | ' | 1 | 22 |
Total operating expenses | 212,081 | 68,871 | 33,111 |
INCOME (LOSS) FROM OPERATIONS | 46,666 | -8,170 | -24,975 |
OTHER INCOME (EXPENSE): | ' | ' | ' |
Gain on equity investment derivative | 39,785 | ' | ' |
Gain (loss) from derivative activities | 1,082 | -3,570 | ' |
Interest expense | -7,686 | -2,818 | ' |
Loss from equity investment | ' | -283 | ' |
Interest income | 200 | 134 | 287 |
Other income (expense) | 1,374 | 223 | 265 |
Total other income (expense) | 34,755 | -6,314 | 552 |
NET INCOME (LOSS) BEFORE INCOME TAXES | 81,421 | -14,484 | -24,423 |
Income tax provision | -7,941 | ' | ' |
NET INCOME (LOSS) | 73,480 | -14,484 | -24,423 |
Less: net loss attributable to the noncontrolling interest in subsidiary | ' | 724 | 145 |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | 73,480 | -13,760 | -24,278 |
Net income (loss) per common share outstanding: | ' | ' | ' |
Basic | $1.07 | ($0.31) | ($0.60) |
Diluted | $0.91 | ($0.31) | ($0.60) |
Weighted average common shares outstanding: | ' | ' | ' |
Basic | 68,578,553 | 44,475,201 | 40,707,957 |
Diluted | 84,557,542 | 44,475,201 | 40,707,957 |
COMPREHENSIVE INCOME (LOSS): | ' | ' | ' |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | 73,480 | -13,760 | -24,278 |
Other comprehensive income (loss) | ' | ' | ' |
Total comprehensive income (loss) | $73,480 | ($13,760) | ($24,278) |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' | ' |
Net income (loss) | $73,480 | ($14,484) | ($24,423) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ' | ' | ' |
Depreciation and amortization | 57,048 | 15,081 | 3,114 |
Impairment of oil and natural gas properties | ' | ' | 10,416 |
Stock-based compensation | 7,830 | 6,637 | 7,567 |
Interest expense not paid in cash | 6,267 | 2,738 | ' |
Accretion and other asset retirement obligation expenses | 1,018 | 184 | 167 |
(Gain) loss on derivative activities | -1,082 | 3,578 | ' |
(Gain) on equity investment derivative | -39,785 | ' | ' |
(Gain) on settlements on commodity derivative instruments | -754 | ' | ' |
Loss from equity investment | ' | 283 | ' |
Equity investment cash distribution | 3,150 | ' | ' |
(Gain) on securities held for investment | -1,040 | -204 | ' |
Deferred income tax liability | 7,941 | ' | ' |
Changes in related current assets and current liabilities: | ' | ' | ' |
Inventory, deposits and prepaid expenses | -3,025 | -2,555 | -136 |
Accounts receivable: | ' | ' | ' |
Oil and natural gas sales | -9,825 | -5,202 | -5,267 |
Trade | -55,958 | -24,612 | -3,919 |
Related party | ' | ' | ' |
Other | -146 | -481 | -406 |
Accounts payable and accrued liabilities | 40,951 | 22,054 | 425 |
Asset retirement expenditures | -484 | -253 | -304 |
Cash provided by (used in) operating activities | 85,586 | 2,764 | -12,766 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' | ' |
Oil and natural gas property expenditures | -401,109 | -135,818 | -107,594 |
Sale of oil and natural gas properties | ' | 3,265 | 47 |
Purchase of oil field services equipment | -27,596 | ' | ' |
Purchase of other property and equipment | -10,928 | -31,037 | -1,319 |
Sale of marketable securities | 6,105 | ' | ' |
Equity investment in Caliber Midstream Partners, L.P. | -18,000 | -12,001 | ' |
Purchase of derivative contracts | ' | -3,889 | ' |
Deposits on equipment under construction | 182 | -182 | -5,648 |
Non-controlling interest in subsidiary | ' | -50 | 4,000 |
Proceeds from return of long-term deposit | ' | ' | 86 |
Cash advanced to operators for oil and gas | ' | ' | -724 |
Acquisition of Team Well Services, Inc. | -7,715 | ' | ' |
Other | 345 | ' | 106 |
Cash used in investing activities | -458,716 | -179,712 | -111,046 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' | ' |
Proceeds from issuance of common stock | 245,333 | ' | 142,313 |
Stock offering costs | -7,072 | ' | -7,570 |
Proceeds from credit facilities | 211,820 | 41,700 | ' |
Repayments of credit facilities | -32,306 | -16,700 | ' |
Proceeds from notes payable | 14,430 | 120,000 | ' |
Repayments of notes payable | -5,876 | ' | ' |
Debt issuance costs | -2,670 | -1,270 | ' |
Cash paid to settle tax on vested restricted stock units | -2,058 | -1,884 | ' |
Purchase minority interest In RockPile | ' | -609 | ' |
Issuance of common stock for exercise of options | 162 | 13 | 111 |
Cash provided by financing activities | 421,763 | 141,250 | 134,854 |
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS | 48,633 | -35,698 | 11,042 |
CASH AND EQUIVALENTS, BEGINNING OF PERIOD | 33,117 | 68,815 | 57,773 |
CASH AND EQUIVALENTS, END OF PERIOD | $81,750 | $33,117 | $68,815 |
Consolidated_Statements_Of_Sto
Consolidated Statements Of Stockholders' Equity (USD $) | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] | Accumulated Deficit [Member] | Non-controlling Interest In Subsidiary [Member] | Common Stock at $7.50 [Member] | Common Stock at $6.00 [Member] | Common Stock at $7.24 [Member] | Common Stock at $6.25 [Member] | Common Stock at $7.20 [Member] | Total |
In Thousands, except Share data | Common Stock at $7.50 [Member] | Common Stock at $6.00 [Member] | Common Stock at $7.24 [Member] | Common Stock at $6.25 [Member] | Common Stock at $7.20 [Member] | Common Stock at $7.50 [Member] | Common Stock at $6.00 [Member] | Common Stock at $7.24 [Member] | Common Stock at $6.25 [Member] | Common Stock at $7.20 [Member] | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | |
USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | ||||||||||||||||
Balance at Jan. 31, 2011 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $159,788 | ($83,982) | ' | ' | ' | ' | ' | ' | $75,806 |
Balance, shares at Jan. 31, 2011 | ' | ' | ' | ' | ' | 22,525,672 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued for the purchase of oil and natural gas properties, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,780 | ' | ' | ' | ' | ' | ' | ' | 11,780 |
Shares issued for the purchase of oil and natural gas properties, shares | ' | ' | ' | ' | ' | 1,437,699 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock issued, value | ' | ' | ' | ' | ' | ' | 142,312 | ' | ' | ' | ' | ' | ' | ' | 142,312 | ' | ' | ' | ' | ' |
Common stock issued, shares | 18,975,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock offering costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,569 | ' | ' | ' | ' | ' | ' | ' | -7,569 |
Exercise of stock options, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 111 | ' | ' | ' | ' | ' | ' | ' | 111 |
Exercise of stock options, shares | ' | ' | ' | ' | ' | 82,501 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 185 | ' | ' | ' | ' | ' | ' | ' | 185 |
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | 24,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Vesting of restricted stock units (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | 471,086 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,593 | ' | ' | ' | ' | ' | ' | ' | 7,593 |
Non-controlling interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000 | ' | ' | ' | ' | ' | 4,000 |
Net income (loss) for the year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -24,278 | -145 | ' | ' | ' | ' | ' | -24,423 |
Balance at Jan. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 314,200 | -108,260 | 3,855 | ' | ' | ' | ' | ' | 209,795 |
Balance, shares at Jan. 31, 2012 | ' | ' | ' | ' | ' | 43,515,958 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued for the purchase of oil and natural gas properties, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,204 | ' | ' | ' | ' | ' | ' | ' | 1,204 |
Shares issued for the purchase of oil and natural gas properties, shares | ' | ' | ' | ' | ' | 225,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued for services | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73 | ' | ' | ' | ' | ' | ' | ' | 73 |
Shares issued for services, shares | ' | ' | ' | ' | ' | 10,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exercise of stock options, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13 | ' | ' | ' | ' | ' | ' | ' | 13 |
Exercise of stock options, shares | ' | ' | ' | ' | ' | 4,167 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,167 |
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 99 | ' | ' | ' | ' | ' | ' | ' | 99 |
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | 17,230 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Vesting of restricted stock units (net of shares surrendered for taxes) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,884 | ' | ' | ' | ' | ' | ' | ' | -1,884 |
Vesting of restricted stock units (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | 774,941 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Acquire minority interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,522 | ' | -3,131 | ' | ' | ' | ' | ' | -609 |
Acquire minority interest in subsidiary, shares | ' | ' | ' | ' | ' | 2,185,715 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,415 | ' | ' | ' | ' | ' | ' | ' | 7,415 |
Net income (loss) for the year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -13,760 | -724 | ' | ' | ' | ' | ' | -14,484 |
Balance at Jan. 31, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 323,642 | -122,020 | ' | ' | ' | ' | ' | ' | 201,622 |
Balance, shares at Jan. 31, 2013 | ' | ' | ' | ' | ' | 46,733,011 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 46,733,011 |
Shares issued for the purchase of oil and natural gas properties, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,438 | ' | ' | ' | ' | ' | ' | ' | 2,438 |
Shares issued for the purchase of oil and natural gas properties, shares | ' | ' | ' | ' | ' | 325,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock issued, value | ' | ' | ' | ' | ' | ' | ' | 55,800 | ' | 107,813 | 81,720 | ' | ' | ' | ' | 55,800 | ' | 107,813 | 81,720 | ' |
Common stock issued, shares | ' | 9,300,000 | ' | 17,250,000 | 11,350,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock offering costs | ' | ' | ' | ' | ' | ' | ' | -115 | ' | -6,045 | -912 | ' | ' | ' | ' | -115 | ' | -6,045 | -912 | ' |
Shares issued for services | ' | ' | ' | ' | ' | ' | ' | ' | 36 | ' | ' | ' | ' | ' | ' | ' | 36 | ' | ' | ' |
Shares issued for services, shares | ' | ' | 5,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exercise of stock options, value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 162 | ' | ' | ' | ' | ' | ' | ' | 162 |
Exercise of stock options, shares | ' | ' | ' | ' | ' | 108,333 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 108,333 |
Vesting of restricted stock units (net of shares surrendered for taxes) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,058 | ' | ' | ' | ' | ' | ' | ' | -2,058 |
Vesting of restricted stock units (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | 664,483 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,221 | ' | ' | ' | ' | ' | ' | ' | 9,221 |
Net income (loss) for the year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73,480 | ' | ' | ' | ' | ' | ' | 73,480 |
Balance at Jan. 31, 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $571,702 | ($48,540) | ' | ' | ' | ' | ' | ' | $523,162 |
Balance, shares at Jan. 31, 2014 | ' | ' | ' | ' | ' | 85,735,827 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85,735,827 |
Consolidated_Statements_Of_Sto1
Consolidated Statements Of Stockholders' Equity (Parenthetical) (USD $) | Jan. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 |
Common Stock at $7.50 [Member] | Common Stock at $6.00 [Member] | Common Stock at $7.24 [Member] | Common Stock at $6.25 [Member] | Common Stock at $7.20 [Member] | |
Shares issued, price per share | $7.50 | $6 | $7.24 | $6.25 | $7.20 |
Description_Of_Business
Description Of Business | 12 Months Ended |
Jan. 31, 2014 | |
Description Of Business [Abstract] | ' |
Description Of Business | ' |
1. DESCRIPTION OF BUSINESS | |
Triangle Petroleum Corporation (“we,” “us,” “our,” the “Company,” or “Triangle”) is a growth-oriented, independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. | |
We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana. Our core focus area is in McKenzie and Williams counties, North Dakota (our “Core Acreage”). We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”). | |
In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin. RockPile began operations in July 2012. | |
In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund (“FREIF”). Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin. | |
The Company also holds leasehold interests in acreage in the Maritimes Basin of Nova Scotia, which we fully impaired as of January 31, 2012. | |
Basis_Of_Presentation
Basis Of Presentation | 12 Months Ended | |||
Jan. 31, 2014 | ||||
Basis Of Presentation [Abstract] | ' | |||
Basis Of Presentation | ' | |||
2. BASIS OF PRESENTATION | ||||
These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3 – Summary of Significant Accounting Policies describes our significant accounting policies. | ||||
Use of Estimates | ||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management believes the major estimates and assumptions impacting our consolidated financial statements are the following: | ||||
· | estimates of proved reserves of oil and natural gas, which affect the calculations of amortization and impairment of capitalized costs of oil and natural gas properties; | |||
· | estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells; | |||
· | estimates as to the future realization of deferred income tax assets; | |||
· | the assumption required by GAAP that proved reserves and proved reserve value for measuring capitalized cost impairment be based (for each proved property) on simple averages of the preceding twelve months’ historical oil and natural gas prices on the first day of each month; | |||
· | impairment of undeveloped properties and other assets; | |||
· | depreciation of property and equipment; | |||
· | valuation of commodity derivative instruments; and | |||
· | impairment of goodwill. | |||
The estimated fair values of our unevaluated oil and natural gas properties affects our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and natural gas properties. | ||||
Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. | ||||
Principles of Consolidation | ||||
The accounts of Triangle and its wholly owned subsidiaries are presented in the accompanying consolidated financial statements. The accounts of Triangle Petroleum Corporation and its subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. | ||||
These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: (i) TUSA, incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile, organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (iv) Leaf Minerals, LLC, organized in the State of Colorado, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, and (vi) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. Additionally, Triangle Caliber Holdings LLC is a joint venture partner in Caliber Midstream Partners LP (“Caliber). The investment in Caliber is accounted for utilizing the equity method of accounting. See Note 11 – Equity Investment for further discussion on Caliber. | ||||
The Company’s 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”), used in these Notes to Consolidated Financial Statements refer to the fiscal years ended January 31, 2015, 2014, 2013, and 2012, respectively. | ||||
Certain amounts in prior years’ consolidated financial statements have been reclassified to conform to the FY2014 financial statement presentation. Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported. | ||||
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 12 Months Ended | ||
Jan. 31, 2014 | |||
Summary Of Significant Accounting Policies [Abstract] | ' | ||
Summary Of Significant Accounting Policies | ' | ||
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Cash and Cash Equivalents | |||
Cash and cash equivalents consist of cash in banks in the United States and Canada. Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. | |||
Fair Value of Financial Instruments | |||
The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments and equity investment derivatives (See Note 14 – Derivative Instruments), marketable securities (See Note 12 - Investment in Marketable Securities) and long-term debt (See Note 13 – Long-Term Debt). Triangle measures fair value in accordance with ASC Topic 820, Fair Value Measurement and Disclosure. ASC 820 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. | |||
The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. Commodity derivatives are recorded on the consolidated balance sheets at amounts which approximate their fair value. The Company’s equity investment derivatives are included in equity investments and recorded at amounts which approximate their fair value on the consolidated balance sheets. The carrying amount of the Company's credit facilities approximates fair value as it bears interest at variable rates over the term of the loan. The Company's 5% Convertible Promissory Note (the “Convertible Note”) issued by the Company to NGP Triangle Holdings, LLC (“NGP”) on July 31, 2012, is recorded at cost and the fair value is disclosed in Note 10 - Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. | |||
Accounts Receivable and Credit Policies | |||
We have certain trade receivables due under normal trade terms and primarily consisting of oil and natural gas sales receivables and trade receivables from third parties participating in the drilling, completion and production of wells we operate and wells for which RockPile provides services. Our management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. At January 31, 2014 and 2013, management had determined that no allowance for uncollectible oil and natural gas trade or sales receivables was necessary. | |||
Oilfield services accounts receivable are stated at the amount billed to customers and are ordinarily due within 30 days of the invoice date. As of the date of these consolidated financial statements, and since inception, the Company has collected all amounts owed. As a result, the Company has not provided for an allowance for doubtful accounts as of the date of the consolidated financial statements. RockPile’s current customer base is comprised of TUSA and other highly credit-worthy third-party customers. Periodically, the Company performs a review of its customer base including outstanding receivables, historical collection information, existing economic conditions and the customer’s creditworthiness to determine the need for establishing an allowance for doubtful accounts. A provision for doubtful accounts would be recorded when non-payment of amounts owed is deemed probable. | |||
Inventories | |||
Inventories maintained by the Company consist of well equipment, sand, chemicals and/or ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors in evaluating net realizable value. | |||
Investment in Unconsolidated Entities | |||
The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations and comprehensive income (loss) (after elimination of intra-company profits and losses). The carrying value of the Company’s investments in unconsolidated entities is recorded in the Equity Investment line of the Consolidated Balance Sheets. The Company records losses of the unconsolidated entities only to the extent of the Company's investment. | |||
We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. See discussion in Note 11 – Equity Investment. | |||
Concentration of Credit Risk | |||
Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash. We maintain substantially all cash assets at four financial institutions - Wells Fargo Bank, RBC Canada, Citi Private Bank and Chase Bank. We periodically evaluate the credit worthiness of financial institutions, and we maintain cash accounts only in large, high quality financial institutions. We believe that credit risk associated with cash is remote. The Company often has balances in excess of the federally insured limits. | |||
The Company's receivables are comprised of oil and natural gas revenue receivables, joint interest billings receivable and receivables associated with oilfield services. The amounts are due from a number of entities. Therefore, the collectability is dependent upon the general economic conditions of a few purchasers, joint interest owners and customers. The receivables are not collateralized. To date the Company has had no bad debts. | |||
The Company's commodity derivative contracts are currently with four counterparties. The counterparties to the derivative instruments are highly rated entities. The creditworthiness of counter-parties is subject to continuing review. | |||
Oil and Natural Gas Properties | |||
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 in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively. The cost pools are amortized on a unit-of-production basis using proved oil and gas reserves. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. 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 for each full cost pool. This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) do not exceed the sum of (i) the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, (ii) the pool’s cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (iv) all related tax effects. If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense. Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. See Note 8 - Property and Equipment for disclosures regarding ceiling test impairments. | |||
Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. | |||
Under the full cost method, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | |||
Other Property and Equipment | |||
We record at cost any long-lived tangible assets that are not oil and natural gas properties. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived property and equipment, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not found or recognized any impairment losses on such other property and equipment. Depreciation is recorded using the straight-line method (to the extent of estimated salvage values) over the estimated useful lives of the related assets as follows: | |||
Depreciable | |||
Asset | Life (years) | ||
Building and improvements | 20-Oct | ||
Oilfield services equipment | 5 | ||
Vehicles | 5 | ||
Leasehold improvements | 10 | ||
Software and computers | 5-Mar | ||
Office equipment | 3 | ||
Asset Retirement Obligations | |||
We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base. | |||
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 are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation or Three Forks formation in North Dakota. | |||
Our internal Senior Reservoir Engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available. | |||
Deferred Financing Costs | |||
Deferred financing costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company's credit facilities and Convertible Note. Deferred financing costs are amortized to interest expense on a straight-line basis over the respective borrowing term. | |||
Derivative Instruments | |||
Commodity derivative | |||
Our commodity derivative contracts are measured at fair value and are included on the consolidated balance sheets as either derivative assets or liabilities. The accounting treatment for settlements and the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the contracts we entered into during the periods covered in these consolidated financial statements. Realized and unrealized gains and losses on commodity derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. Net gains and losses on commodity derivative activities are recorded based on the changes in the fair values of the derivative instruments. Cash settlements of our commodity derivative contracts are included in cash flows from operating activities in our consolidated statements of cash flows. | |||
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 in equity investment on the consolidated balance sheet. Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations. | |||
Income Taxes | |||
Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes. We compute deferred income taxes using the liability method whereby deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. | |||
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). | |||
Contingencies | |||
A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. We have not accrued for any contingencies as of January 31, 2014. | |||
Revenue Recognition | |||
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 has transferred, and/or collectability is reasonably assured and evidenced by a contract. Additionally, there were no oil or natural gas sales imbalances at January 31, 2014 2013 and 2012. | |||
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 only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment as defined in the contract, whether or not those services are actually utilized. To the extent customers utilize more than the contracted minimum, they are invoiced for such excess at rates defined in the contract. As of January 31, 2014, the Company has not entered into any pressure pumping term contracts with third parties. | |||
Under the full cost method, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | |||
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. | |||
Earnings per Share | |||
Basic earnings per share (EPS) is computed by dividing net gain (or loss) available to common stock (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS gives effect to all dilutive instruments outstanding during the period including convertible debt, restricted stock units, stock options and warrants, using the treasury stock method. In computing diluted EPS, the average stock price for the period is used in determining the number of shares assumed to be purchased from the exercise of stock options or warrants. Diluted EPS excludes instruments if their effect is anti-dilutive. | |||
Business Combinations | |||
Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair values at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of the net assets acquired and their tax basis. Any excess of purchase price over the fair value of the net assets acquired is recognized as goodwill. Associated transaction costs are expensed when incurred. | |||
Goodwill | |||
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 would be a significant decline to 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 to fair value of a reporting unit is more likely than not, 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 a reporting unit based on discounted future probability-weighted cash flows. If Step 1 indicates that the carrying value of a reporting unit is in excess of 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 calculated in Step 2. Our goodwill represents consideration paid in excess of the fair value of the identifiable net assets acquired in a business combination. Our goodwill results from the October 16, 2013 acquisition of Team Well Service, Inc. by RockPile and is preliminary (see Note 9 – Intangible Assets and Goodwill). We review goodwill for impairment annually, or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of the reporting unit could be less than its carrying amount. | |||
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. | |||
Off Balance Sheet Arrangements | |||
We have no significant off balance sheet arrangements. | |||
Segment Information | |||
In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have 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 exploration and production operating segment is responsible for finding and producing oil and natural gas. The oilfield services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties. See Note 4 - Segment Reporting. | |||
Recent Accounting Developments | |||
No significant accounting standards applicable to Triangle have been issued during FY2014. | |||
Segment_Reporting
Segment Reporting | 12 Months Ended | |||||||||||||||||||||||
Jan. 31, 2014 | ||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||||||||||
Segment Reporting | ' | |||||||||||||||||||||||
4. SEGMENT REPORTING | ||||||||||||||||||||||||
We conduct our operations with two reportable operating segments. We identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as all operations are in the Williston Basin of the United States. The exploration and production operating segment is responsible for finding and producing oil and natural gas. The oilfield services operating segment is responsible for a variety of oilfield and complementary services for both Triangle-operated wells and wells operated by third- parties. | ||||||||||||||||||||||||
Management evaluates the performance of our segments based upon income (loss) before income taxes. The following table presents selected financial information for Triangle’s operating segments for the fiscal years ended January 31, 2014 and 2013. RockPile was formed in June 2011 and was initially capitalized in October 2011. Our oilfield services business was previously presented as part of other operations as it had not yet begun operations and was not considered significant. Therefore, no segment information was presented for the fiscal year ended January 31, 2012 and is not presented below. | ||||||||||||||||||||||||
For the year ended January 31, 2014 | ||||||||||||||||||||||||
(in thousands) | Exploration and Production | Oilfield Services | Corporate and Other (1) | Eliminations and Other | Consolidated Total | |||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Oil and natural gas sales | $ | 160,548 | $ | - | $ | - | $ | - | $ | 160,548 | ||||||||||||||
Oilfield services for third parties | - | 102,606 | - | -4,407 | 98,199 | |||||||||||||||||||
Intersegment revenues | - | 91,019 | - | -91,019 | - | |||||||||||||||||||
Other | - | - | 1,192 | -1,192 | - | |||||||||||||||||||
Total revenues | 160,548 | 193,625 | 1,192 | -96,618 | 258,747 | |||||||||||||||||||
Expenses | ||||||||||||||||||||||||
Production taxes and other lease operating | 32,460 | - | - | - | 32,460 | |||||||||||||||||||
Gathering, transportation and processing | 4,302 | - | - | - | 4,302 | |||||||||||||||||||
Depreciation and amortization | 51,065 | 8,905 | 620 | -3,542 | 57,048 | |||||||||||||||||||
Accretion and other asset retirement obligation expenses | 1,018 | - | - | - | 1,018 | |||||||||||||||||||
Cost of oilfield services | - | 142,339 | - | -60,012 | 82,327 | |||||||||||||||||||
General and Administrative: | ||||||||||||||||||||||||
Stock-based compensation | 1,127 | 590 | 6,113 | - | 7,830 | |||||||||||||||||||
Other general and administrative | 7,777 | 11,116 | 8,203 | - | 27,096 | |||||||||||||||||||
Total operating expenses | 97,749 | 162,950 | 14,936 | -63,554 | 212,081 | |||||||||||||||||||
Income (loss) from operations | 62,799 | 30,675 | -13,744 | -33,064 | 46,666 | |||||||||||||||||||
Other income (expense), net | 125 | -991 | 37,805 | -2,184 | 34,755 | |||||||||||||||||||
Net income (loss) before income taxes | $ | 62,924 | $ | 29,684 | $ | 24,061 | $ | -35,248 | $ | 81,421 | ||||||||||||||
Total Assets | $ | 821,042 | $ | 126,114 | $ | 177,500 | $ | -97,072 | $ | 1,027,584 | ||||||||||||||
Net oil and natural gas properties | $ | 730,718 | $ | - | $ | - | $ | -47,931 | $ | 682,787 | ||||||||||||||
Oilfield services equipment - net | $ | - | $ | 46,586 | $ | - | $ | - | $ | 46,586 | ||||||||||||||
Other property and equipment - net | $ | 1,594 | $ | 18,912 | $ | 4,001 | $ | - | $ | 24,507 | ||||||||||||||
Total Liabilities | $ | 318,875 | $ | 64,017 | $ | 141,671 | $ | -20,141 | $ | 504,422 | ||||||||||||||
-1 | Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or oilfield services segments. These subsidiaries have limited activity. | |||||||||||||||||||||||
For the year ended January 31, 2013 | ||||||||||||||||||||||||
(in thousands) | Exploration and Production | Oilfield Services | Corporate and Other (1) | Eliminations and Other | Consolidated Total | |||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Oil and natural gas sales | $ | 39,614 | $ | - | $ | - | $ | - | $ | 39,614 | ||||||||||||||
Oilfield services for third parties | - | 22,535 | - | -1,788 | 20,747 | |||||||||||||||||||
Intersegment revenues | - | 34,672 | - | -34,672 | - | |||||||||||||||||||
Other | 248 | - | 975 | -883 | 340 | |||||||||||||||||||
Total revenues | 39,862 | 57,207 | 975 | -37,343 | 60,701 | |||||||||||||||||||
Expenses | ||||||||||||||||||||||||
Production taxes and other lease operating | 8,058 | - | - | - | 8,058 | |||||||||||||||||||
Gathering, transportation and processing | 150 | - | - | - | 150 | |||||||||||||||||||
Depreciation and amortization | 13,578 | 2,857 | 378 | -1,732 | 15,081 | |||||||||||||||||||
Accretion and other asset retirement obligation expenses | 184 | - | - | - | 184 | |||||||||||||||||||
Cost of oilfield services | - | 39,534 | - | -22,928 | 16,606 | |||||||||||||||||||
General and Administrative: | ||||||||||||||||||||||||
Stock-based compensation | 2,507 | 617 | 3,342 | - | 6,466 | |||||||||||||||||||
Other general and administrative | 6,838 | 11,130 | 4,358 | - | 22,326 | |||||||||||||||||||
Total operating expenses | 31,315 | 54,138 | 8,078 | -24,660 | 68,871 | |||||||||||||||||||
Income (loss) from operations | 8,547 | 3,069 | -7,103 | -12,683 | -8,170 | |||||||||||||||||||
Other income (expense), net | -6,318 | 4 | - | - | -6,314 | |||||||||||||||||||
Net income (loss) before income taxes | $ | 2,229 | $ | 3,073 | $ | -7,103 | $ | -12,683 | $ | -14,484 | ||||||||||||||
Total Assets | $ | 362,878 | $ | 38,668 | $ | 40,220 | $ | -13,445 | $ | 428,321 | ||||||||||||||
Net oil and natural gas properties | $ | 310,557 | $ | - | $ | - | $ | -11,800 | $ | 298,757 | ||||||||||||||
Oilfield services equipment - net | $ | - | $ | 18,878 | $ | - | $ | - | $ | 18,878 | ||||||||||||||
Other property and equipment - net | $ | 1,597 | $ | 12,443 | $ | 1,739 | $ | - | $ | 15,779 | ||||||||||||||
Total Liabilities | $ | 91,134 | $ | 11,845 | $ | 125,364 | $ | -1,644 | $ | 226,699 | ||||||||||||||
-1 | Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or oilfield services segments. These subsidiaries have limited activity. | |||||||||||||||||||||||
Eliminations and Other | ||||||||||||||||||||||||
For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs. | ||||||||||||||||||||||||
Under the full cost method, we deferred recognition of an additional $4.4 million and $1.8 million in service income in FY2014 and FY2013, respectively, by charging such service income against service revenue and crediting capitalized costs of the related wells. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | ||||||||||||||||||||||||
Oil_And_Natural_Gas_Properties
Oil And Natural Gas Properties | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Oil And Natural Gas Properties [Abstract] | ' | ||||||||||||
Oil And Natural Gas Properties | ' | ||||||||||||
5. OIL AND NATURAL GAS PROPERTIES | |||||||||||||
Aggregate Capitalized Costs | |||||||||||||
The table below reflects the aggregate capitalized costs relating to our U.S. oil and natural gas producing activities at January 31, 2014 and 2013: | |||||||||||||
January 31, | January 31, | ||||||||||||
(in thousands) | 2014 | 2013 | |||||||||||
Oil and natural gas properties, full cost method: | |||||||||||||
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, full cost method | 750,444 | 315,423 | |||||||||||
Less accumulated amortization | -67,657 | -16,666 | |||||||||||
Net carrying value of oil and natural gas properties | $ | 682,787 | $ | 298,757 | |||||||||
Oil and Natural Gas Property Additions | |||||||||||||
During FY2014 and FY2013, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $434.4 million and $168.4 million, including $121.6 million and $20.1 million for the acquisition of leaseholds, respectively. Total consideration consisted of cash and other working capital of $432.0 million and $167.2 million and common stock of $2.4 million and $1.2 million for FY2014 and FY2013, respectively. | |||||||||||||
During FY2014 and FY2013, we capitalized $3.7 million and $2.0 million, respectively, of internal land, geology and operations department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. The internal land and geology department costs were capitalized to unevaluated costs. | |||||||||||||
Costs Incurred | |||||||||||||
The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States for fiscal years ended January 31, 2014, 2013 and 2012: | |||||||||||||
Years Ended January 31, | |||||||||||||
(in thousands) | 2014 | 2013 | 2012 | ||||||||||
Costs incurred during the year | |||||||||||||
Acquisition of properties: | |||||||||||||
Proved | $ | 80,201 | $ | 623 | $ | - | |||||||
Unproved | 41,377 | 20,570 | 87,226 | ||||||||||
Exploration | 96,731 | 55,583 | 40,728 | ||||||||||
Development | 216,046 | 91,666 | 4,706 | ||||||||||
Oil and natural gas expenditures | 434,355 | 168,442 | 132,660 | ||||||||||
Asset retirement obligation, net | 676 | 370 | 3 | ||||||||||
$ | 435,031 | $ | 168,812 | $ | 132,663 | ||||||||
Costs Not Being Amortized | |||||||||||||
The following table summarizes oil and natural gas property costs not being amortized at January 31, 2014, by year that the costs were incurred: | |||||||||||||
Type of Capitalized Cost | |||||||||||||
(in thousands) | Total | Acquisition | Exploration | Capitalized Interest | |||||||||
Capitalized at January 31, 2014 | |||||||||||||
Not yet being amortized | $ | 121,393 | $ | 108,147 | $ | 10,225 | $ | 3,021 | |||||
Incurred in fiscal year 2014 | $ | 54,623 | $ | 41,377 | $ | 10,225 | $ | 3,021 | |||||
Incurred in fiscal year 2013 | $ | 15,618 | $ | 15,618 | $ | - | $ | - | |||||
Incurred in fiscal year 2012 | $ | 44,620 | $ | 44,620 | $ | - | $ | - | |||||
Incurred in prior years | $ | 6,532 | $ | 6,532 | $ | - | $ | - | |||||
The $121.4 million of costs not being amortized includes $8.9 million in costs for unevaluated wells in progress expected to be completed prior to January 31, 2015. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization. | |||||||||||||
The majority of the unproved oil and natural gas property costs, which are not subject to amortization, relate to oil and natural gas property acquisitions and leasehold acquisition costs as well as work-in-progress on various projects. The Company expects that substantially all of its unproved property costs as of January 31, 2014 will be reclassified to proved properties over the next five years. | |||||||||||||
Depreciation and Amortization Expense | |||||||||||||
Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2014, 2013 and 2012 was $50.1 million ($26.43/Boe), $13.5 million ($27.75/Boe) and $3.0 million ($31.85/Boe), respectively. | |||||||||||||
Acquisitions
Acquisitions | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Acquisitions [Abstract] | ' | ||||||
Acquisitions | ' | ||||||
6. ACQUISITIONS | |||||||
Kodiak Oil & Gas Property Acquisition | |||||||
On August 28, 2013, TUSA acquired interests in approximately 5,600 net acres of Williston Basin leaseholds and related producing properties along with various other related rights, permits, contracts, equipment and other assets, all located in McKenzie County, North Dakota, from Kodiak Oil & Gas Corporation (“Kodiak”). We paid approximately $83.8 million in cash, subject to customary post-closing adjustments. The effective date for the acquisition was July 1, 2013. The acquisition contributed $8.2 million of revenue to the Company for fiscal year ended 2014. Transaction costs related to the acquisition incurred through January 31, 2014 were approximately $0.2 million and are recorded in the statement of operations within the general and administrative expenses line item. | |||||||
The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. Accordingly, the allocation may change as additional information becomes available and is assessed by the Company, and the impact of such changes may be material. | |||||||
The following table summarizes the purchase price and the preliminary estimated values of assets acquired and liabilities assumed (in thousands): | |||||||
Preliminary purchase price: | |||||||
Consideration given | |||||||
Cash | $ | 83,805 | |||||
Total consideration given | $ | 83,805 | |||||
Preliminary fair value allocation of purchase price: | |||||||
Oil and natural gas properties: | |||||||
Proved properties | $ | 50,200 | |||||
Unproved properties | 32,976 | ||||||
Total oil and natural gas properties | 83,176 | ||||||
Accounts payable | 761 | ||||||
Asset retirement obligation assumed | -132 | ||||||
Fair value of net assets acquired | $ | 83,805 | |||||
On August 2, 2013, the Company closed a trade agreement with Kodiak to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’s operated units for approximately 600 net acres of leasehold interests held by Kodiak in units then operated by the Company. The effective date of the trade agreement was also July 1, 2013. | |||||||
Pro Forma Financial Information | |||||||
The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak for the years ended January 31, 2014 and 2013 as if the acquisition and exchange transactions had occurred on February 1, 2012. The following pro forma results include the operating revenues and direct operating expenses for the acquired and exchanged properties for the years ended January 31, 2014 and 2013 (in thousands, except per share data): | |||||||
For the Year Ended | |||||||
January 31, | |||||||
(in thousands, except per share data) | 2014 | 2013 | |||||
Operating revenues | $ | 272,548 | $ | 63,167 | |||
Net income (loss) | $ | 80,086 | $ | -13,903 | |||
Earnings (loss) per common share | |||||||
Basic | $ | 1.07 | $ | -0.25 | |||
Diluted | $ | 0.93 | $ | -0.25 | |||
Weighted average common shares outstanding: | |||||||
Basic | 75,046,511 | 55,794,054 | |||||
Diluted | 91,025,500 | 55,794,054 | |||||
For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock pursuant to the Stock Purchase Agreement (see Note 16 – Capital Stock) were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012. The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $4.0 million for the year ended January 31, 2014 as compared to $2.0 million for the year ended January 31, 2013. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common shares had been issued, as of the beginning of the period, nor are they necessarily indicative of future results. | |||||||
Acquisition of Team Well Service, Inc. | |||||||
On October 16, 2013, RockPile completed its acquisition of Team Well Service, Inc. (“Team Well”), an operator of well service rigs in North Dakota, in exchange for (i) $6.8 million in cash; (ii) unsecured seller notes of $0.8 million; and, (iii) contingent consideration of $1.5 million. The purchase price is subject to customary post-closing adjustments. | |||||||
The unsecured seller notes have an aggregate face value of $1.0 million and bear an interest at a rate of 1% per annum. Principal and accrued interest is due on October 16, 2016. The contingent or “earn-out” consideration, is comprised of three annual payments equal to 10% of revenue from the acquired assets during each consecutive earn-out period (the one year period beginning on the first day of the first month immediately following the closing date) with payments limited to a maximum of $0.7 million for each earn-out period, based on revenue of up to $7.0 million. The estimated liability assumed that 100% of the earn-out would be achieved. The final purchase price allocation resulted in identifiable intangible assets and goodwill of approximately $3.9 million and $1.7 million, respectively. Transaction and other costs associated with the acquisition of net assets are expensed as incurred. Pro forma information has not been provided for the Team Well acquisition as the impact is immaterial to our consolidated financial statements. | |||||||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Asset Retirement Obligations [Abstract] | ' | |||||||||
Asset Retirement Obligations | ' | |||||||||
7. ASSET RETIREMENT OBLIGATIONS | ||||||||||
The following tables reflect the change in asset retirement obligations (“ARO”) for the fiscal years ended January 31, 2014 and 2013: | ||||||||||
For the Year Ended | ||||||||||
31-Jan-14 | ||||||||||
(in thousands) | USA | Canada | Total | |||||||
Balance, January 31, 2013 | $ | 1,973 | $ | 1,449 | $ | 3,422 | ||||
Liabilities incurred | 944 | - | 944 | |||||||
Revision of estimates | -188 | 962 | 774 | |||||||
Sale of assets | -83 | - | -83 | |||||||
Liabilities settled | -132 | -352 | -484 | |||||||
Accretion | 56 | - | 56 | |||||||
Balance, January 31, 2014 | 2,570 | 2,059 | 4,629 | |||||||
Less current portion of obligations | -1,361 | -1,972 | -3,333 | |||||||
Long-term asset retirement obligations | $ | 1,209 | $ | 87 | $ | 1,296 | ||||
For the Year Ended | ||||||||||
31-Jan-13 | ||||||||||
(in thousands) | USA | Canada | Total | |||||||
Balance, January 31, 2012 | $ | 83 | $ | 1,540 | $ | 1,623 | ||||
Liabilities incurred | 1,769 | - | 1,769 | |||||||
Revision of estimates | 147 | - | 147 | |||||||
Sale of assets | -48 | - | -48 | |||||||
Liabilities settled | - | -253 | -253 | |||||||
Accretion | 22 | 162 | 184 | |||||||
Balance, January 31, 2013 | 1,973 | 1,449 | 3,422 | |||||||
Less current portion of obligations | -1,500 | -1,449 | -2,949 | |||||||
Long-term asset retirement obligations | $ | 473 | $ | - | $ | 473 | ||||
Internal engineering re-assessment of Canadian ARO resulted in a $1.0 million increase in the ARO during FY2014. Since our Canadian oil and natural gas properties were fully impaired, the ARO revision was expensed and included in accretion and asset retirement obligation expenses in the accompanying consolidated statements of operations and comprehensive income (loss) for the year ended January 31, 2014. | ||||||||||
The $3.3 million current liability at January 31, 2014 consists of (a) an estimated $2.0 million for reclamation of man-made “ponds” holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada, and (b) $1.3 million for the estimated remaining costs to plug and abandon several producing (but marginally economic) vertical wells drilled many years ago on North Dakota leases we acquired in the second half of FY2013. These North Dakota leases are held by production. We intend to drill, complete and produce horizontal wells on the leases in FY2014 or early FY2015, allowing us to plug and abandon the marginally economic vertical wells and still hold the leases by production. | ||||||||||
Property_And_Equipment
Property And Equipment | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Property And Equipment [Abstract] | ' | ||||||
Property And Equipment | ' | ||||||
8. PROPERTY AND EQUIPMENT | |||||||
Property and equipment as of January 31, 2014 and 2013 consisted of the following: | |||||||
January 31, | January 31, | ||||||
(in thousands) | 2014 | 2013 | |||||
Land | $ | 2,512 | $ | 2,520 | |||
Building and leasehold improvements | 18,388 | 4,805 | |||||
Oilfield service equipment | 56,355 | 22,255 | |||||
Vehicles | 2,288 | 1,240 | |||||
Software, computers and office equipment | 3,016 | 1,190 | |||||
Total Depreciable Assets | $ | 82,559 | $ | 32,010 | |||
Accumulated depreciation | -12,799 | -3,339 | |||||
Depreciable assets, net | $ | 69,760 | $ | 28,671 | |||
Assets not placed in service | 1,333 | 5,986 | |||||
Total oilfield service equipment and other property & equipment, net | $ | 71,093 | $ | 34,657 | |||
Oilfield services equipment of $56.4 million ($46.6 million net of accumulated depreciation) consists primarily of costs for two hydraulic fracturing spreads and other complementary well completion and workover equipment, all of which were in service as of January 31, 2014. | |||||||
Intangible_Assets_And_Goodwill
Intangible Assets And Goodwill | 12 Months Ended |
Jan. 31, 2014 | |
Intangible Assets And Goodwill [Abstract] | ' |
Intangible Assets And Goodwill | ' |
9. INTANGIBLE ASSETS AND GOODWILL | |
Triangle’s net intangible asset and goodwill balances of $3.9 million and of $1.7 million, respectively, as of January 31, 2014, are a result of the October 16, 2013 acquisition of Team Well by RockPile. As of January 31, 2013, intangible assets and goodwill had a balance of $0. | |
The intangible assets as of January 31, 2014 consisted of $1.0 million for use of the trade name, $0.6 million for developed (patented and unpatented) technology, $0.1 million for a non-competition agreement and $2.2 million for customer relationships and information. The developed technology and customer relationship assets have useful lives of 10 years and the non-competition agreement and the trade name assets have useful lives of 5 years. During the fiscal years ended January 31, 2014 and 2013, Triangle recognized amortization expense of $0.1 million and $0, respectively. As of January 31, 2014, we have recorded no impairment of intangible assets. | |
Our goodwill represents consideration paid in excess of the fair value of identifiable net assets acquired in the Team Well acquisition. 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. As of January 31, 2014, no goodwill impairments were recorded. | |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Fair Value Measurements [Abstract] | ' | ||||||||||||
Fair Value Measurements | ' | ||||||||||||
10. FAIR VALUE MEASUREMENTS | |||||||||||||
ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: | |||||||||||||
• Level 1: Quoted prices are available in active markets for identical assets or liabilities; | |||||||||||||
• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; | |||||||||||||
• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. | |||||||||||||
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition. | |||||||||||||
The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2014 by level within the fair value hierarchy: | |||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Derivative assets | $ | - | $ | 2,147 | $ | 39,734 | $ | 41,881 | |||||
Liabilities: | |||||||||||||
Earn-out liability | $ | - | $ | -1,139 | $ | - | $ | -1,139 | |||||
Note payable | $ | - | $ | -9,002 | $ | - | $ | -9,002 | |||||
Commodity Derivative Instruments | |||||||||||||
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company's own credit rating. In considering counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At January 31, 2014, derivative instruments utilized by the Company consist of costless collars and swaps. The Company's derivative instruments are valued using public indices are traded with third-party counterparties, and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2. | |||||||||||||
Caliber Trigger Units and Warrants | |||||||||||||
The Company determines its estimate of the fair value of Caliber Trigger Units and Warrants using modified market approach and Black-Scholes options pricing model, respectively. The associated assumptions for the model are based on several factors, including 10-year historical volatilities for publicly-traded comparable companies, risk-free interest rates over the expected warrant term and dividend yields based on expected distributions. At January 31, 2014, the Company's Caliber Trigger Units and Warrants are valued using valuation models that are generally less observable from objective sources. As such, the Company has classified these instruments as Level 3. See Note 14 – Derivative Instruments for further discussion. | |||||||||||||
Earn-out Liability | |||||||||||||
The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2. | |||||||||||||
Note Payable | |||||||||||||
The Company determined the estimated fair value of the note payable relating to the same transaction using a market approach based on several factors, including quoted market rates in active markets, and RockPile’s current cost of funds. As such, the note payable has been classified as Level 2. | |||||||||||||
Credit Facilities | |||||||||||||
The carrying value of the Company’s credit facilities of $183.0 million approximated fair value as they bear interest at variable rates over the term of the loan, which rates are based on quoted prices in active markets (Level 2). | |||||||||||||
Convertible Note | |||||||||||||
The Convertible Note (carried at $129.3 million at January 31, 2014) has an estimated fair value at January 31, 2014 of $169.2 million, based on discounted cash flow analysis and option pricing (Level 3). The excess of fair value over carrying value is largely due to an increase in the option value attributed to the conversion feature, as the closing price for Triangle common stock was $7.61/share at January 31, 2014 compared with $5.59/share when the Convertible Note was issued on July 31, 2012. | |||||||||||||
The following table presents the rollforward of Level 3 financial assets and liabilities: | |||||||||||||
(in thousands) | Convertible Notes | Class A Triggering Units | Warrants (1) | ||||||||||
Beginning balance, February 1, 2012 | $ | - | $ | - | $ | - | |||||||
Sale of Convertible Notes | -120,000 | - | - | ||||||||||
Interest paid in-kind | -3,023 | - | - | ||||||||||
Total net unrecognized loss | -9,877 | - | - | ||||||||||
Ending balance, January 31, 2013 | $ | -132,900 | $ | - | $ | - | |||||||
Initial recognition of equity investment derivative assets | - | 38,091 | 1,643 | ||||||||||
Interest paid in-kind | -6,267 | - | - | ||||||||||
Total net unrecognized gain (loss) | -30,003 | - | - | ||||||||||
Ending balance, January 31, 2014 | $ | -169,170 | $ | 38,091 | $ | 1,643 | |||||||
-1 | Includes Class A Triggering Units, and Series 1 and Series 2 Warrants. | ||||||||||||
Equity_Investment
Equity Investment | 12 Months Ended | ||||||||
Jan. 31, 2014 | |||||||||
Equity Investment [Abstract] | ' | ||||||||
Equity Investment | ' | ||||||||
11. EQUITY INVESTMENT | |||||||||
On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly-owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly-owned subsidiary of FREIF. The joint venture entity, Caliber Midstream Partners, L.P. (“Caliber”), was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. | |||||||||
Pursuant to the terms of the October 1, 2012 Contribution Agreement (the “Contribution Agreement”), Triangle Caliber Holdings agreed to contribute $30.0 million to Caliber in exchange for 3,000,000 Class A Units; 4,000,000 Class A Trigger Units (“Trigger Units”) with certain performance conditions; 4,000,000 Series 1 Warrants and 1,600,000 Class A Trigger Unit Warrants with an exercise price of $14.69; 2,400,000 Series 2 Warrants with an exercise price of $24.00; and FRIEF Caliber Holdings agreed to contribute $70.0 million to Caliber in exchange for 7,000,000 Class A Units, the general partner of Caliber owned and controlled equally by Triangle Caliber Holdings and FREIF Caliber Holdings. | |||||||||
On September 12, 2013, Triangle Caliber Holdings and FREIF Caliber Holdings entered into an Amended and Restated Contribution Agreement (“A&R Contribution Agreement”), which amended and restated the Contribution Agreement. Pursuant to the terms of the A&R Contribution Agreement, FREIF Caliber Holdings agreed to contribute an additional $80.0 million to Caliber in exchange for an additional 8,000,000 Class A Units, to be issued no later than June 30, 2014, and 5,000,000 Series 5 Warrants with an exercise price of $32.00. Also pursuant to the terms of the A&R Contribution Agreement, Triangle Caliber Holdings’ received 3,000,000 Series 3 Warrants with an exercise price of $24.00; 2,000,000 Series 4 Warrants with an exercise price of $30.00; and the performance conditions associated with the 4,000,000 Class A Trigger Units granted in connection with the Contribution Agreement were removed and replaced with a provision to convert the 4,000,000 Class A Units at the earlier of the commissioning of the Alexander gas processing facility or June 30, 2014. The conversion of the Class A Trigger Units will not require any additional contribution of capital from Triangle Caliber Holdings. Additionally, the 1,600,000 Class A Trigger Unit Warrants granted in connection with the Contribution Agreement will be converted to 1,600,000 Series 1 Warrants with an exercise price of $14.69 no later than June 30, 2014. | |||||||||
Following the issuance of the additional 8,000,000 Class A Units to FREIF Caliber Holdings and the conversion of Triangle Caliber Holdings’ 4,000,000 Class A Trigger Units to 4,000,000 Class A Units, FREIF Caliber Holdings will own 15,000,000 Class A Units, representing an approximate sixty-eight percent (68%) limited partner interest in Caliber, and Triangle Caliber Holdings will own 7,000,000 Class A Units, representing an approximate thirty-two percent (32%) limited partner interest in Caliber. Triangle Caliber Holdings currently holds a thirty percent (30%) limited partner interest in Caliber. | |||||||||
Triangle Caliber Holdings’ investment interest in Caliber is considered to be variable and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk. However, Triangle Caliber Holdings is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to the economic performance of Caliber. Under the equity method, Triangle Caliber Holdings investment will be adjusted each period for contributions made, distributions received, and Triangle Caliber Holdings’ share of Caliber’s comprehensive income and accretion of any basis difference. Triangle Caliber Holdings’ maximum exposure to loss related to Caliber is limited to its equity investment as presented in the accompanying Consolidated Balance Sheet at January 31, 2014. Triangle Caliber Holdings does not guarantee or otherwise support Caliber’s $200.0 million credit facility, as such Triangle Caliber Holdings would not have additional exposure associated any borrowings on Caliber’s credit facility. | |||||||||
Triangle evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. | |||||||||
As of January 31, 2014, the balance of the Company’s investment in Caliber was $68.5 million, which consisted of the following: | |||||||||
(in thousands, except units) | Units | Price | Investment | ||||||
Balance - January 31, 2013 | $ | $ | 11,768 | ||||||
Class A Units | 3,000,000 | $ | 10.00 | 18,000 | |||||
Class A Trigger Units | 4,000,000 | $ | - | 38,091 | |||||
Class A Trigger Unit Warrants | 1,600,000 | $ | 14.69 | 234 | |||||
Series 1 Warrants | 4,000,000 | $ | 14.69 | 926 | |||||
Series 2 Warrants | 2,400,000 | $ | 24.00 | 254 | |||||
Series 3 Warrants | 3,000,000 | $ | 24.00 | 207 | |||||
Series 4 Warrants | 2,000,000 | $ | 30.00 | 22 | |||||
Distributions | -3,150 | ||||||||
Equity investment share of net income for the year | 2,184 | ||||||||
Balance - January 31, 2014 | $ | 68,536 | |||||||
The investment balance was increased in FY2014 by $18.0 million in additional contributions by Triangle Caliber Holdings, $2.2 million representing the equity investment share of Caliber’s net income, and by $39.7 million associated with the fair value of the Class A Trigger Units, Class A Trigger Unit Warrants and Warrants held by Triangle Caliber Holdings. The Class A Trigger Units increased in value substantially in the third quarter of FY2014 due to the removal of the associated performance conditions, as further discussed in Note 14 – Derivative Instruments. Additionally, the investment balance was reduced by Triangle Caliber Holdings’ $3.2 million share of FY2014 Caliber cash distributions to its owners. | |||||||||
The $2.2 million share of income was eliminated as intracompany profit and recorded as a reduction in Triangle’s capitalized well costs attributable to services provided by Caliber in FY2014. | |||||||||
Investment_In_Marketable_Secur
Investment In Marketable Securities | 12 Months Ended |
Jan. 31, 2014 | |
Investment In Marketable Securities [Abstract] | ' |
Investment In Marketable Securities | ' |
12. INVESTMENT IN MARKETABLE SECURITIES | |
In January 2013, TUSA received 851,315 shares of Emerald Oil, Inc. (“Emerald”) common stock (NYSE MKT symbol: EOX) as partial consideration in the sale to Emerald of oil and gas lease interests (1,590 net acres), as further discussed in Note 5 – Oil and Natural Gas Properties. | |
When acquired, the Emerald shares were valued and recorded at $4.9 million. During FY2014, we sold those shares for $6.1 million, net of brokerage fees. We had elected the fair value option for this investment in equity securities and therefore recorded the change in fair value during the period in the consolidated statements of operations and comprehensive income (loss). We recorded a $0.20 million gain in FY2013 and $1.1 million in net gains for FY2014. The gains are included in other income (expense) on the consolidated statements of operations and comprehensive income (loss). | |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Long-Term Debt [Abstract] | ' | ||||||
Long-term Debt | ' | ||||||
13. LONG-TERM DEBT | |||||||
As of January 31, 2014 and 2013, respectively, the Company’s long-term debt consisted of the following: | |||||||
(in thousands) | 31-Jan-14 | 31-Jan-13 | |||||
TUSA credit facility | $ | 183,000 | $ | 25,000 | |||
RockPile credit facility | 21,515 | - | |||||
Less current portion of RockPile credit facility | -8,450 | - | |||||
Long-term portion of credit facilities | 196,065 | 25,000 | |||||
5% Convertible Note | 129,290 | 123,023 | |||||
RockPile notes payable | 9,403 | - | |||||
Less current portion of RockPile notes payable | -401 | - | |||||
Total long-term debt | 334,357 | 148,023 | |||||
Total current portion of debt | 8,851 | - | |||||
Total debt | $ | 343,208 | $ | 148,023 | |||
TUSA Credit Facility | |||||||
On January 13, 2014, TUSA entered into Amendment No. 3 to the Amended and Restated Credit Agreement and Master Assignment (the “Amendment No. 3”) with Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the other lenders named therein, as lenders. The Amendment No. 3 amends that certain Amended and Restated Credit Agreement (the “A&R Credit Agreement”), dated April 11, 2013, as amended by that certain Amendment No. 1 to Amended and Restated Credit Agreement and Master Assignment, dated July 30, 2013, and that certain Amendment No. 2 to Amendment and Restated Master Assignment, dated October 16, 2013 (the “Amended A&R Credit Agreement”), to (i) broaden the definition of “Independent Engineering Report” to include a report prepared by or under the supervision of TUSA’s engineers, provided that such report be accompanied by an audit letter issued by an independent engineer that it has audited at least 90% by value of the Proven Reserves attributable to the Oil and Gas Properties owned (or to be acquired) by the credit parties which are or are to be included in the borrowing base, and (ii) increase the borrowing base under the Amended A&R Credit Agreement from $275.0 million to $320.0 million. The amendments in Amendment No. 1 remaining in force were (i) the permitting of TUSA to hedge up to 85% of the anticipated production of (x) oil, (y) gas, and (z) natural gas liquid volumes, respectively, attributable to TUSA’s total proved reserves, and (ii) the revisions enabling TUSA to enter into a second lien credit facility at a future date. The amendments in Amendment No. 2 remaining in force were (i) the addition of JPMorgan Chase Bank, N.A., KeyBank National Association, and IBERIABANK as new lenders under the facility, (ii) the extension of the maturity date to October 16, 2018, and (iv) the decrease of the applicable margins for ABR and eurodollar advances by 0.25% at all utilization levels. Further, the existing lenders assigned a portion of their lending commitments to the three new lenders. As of January 31, 2014, TUSA, as borrower, had borrowings of $183.0 million outstanding under the A&R Credit Agreement, as amended (the “TUSA Credit Facility”). | |||||||
The borrowing base under the TUSA Credit Facility is subject to redetermination by the beginning of May 2014 and November 2014, and thereafter on a semi-annual basis by the beginning of each May and November. In addition, TUSA has the option to request one unscheduled interim redetermination prior to May 1, 2014 during any calendar year and two additional redeterminations after May 1, 2014 during any calendar year. With a five-year term, all borrowings under the TUSA Credit Facility mature on October 16, 2018. | |||||||
The TUSA Credit Facility contains representations, warranties and covenants that are customary for similar credit arrangements, including, among other things, covenants relating to (i) financial reporting and notification, (ii) payment of obligations, (iii) compliance with applicable laws and (iv) notification of certain events. The TUSA Credit Facility also contains various covenants and restrictive provisions which may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, make investments or loans and create liens. | |||||||
The TUSA Credit Facility contains financial covenants requiring TUSA to comply with the following: (i) TUSA must maintain a ratio of consolidated current assets (as defined in the TUSA Credit Facility) to consolidated current liabilities (as defined in the TUSA Credit Facility) of at least 1.0 to 1.0; and (ii) the ratio of TUSA’s consolidated debt to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) may not be greater than 4.0 to 1.0. As of January 31, 2014, TUSA was in compliance with all financial covenants under the TUSA Credit Facility. | |||||||
Convertible Note | |||||||
On July 31, 2012, the Company sold to NGP the Convertible Note, which became convertible after November 16, 2012 into Company common stock at a conversion rate of one share per $8.00 of note principal. | |||||||
The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest will be paid-in-kind by adding to the principal balance of the Convertible Note; provided that, after July 31, 2017, the Company has the option to make such interest payments in cash. As of January 31, 2014, $9.3 million of accrued interest has been added to the principal balance of the Convertible Note. | |||||||
RockPile Credit Facility | |||||||
RockPile’s $27.5 million credit facility in place at January 31, 2014 was replaced on March 25, 2014 with a $100.0 million credit facility. Both credit facilities are discussed below. | |||||||
On November 18, 2013 RockPile entered into Amendment No. 1 to the Credit and Security Agreement (the “RockPile Credit Agreement”) between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”). Amendment No. 1 amended the Equipment Term Loan, the terms of the Discretional Capex Term Loan and the Revolving Facility remained unchanged. The RockPile Credit Agreement provided for a maximum borrowing of $27.5 million. Principal amounts paid on the term loans were not eligible for re-borrowing. Borrowings under the RockPile Credit Agreement were available to: (i) provide for the working capital and general corporate requirements of RockPile, (ii) purchase equipment, (iii) pay any fees and expenses in connection with the RockPile Credit Agreement, and (iv) support letters of credit. The maturity date of the RockPile Credit Agreement was February 25, 2016, unless sooner terminated as provided in the RockPile Credit Agreement. The RockPile Credit Agreement had three components: | |||||||
i) | Equipment Term Loan: On November 18, 2013, the RockPile Credit Agreement was amended increasing the maximum borrowing limit to $18.0 million and the monthly principal payment to $0.6 million. All other terms of the original agreement remained in force. The loan bore interest at the daily three month LIBOR plus 4.50%. At January 31, 2014, $15.7 million was outstanding, the interest rate was 4.75% and accrued and unpaid interest were de minimis. | ||||||
ii) | Discretionary Capex Term Loan: The Discretionary Capex Term Loan had a maximum borrowing of $2.0 million. This loan bore interest at the daily three month LIBOR plus 4.50%. Payments on this loan were interest only for the first six months and then converted to monthly principal payments of $0.1 million plus accrued and unpaid interest. At January 31, 2014, the full $2.0 million was outstanding, the interest rate was 4.75% and accrued and unpaid interest were de minimis. | ||||||
iii) | Revolving Loan: The revolving loan had a maximum borrowing of $7.5 million. RockPile could draw down on this facility from time to time in amounts not to exceed the maximum borrowing or an amount supported by a borrowing base certificate, whichever was less. This loan bore interest at the daily three month LIBOR plus 4.00%. Amounts outstanding under this loan could be repaid and reborrowed at any time. At January 31, 2014, $3.8 million was outstanding, the interest rate was 4.25% and accrued interest were de minimis. | ||||||
At January 31, 2014, there were no letters of credit outstanding. | |||||||
The borrowings under the RockPile Credit Agreement were guaranteed by Triangle and each subsidiary of RockPile. Borrowings under the RockPile Credit Agreement are secured by certain of RockPile’s assets, including all of its equipment and other personal property of RockPile but excluding any owned real property. In addition, RockPile’s subsidiary guarantors pledged certain of their assets to secure their obligations under the guaranty. | |||||||
The RockPile Credit Agreement contained standard representations, warranties and covenants for a transaction of its nature, including, among other things, covenants relating to (i) financial reporting and notification, (ii) payment of obligations, (iii) compliance with applicable laws, and (iv) notification of certain events. The RockPile Credit Agreement also contained various covenants and restrictive provisions which, among other things, limited RockPile’s ability to sell assets, incur additional indebtedness, make investments or loans, and create liens. As of January 31, 2014, RockPile was in compliance with all financial covenants under the RockPile Credit Agreement. | |||||||
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 is 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 bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted eurodollar rate (as defined in the FY2015 RockPile Credit Agreement) plus 1%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recent fiscal quarter, or (ii) the eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recent fiscal quarter. RockPile may prepay borrowings under the FY2015 RockPile Credit Agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. All borrowings under the FY2015 RockPile Credit Agreement mature on March 25, 2019. | |||||||
RockPile will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the FY2015 RockPile Credit Agreement. RockPile will also pay a per annum fee on all letters of credit issued under the FY2015 RockPile Credit Agreement, which will equal the applicable margin for loans accruing interest based on the eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. In connection with entering into the FY2015 RockPile Credit Agreement, RockPile paid certain upfront fees to the lenders thereunder, and RockPile paid certain arrangement and other fees to Citi and Wells Fargo. Triangle is not a guarantor under the FY2015 RockPile Credit Agreement. | |||||||
Upon entering into the FY2015 RockPile Credit Agreement, RockPile drew funds to pay down and close its existing credit facility, which was in place at January 31, 2014 and is described above. | |||||||
RockPile Notes Payable to Dacotah Bank | |||||||
On February 15, 2013, Bakken Real Estate Development, LLC (“BRED”), a wholly-owned subsidiary of RockPile, entered into two loan agreements with Dacotah Bank in the amounts of $2.6 million for construction financing of its residential units in Dickinson, North Dakota and $3.3 million for construction financing of its administrative and maintenance facility in Dickinson, North Dakota. The loans had a fixed interest rate of 4.75% and a maturity date of December 31, 2013. Payments on the loans were interest only until maturity and the full principal balance was due on December 31, 2013. The construction mortgages were guaranteed by Triangle. As of January 31, 2014, both loans were paid off in full. | |||||||
RockPile Mortgages Payable to Dacotah Bank | |||||||
On December 11, 2013, BRED entered into two mortgage loan agreements with Dacotah Bank in the amounts of $2.6 million for its residential units in Dickinson, North Dakota and $4.5 million for its administrative and maintenance facility in Dickinson, North Dakota. The mortgage loans have a term of 15 years, bear interest at a variable rate equal to the Federal Home Loan Bank of Des Moines Five-Year Fixed-Rate Advance Rate plus 2.80%, and have a maturity date of December 15, 2028. At January 31, 2014 the interest rate on the loans was 4.75% and the outstanding balances were $2.6 million and $4.5 million, respectively. | |||||||
RockPile Notes Payable to Sellers of Team Well Service, Inc. | |||||||
On October 16, 2013, RockPile issued two identical unsecured subordinated promissory notes to the sellers of Team Well. The notes each have a face value of $0.5 million and bear interest at a fixed rate of 1%. The loans have a maturity date of October 16, 2016, at which time the principal and accrued interest is due and payable. The aggregate carrying value of the loans at January 31, 2014 was $0.9 million. Over the term of the loans, the discount will be accreted on a monthly basis by increasing the carrying value of both notes and recording interest expense. | |||||||
RockPile Hauck Apartments Mortgage | |||||||
On November 20, 2013, RockPile closed on the purchase of a 12 unit apartment building in Dickinson, ND for a total purchase price of $1.8 million. The purchase was funded by cash on hand and a mortgage from Dacotah Bank in the amount of $1.5 million. The mortgage has a term of 15 years and bears interest at a variable rate equal to the Federal Home Loan Bank of Des Moines Five-Year Fixed-Rate Advance Rate plus 2.70%. At January 31, 2014 the interest on the mortgage was 4.75% balance outstanding balance on the mortgage was $1.5 million. | |||||||
Commodity_Derivative_Instrumen
Commodity Derivative Instruments | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Commodity Derivative Instruments [Abstract] | ' | ||||||||||||
Commodity Derivative Instruments | ' | ||||||||||||
14. DERIVATIVE INSTRUMENTS | |||||||||||||
Commodity Derivative Instruments | |||||||||||||
Through TUSA, the Company has entered into commodity derivative instruments as described below. The Company has utilized swaps, single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil 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, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional 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 does not enter into derivative contracts for speculative purposes. | |||||||||||||
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with four counterparties. The Company has netting arrangements with each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. | |||||||||||||
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as either derivative assets or liabilities. The Company has not designated any of its derivative contracts as hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on derivative activities are recorded in the gain (loss) from derivative activities line on the consolidated statements of operations and comprehensive income (loss). The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. | |||||||||||||
The Company's commodity derivative contracts as of January 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. | |||||||||||||
The following table details the fair value of the derivatives recorded in the applicable consolidated balance sheets, by category: | |||||||||||||
(in thousands) | As of January 31, 2014 | ||||||||||||
Underlying Commodity | Balance Sheet Classification | Gross Amount of Recognized Assets (Liabilities) | Gross Amount of Offset | Net Amount of Assets (Liabilities) | |||||||||
Crude oil derivative contract | Current asset | $ | 1,066 | $ | -111 | $ | 955 | ||||||
Crude oil derivative contract | Long-term assets | $ | 1,192 | $ | - | $ | 1,192 | ||||||
Equity investment derivatives | Long-term assets | $ | 39,734 | $ | - | $ | 39,734 | ||||||
(in thousands) | As of January 31, 2013 | ||||||||||||
Underlying Commodity | Balance Sheet Classification | Gross Amount of Recognized Assets (Liabilities) | Gross Amount of Offset | Net Amount of Assets (Liabilities) | |||||||||
Crude oil derivative contract | Current assets | $ | 1,305 | $ | -702 | $ | 603 | ||||||
Crude oil derivative contract | Long-term liabilities | $ | -292 | $ | - | $ | -292 | ||||||
The Company recorded a gain of $1.1 million for FY2014 and a loss of $3.6 million for FY2013 with respect to our commodity derivatives. The Company had not entered into derivative contracts prior to FY2013. In regards to our equity investment derivatives, we recorded a gain of $39.7 million for FY2014 and $0 for FY2013. | |||||||||||||
Equity Investment Derivatives | |||||||||||||
Class A Trigger Units | |||||||||||||
On October 1, 2012, we acquired from Caliber 4,000,000 Class A Trigger Units. The Class A Trigger Units convert to 4,000,000 Class A Units upon either of the following: (i) 162 producer wells, or (ii) revenues attributable to third party volumes equal 50% of projected distributable cash flow for 6 consecutive quarters or 8 non‐consecutive quarters in the aggregate, or (iii) Caliber GP Board discretion. On September 12, 2013, Caliber GP’s Board voted to remove the performance conditions of vesting and provided that the Class A Trigger Units should vest in to Class A Units at the earlier of the commissioning of the Alexander gas processing facility or June 30, 2014. At the initial issuance of the Class A Trigger Units in October 2012, the fair value of the Class A Trigger Units was immaterial to the Company. Upon removal of the performance conditions in September 2013, the Company measured the fair value of the Class A Trigger Units to recognize the associated gain in equity investment derivatives, as further discussed in Note 14 – Derivative Instruments. | |||||||||||||
The Company determined the Class A Trigger Units are equity investment derivatives and are measured at fair value and are included in the accompanying balance sheets in equity investments with any gain or loss reflected in the accompanying statement of operations in gain on equity investment derivatives. The fair value of the Class A Trigger Units was estimated using a modified market approach. This method measured the value of the underlying security, less the present value of any distributions paid to the underlying security but not to the Class A Trigger Units, multiplied by the probability that the performance obligations would be satisfied such that the Class A Trigger Units would convert to Class A Units. The fair value of the underlying Class A Units were estimated at $10.00 each based on the cash investment price paid by FREIF on October 1, 2012 and September 12, 2013. Management forecast the distributions to the Class A Units over the expected life of the Class A Trigger Units. These amounts were present-valued using a weighted average cost of capital that ranged from 10.3 percent to 11.6 percent. The probability of converting to Class A Units was estimated at 5.0 percent from October 1, 2012 through July 31, 2013, and 100.0 percent from September 12, 2013 and thereafter. | |||||||||||||
Class A Trigger Unit Warrants | |||||||||||||
On October 1, 2012, we acquired from Caliber 1,600,000 Class A Trigger Unit Warrants. The Class A Trigger Unit Warrants expire on October 1, 2024 and have an initial exercise price of $14.69. The exercise price is reduced by all distributions paid to the underlying Class A Units, subject to a floor exercise price of $5.00 per share. | |||||||||||||
The Company determined the Class A Trigger Unit Warrants are equity investment derivatives and are measured at fair value and are included in the accompanying balance sheets in equity investments with any gain or loss reflected in the accompanying statement of operations in gain on equity investment derivatives. The fair value of the Class A Trigger Unit Warrants was estimated using a Black-Scholes options pricing model. The value of the underlying Class A Trigger Units was valued based on the method discussed above in “Class A Trigger Units”. The expected term of the warrants was estimated as the earlier of a) the contractual life of 12 years, and b) the point at which the exercise price is reduced to $5.00 per share and it would be advantageous to exercise early to capture future distributions on the Class A Units. Expected volatility of 25.0 percent was selected based on a review of 10-year historical volatilities for publicly-traded comparable companies. The risk-free interest rates over the expected warrant terms ranged from 0.5 percent to 1.2 percent based the U.S. Treasury yield curve in effect at each valuation date. The dividend yields were based on the expected distributions to be paid to the underlying Class A Units over the expected term of the warrants. | |||||||||||||
Class A Warrants (Series 1 through Series 4) | |||||||||||||
On October 1, 2012, we acquired from Caliber 4,000,000 Class A Unit Warrants (Series 1) with an initial exercise price of $14.69 and 2,400,000 Class A Unit Warrants (Series 2) with an initial exercise price $24.00. Both the Series 1 and Series 2 warrants expire on October 1, 2024. On September 12, 2013, we acquired from Caliber 3,000,000 Class A Unit Warrants (Series 3) with an initial exercise price of $24.00 and 2,000,000 Class A Unit Warrants (Series 4) with an initial exercise price $30.00. Both the Series 3 and Series 4 warrants expire on September 12, 2025. The exercise prices for Series 1 through Series 4 are reduced by all distributions paid to the underlying Class A Units, subject to a floor exercise price of $5.00 per share. | |||||||||||||
The Company determined the Class A Trigger Unit Warrants are equity investment derivatives and are measured at fair value and are included in the accompanying balance sheets in equity investments with any gain or loss reflected in the accompanying statement of operations in gain on equity investment derivatives. The fair values of the Class A Warrants was estimated using a Black-Scholes options pricing model. The value of the underlying Class A Units was estimated at $10.00 each based on the cash investment price paid by FREIF on October 1, 2012 and September 12, 2013. The expected term of the warrants was estimated as the earlier of a) the contractual life of 12 years, and b) the point at which the exercise price is reduced to $5.00 per share and it would be advantageous to exercise early to capture future distributions on the Class A Units. Expected volatility of 25.0 percent was selected based on a review of 10-year historical volatilities for publicly-traded comparable companies. The risk-free interest rates over the expected warrant terms ranged from 0.4 percent to 3.0 percent based the U.S. Treasury yield curve in effect at each valuation date. The dividend yields were based on the expected distributions to be paid to the underlying Class A Units over the expected term of the warrants. | |||||||||||||
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. | |||||||||||||
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended | |||
Jan. 31, 2014 | ||||
Commitments And Contingencies [Abstract] | ' | |||
Commitments And Contingencies | ' | |||
15. COMMITMENTS AND CONTINGENCIES | ||||
Office Leases | ||||
The Company leases office facilities in Denver, Colorado under operating lease agreements that expire in October 2017. Rent expense was $0.8 million, $0.5 million and $0.2 million for the years ended January 31, 2014, 2013 and 2012, respectively. The following table shows the annual rentals per year for the life of the leases: | ||||
Fiscal year ending January 31, | Annual rental amount | |||
2015 | $ | 1,180 | ||
2016 | $ | 1,207 | ||
2017 | $ | 1,234 | ||
2018 | $ | 1,108 | ||
2019 | $ | 617 | ||
Drilling Rig Contracts | ||||
As of January 31, 2014 the Company was subject to commitments on three drilling rig contracts. The contracts expire between April 2014 and February 2015. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $11.5 million as of January 31, 2014 as required under the terms of the contracts. | ||||
Related Party Transactions | ||||
See Note 22 – Related Party Transactions for a description of agreements between TUSA and various subsidiaries of Caliber pursuant to which TUSA has committed to use certain products and services provided by the Caliber subsidiaries. | ||||
CEO Transaction Bonus Program | ||||
Pursuant to the Third Amended and Restated Employment Agreement, dated July 4, 2013 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its initial investment in the relevant entity. The amount of this bonus would be equivalent to 5% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. Because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors, the Company has determined that the contingent liability associated with such a bonus is not probable at January 31, 2014, and, therefore, no amounts have been recorded in the accompanying consolidated balance sheets. | ||||
RockPile Commitments | ||||
As of January 31, 2014, RockPile had various commitments for future expenditures relating to (i) leases of land, rail spur, rail cars and tractor trailer units, (ii) transloading services and track rental and (iii) an agreement relating to the use of technology and equipment for transportation, transloading and storage of bulk commodities. The commitments by fiscal year are as follows: | ||||
Fiscal year ending January 31, | Annual rental amount | |||
2015 | $ | 1,752 | ||
2016 | $ | 582 | ||
2017 | $ | 441 | ||
2018 | $ | 360 | ||
2019 | $ | 200 | ||
Thereafter | $ | 655 | ||
Environmental Laws and Regulations | ||||
At January 31, 2014, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability other than asset retirement obligations reflected on the consolidated balance sheets. Non-compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company’s financial position, results of operations or cash flows. | ||||
Capital_Stock
Capital Stock | 12 Months Ended | |||
Jan. 31, 2013 | ||||
Capital Stock [Abstract] | ' | |||
Capital Stock | ' | |||
16. CAPITAL STOCK | ||||
Summary of Changes in Common Stock | ||||
The Consolidated Statement of Stockholders’ Equity provides a listing of changes in the common stock outstanding from February 1, 2013 to January 31, 2014. | ||||
A summary of our common stock activity for January 31, 2014 is as follows: | ||||
· | On March 8, 2013, the Company sold to two affiliates of NGP an aggregate of 9,300,000 shares of common stock in a private placement at $6.00 per share for aggregate consideration of $55.8 million. The Company paid approximately $0.1 million in expenses related to this offering. | |||
· | We issued 664,483 shares of common stock (net of shares surrendered for related employee payroll tax withholding) for restricted stock units that vested during the period. | |||
· | We issued 5,000 shares of common stock at $7.24 per share to a consultant for services provided to TUSA. | |||
· | On August 2, 2013, the Company issued 325,000 shares of common stock to an unaffiliated oil and gas company at $7.50 per share for total consideration of $2.4 million. | |||
· | In August and September, 2013, the Company sold an aggregate of 17,250,000 shares of common stock at $6.25 per share in a public offering for gross proceeds of $107.8 million. The Company paid approximately $6.0 million in expenses related to this offering. | |||
· | On August 28, 2013, the Company sold 11,350,000 shares of common stock to an unaffiliated entity at $7.20 per share for total consideration of $81.7 million. The Company paid approximately $0.9 million in expenses related to this offering. | |||
· | We issued 108,333 shares of common stock for the exercise of stock options. | |||
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 under the Stock Purchase Agreement to ActOil Bakken, LLC (“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 gross proceeds to the Company of $81.7 million ($80.8 million net after transaction costs), which were used to consummate the August 28, 2013 Kodiak property acquisition. Concurrently with the issuance, the Company entered into a Rights Agreement (the “Rights Agreement”) with ActOil. Under the Rights Agreement, ActOil is entitled to certain demand registration rights and unlimited piggyback registration rights under the Securities Act. | ||||
The Rights Agreement also grants ActOil the preemptive right to purchase its pro rata share on a fully diluted basis of any future equity offerings by the Company until such time as ActOil and its affiliates cease to hold at least the lesser of (i) 50% of the shares of common stock acquired by ActOil pursuant to the Stock Purchase Agreement and (ii) 10% of the Company’s then-outstanding shares of the common stock (a “Termination Event”). Such rights are subject to customary exclusions such as securities offered in connection with employee benefits plans, business combinations, pro-rata distributions, and stockholder rights plans. | ||||
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 Company’s then issued and outstanding common stock, without the prior written consent of ActOil, the Company and its subsidiaries shall not incur any indebtedness unless the Consolidated Leverage Ratio (as defined in the Rights Agreement) does not exceed 5.0 to 1.0 (provided that debt outstanding under TUSA’s credit facility and the Convertible Note issued in July 2012 are excluded from such calculation). | ||||
Public Equity Offering | ||||
On August 8, 2013, the Company entered into an underwriting agreement (the “Underwriting Agreement”) with Wells Fargo Securities, LLC, as representative of the several underwriters named therein (collectively, the “Underwriters”), pursuant to which the Company agreed to issue and sell to the Underwriters in a firm commitment offering (the “Offering”) 15,000,000 shares of common stock at a price to the public of $6.25 per share. Pursuant to the Underwriting Agreement, the Company also granted to the Underwriters a 30-day over-allotment option to purchase up to an additional 2,250,000 shares of common stock at the same public offering price. The Offering was made pursuant to the Company’s effective registration statement on Form S-3 (Registration Statement No. 333-171958) previously filed with the Securities and Exchange Commission on January 31, 2011. The Offering closed on August 14, 2013. On September 6, 2013, the Underwriters exercised their 30-day over-allotment option to purchase an additional 2,250,000 shares of the Company’s common stock at a price to the public of $6.25 per share. The over-allotment option closed on September 11, 2013. | ||||
The total gross proceeds to the Company from the Offering and the exercise of the over-allotment option were approximately $107.8 million ($101.8 million net, after deducting underwriting discounts and commissions and other estimated offering expenses). | ||||
Significant_Customers
Significant Customers | 12 Months Ended |
Jan. 31, 2014 | |
Significant Customers [Abstract] | ' |
Significant Customers | ' |
17. SIGNIFICANT CUSTOMERS | |
Oil, NGL and Natural Gas Customers | |
In the U.S., sales prices of produced crude oil, natural gas and natural gas liquids are not regulated. Sales are made at negotiated prices. Of our $160.5 million in revenues from oil, NGL and gas sales in FY2014, $155.0 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 in FY2014. | |
For wells that we operate, oil production is sold at the wellhead, or a location nearby, under short term agreements with several purchasers. While the pricing terms of these agreements vary by purchaser, they all reflect a price determined by the current NYMEX West Texas Intermediate contract, less a discount that is either calculated, fixed, or a combination of calculated and fixed. | |
In FY2014, we made oil sales directly to five oil purchasers, one NGL purchaser and one natural gas purchaser. We also had sales through unrelated operators of wells in which we have revenue interests. 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. | |
Although a substantial portion of our production is purchased by, or through, these parties, we do not believe the loss of any one customer would have a material adverse effect on our business as other customers should be accessible to us. We regularly monitor the credit worthiness of customers and may require parental guarantees, letters of credit or prepayments when deemed necessary. | |
For our economic interests in wells operated by third-parties, substantially all of our sales of crude oil and natural gas in fiscal years 2014, 2013 and 2012 were sold (i) through arrangements made by the wells’ operators and (ii) at sales points at or close to the producing wells. These third-party operators include a variety of exploration and production companies ranging from large publicly-traded companies to small privately-owned companies. We do not believe the loss of any single operator’s customer would have a material adverse effect on our Company as a whole. | |
For our economic interests in wells operated by third-parties, we have the right to take and sell our proportionate share of production, rather than have the operator arrange such sale; however, we did not do so in fiscal years 2014, 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 producing companies needing completion of horizontal wells 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 six 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. | |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Earnings Per Share [Abstract] | ' | |||||||||
Earnings Per Share | ' | |||||||||
18. EARNINGS PER SHARE | ||||||||||
Basic net income (loss) per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. | ||||||||||
The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2014, 2013, and 2012: | ||||||||||
2014 | 2013 | 2012 | ||||||||
Net income (loss) attributable to common stockholders | $ | 73,480 | $ | -13,760 | $ | -24,278 | ||||
Effect of debt conversion | 3,392 | - | - | |||||||
Net income (loss) attributable to common stockholders after effect of debt conversion | 76,872 | -13,760 | -24,278 | |||||||
Basic weighted average common shares outstanding | 68,578,553 | 44,475,201 | 40,707,957 | |||||||
Effect of dilutive securities | 15,978,989 | - | - | |||||||
Diluted weighted average common shares outstanding | 84,557,542 | 44,475,201 | 40,707,957 | |||||||
Basic net income (loss) per share | $ | 1.07 | $ | -0.31 | $ | -0.6 | ||||
Diluted net income (loss) per share | $ | 0.91 | $ | -0.31 | $ | -0.6 | ||||
2014 | 2013 | 2012 | ||||||||
Anti-dilutive shares | 5,250,000 | 4,500,000 | - | |||||||
For the fiscal years ended January 31, 2013 and 2012, with a basic net loss per share, all of the stock options and restricted stock units would have been anti-dilutive if converted into additional common stock and were excluded in calculating diluted net loss per share. | ||||||||||
Of the stock options, restricted stock units and convertible debt outstanding at January 31, 2014, only the options relating to the CEO Option Grant, having an exercise price of $8.50 to $15.00 per share, were anti-dilutive for FY2014. Accordingly, the related potential 5,250,000 common shares were excluded from the calculation of the diluted net income per share. These CEO stock options could be potentially dilutive in future periods. | ||||||||||
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Income Taxes [Abstract] | ' | |||||||||
Income Taxes | ' | |||||||||
19. INCOME TAXES | ||||||||||
Federal income tax expense (benefit) for the years presented differ from the amounts that would be provided by applying the U.S. Federal and state income tax rate. The components of the provision for income taxes are as follows for the fiscal years 2014, 2013 and 2012: | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Current tax expense (benefit) | $ | - | $ | - | $ | - | ||||
Deferred tax expense (benefit) | ||||||||||
Federal | 7,324 | -2,137 | -6,189 | |||||||
State | 617 | -223 | -175 | |||||||
Foreign | - | -83 | -1,510 | |||||||
Valuation allowance - United States and Canada | - | 2,443 | 7,874 | |||||||
Income tax expense (benefit) | $ | 7,941 | $ | - | $ | - | ||||
Income (loss) before income taxes | $ | 81,421 | $ | -14,484 | $ | -24,423 | ||||
Effective income tax rate | 10% | 0% | 0% | |||||||
Reconciliations of the income tax benefit calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows for fiscal years 2014, 2013 and 2012: | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Federal statutory tax expense (benefit) | $ | 28,498 | $ | -5,069 | $ | -8,361 | ||||
State income tax expense / (benefit), net of federal income tax benefit | 2,324 | -361 | -565 | |||||||
Permanent differences | 3,221 | 2,280 | 132 | |||||||
Difference in foreign tax rates | 164 | 28 | 600 | |||||||
Effect of tax rate change | -258 | -71 | 83 | |||||||
Credits | -100 | - | - | |||||||
Changes in valuation allowance | -26,364 | 2,443 | 7,874 | |||||||
Other | 456 | 750 | 237 | |||||||
Provision for income taxes | $ | 7,941 | $ | - | $ | - | ||||
The difference in foreign tax rate of $0.16 million is a result of adjusting the U.S. blended statutory tax rate of 37.9% down to the Canadian effective tax rate of 25.0%. | ||||||||||
The components of Triangle’s net deferred income tax assets are as follows for fiscal years 2014 and 2013: | ||||||||||
2014 | 2013 | |||||||||
(in thousands) | ||||||||||
Current: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | $ | 1,071 | $ | - | ||||||
Accruals | 102 | - | ||||||||
Hedging assets | - | 1,342 | ||||||||
Total current assets | 1,173 | 1,342 | ||||||||
Valuation allowance | -492 | -1,342 | ||||||||
Total current assets after valuation allowance | 681 | - | ||||||||
Liabilities: | ||||||||||
Hedging liabilities | -361 | - | ||||||||
Total current liabilities | -361 | - | ||||||||
Net current deferred income tax asset | $ | 321 | $ | |||||||
Non-Current: | ||||||||||
Assets: | ||||||||||
Canadian oil and natural gas properties | 6,080 | 6,095 | ||||||||
United States net losses carried forward | 33,129 | 37,816 | ||||||||
Canadian net losses carried forward | 1,905 | 1,726 | ||||||||
Asset retirement obligations | 416 | 1,102 | ||||||||
Stock-based compensation | 3,105 | 1,356 | ||||||||
Investment in RockPile | - | - | ||||||||
Investment in Caliber | - | 106 | ||||||||
Property and equipment | 157 | 157 | ||||||||
Hedging assets | - | - | ||||||||
Other | 1,864 | 673 | ||||||||
Total non-current assets | 46,656 | 49,031 | ||||||||
Valuation allowance | -8,165 | -33,679 | ||||||||
Total non-current assets after valuation allowance | 38,491 | 15,352 | ||||||||
Liabilities: | ||||||||||
United States oil and natural gas properties | -29,536 | -15,275 | ||||||||
Investment in Caliber | -16,766 | |||||||||
Hedging liabilities | -451 | |||||||||
Other | - | -77 | ||||||||
Total deferred non-current income tax liability | -46,753 | -15,352 | ||||||||
Net non-current deferred income tax liability | $ | -8,262 | $ | - | ||||||
As of FY2013 the Company placed a full valuation allowance against deferred income taxes. During the year ended January 31, 2014, in accordance with ASC 740, Accounting for Income Taxes, Triangle has determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net US deferred tax assets will be realized. Hence, all deferred tax benefits will be recognized and the full valuation allowance removed as part of the effective tax rate. The key positive evidence relating to the US deferred tax assets considered in this determination includes the following: (1) a history of book income; (2) cumulative income in the prior 3 years; (3) an expectation of projected taxable income during the next four to five years. Therefore, the combination of historical/cumulative income as well as an expectation of taxable income in the foreseeable future is the basis for the full recognition of the US deferred tax assets. In accordance with ASC 740, Accounting for Income Taxes, Triangle has determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized. Hence, all Canadian deferred tax benefits will have a full valuation allowance placed against them. The key negative evidence relating to the Canadian deferred tax assets considered in this determination includes the following: (1) a history of both book and tax loss; (2) cumulative loss in recent years; (3) an expectation of tax loss during the next four to five years. Therefore, the combination of historical/cumulative loss as well as an expectation of book and taxable loss in the foreseeable future is the basis for the placement of a full valuation allowance against all of the Canadian deferred tax assets. | ||||||||||
The Company has a U.S. net operating loss carry forward for federal tax purposes of approximately $91.5 million, of which $3.9 million is not benefited for financial statement purposes. The difference of $3.9 million between the federal income tax net operating losses (“NOL”) and financial reporting NOL relate to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The Company has a Canadian NOL of approximately $7.6 million at January 31, 2014 that could be utilized to offset taxable income of future years. The U.S. NOL carry forwards begin expiring in 2024 and the Canadian NOL carry forwards begin expiring in 2027. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.The key negative evidence relating to the Canadian deferred tax assets considered in this determination includes the following: (1) a history of both book and tax loss; (2) cumulative loss in recent years; (3) an expectation of tax loss during the next four to five years. Therefore, the combination of historical/cumulative loss as well as an expectation of book and taxable loss in the foreseeable future is the basis for the placement of a full valuation allowance against all of the Canadian deferred tax assets. | ||||||||||
The Company has a U.S. net operating loss (“NOL”) carry forward for federal tax purposes of approximately $91.5 million, of which $3.9 million is not benefited for financial statement purposes. The difference of $3.9 million between the federal income tax NOL and financial reporting NOL relate to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The Company has Canadian NOL of approximately $7.6 million at January 31, 2014 that could be utilized to offset taxable income of future years. The U.S. NOL carry forward begin expiring in 2024 and the Canadian NOL carry forward begin expiring in 2027. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years. | ||||||||||
At January 31, 2014 and 2013, we have no unrecognized tax benefits that would impact our effective tax rate, and we have made no provisions for interest or penalties related to uncertain tax positions. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. | ||||||||||
The tax years for fiscal years ending 2011 to 2013 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for examination for fiscal years 2011 to 2013, except for Colorado which is open for the fiscal years 2010 to 2013. We also file with various Canadian taxing authorities which remain open for fiscal years 2010 to 2013. | ||||||||||
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. | ||||||||||
ShareBased_Compensation
Share-Based Compensation | 12 Months Ended | ||||||||||
Jan. 31, 2014 | |||||||||||
Share-Based Compensation [Abstract] | ' | ||||||||||
Share-Based Compensation | ' | ||||||||||
20. SHARE-BASED COMPENSATION | |||||||||||
Effective January 28, 2009, the Company’s board of directors approved a Stock Option Plan (the “Rolling Plan”) whereby the number of authorized but unissued shares of common stock that may be issued upon the exercise of stock options granted under the Rolling Plan at any time could not exceed 10% of the issued and outstanding shares of common stock on a non-diluted basis at any time, and such aggregate number of shares of common stock available for issuance automatically increased or decreased as the number of issued and outstanding shares of common stock changed. Pursuant to the Rolling Plan, stock options became exercisable ratably in one-third increments on each of the first, second and third anniversaries of the date of the grant, and could be granted at an exercise price of not less than fair value of the common stock at the time of grant and for a term not to exceed ten years. | |||||||||||
Upon approval of the 2011 Omnibus Incentive Plan (the “2011 Plan”) by the Company’s stockholders on July 22, 2011, the Rolling Plan was terminated and no additional awards may be granted under the Rolling Plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions. | |||||||||||
The 2011 Plan, as amended in November 2012, authorizes the Company to issue stock options, stock appreciation rights (“SARs”), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company and its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 5,900,000 shares, subject to adjustment for certain transactions. | |||||||||||
We have recognized non-cash stock-based compensation cost as follows: | |||||||||||
Years Ended January 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Restricted stock units | $ | 7,496 | $ | 6,639 | $ | 7,512 | |||||
Stock options | 1,135 | 60 | 81 | ||||||||
Stock issued pursuant to termination agreements | - | 99 | 185 | ||||||||
RockPile stock based compensation related to Series B Units | 590 | 617 | - | ||||||||
9,221 | 7,415 | 7,778 | |||||||||
Less amounts capitalized to oil and natural gas properties | -1,391 | -949 | -211 | ||||||||
Compensation expense | $ | 7,830 | $ | 6,466 | $ | 7,567 | |||||
Historical amounts may not be representative of future amounts as additional awards may be granted. | |||||||||||
Restricted Stock Units | |||||||||||
A restricted stock unit represents a right to an unrestricted share of common stock upon satisfaction of defined service, vesting and holding conditions. Restricted stock units have a one to five year vesting schedule prior to conversion into common stock. Compensation costs for the service-based vesting restricted share units are based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. | |||||||||||
The following table provides information about restricted stock unit awards granted during the last three fiscal years: | |||||||||||
Number of Shares | Weighted- Average Award Date Fair Value | ||||||||||
Restricted stock units outstanding - January 31, 2011 | 509,636 | $ | 5.61 | ||||||||
Units granted in fiscal year 2012 | 2,645,110 | $ | 7.06 | ||||||||
Units forfeited in fiscal year 2012 | -134,000 | $ | 6.81 | ||||||||
Units that vested during in fiscal year 2012 | -532,404 | $ | 6.20 | ||||||||
Restricted stock units outstanding - January 31, 2012 | 2,488,342 | $ | 7.02 | ||||||||
Units granted in fiscal year 2013 | 1,041,400 | $ | 6.37 | ||||||||
Units forfeited in fiscal year 2013 | -5,600 | $ | 7.59 | ||||||||
Units that vested during in fiscal year 2013 | -1,000,057 | $ | 6.90 | ||||||||
Restricted stock units outstanding - January 31, 2013 | 2,524,085 | $ | 6.68 | ||||||||
Units granted in fiscal year 2014 | 1,440,133 | $ | 6.95 | ||||||||
Units forfeited in fiscal year 2014 | -141,909 | $ | 6.58 | ||||||||
Units that vested during in fiscal year 2014 | -946,681 | $ | 6.71 | ||||||||
Restricted stock units outstanding - January 31, 2014 | 2,875,628 | $ | 6.62 | ||||||||
The Company recorded stock-based compensation related to previous grants of restricted stock of $7.5 million and $6.6 million, for fiscal years 2014 and 2013, respectively. | |||||||||||
The total grant date fair value of the restricted stock units that vested during fiscal years 2014 and 2013 was $6.4 million and $6.9 million, respectively. | |||||||||||
Unamortized compensation cost related to unvested restricted stock units at January 31, 2014 was $14.4 million. We expect to recognize that cost over a weighted average period of 2.41 years. | |||||||||||
Stock Options | |||||||||||
On July 4, 2013, the Company entered into a CEO Stand-Alone Stock Option Agreement with the Company’s President and Chief Executive Officer (the “CEO Option Grant”). The CEO Option Grant is a stand-alone stock option agreement unrelated to the 2011 Plan. As such, the CEO Option Grant required stockholder approval before any shares of the Company’s common stock could be issued thereunder. The options under the CEO Option Grant were granted as of the execution date thereof; however, the options granted thereunder were not exercisable, and would have expired and become null and void in their entirety, if they were not approved by the stockholders of the Company on or before July 4, 2015. Thus, no compensation expense was recognized for these option grants prior to their approval by the stockholders. At the Company’s Annual Meeting of Stockholders held on August 30, 2013, the CEO Option Grant was approved. | |||||||||||
The CEO Option Grant covers a total of 6.0 million shares of Company common stock and is divided into five tranches, each with a different exercise price, as follows: | |||||||||||
Name of Tranche | Number of Shares | Exercise Price | |||||||||
“$7.50 Tranche” | 750,000 | $7.50 per share | |||||||||
“$8.50 Tranche” | 750,000 | $8.50 per share | |||||||||
“$10.00 Tranche” | 1,500,000 | $10.00 per share | |||||||||
“$12.00 Tranche” | 1,500,000 | $12.00 per share | |||||||||
“$15.00 Tranche” | 1,500,000 | $15.00 per share | |||||||||
Each tranche of the CEO Option Grant vests and becomes exercisable on the same vesting schedule, with 10% of each tranche becoming vested and exercisable on each of the first two anniversaries of the grant date, 50% of each tranche becoming vested and exercisable on the third anniversary of the grant date, 20% of each tranche becoming vested and exercisable on the fourth anniversary of the grant date, and the remaining 10% of each tranche becoming vested and exercisable on the fifth anniversary of the grant date. Once any portion of the CEO Option Grant becomes vested, it is exercisable until the options expire on July 4, 2023. | |||||||||||
Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatility is generally based on the historical volatility of (a) Triangle’s common stock and (b) for expected terms exceeding three years, the historical volatility of similar companies with significant exploration and production activity in the Bakken over a historical period consistent with that of the expected term of the options. Triangle’s historical volatility before January 2011 related to high-risk, unsuccessful exploration in Nova Scotia and is not representative of expected future volatility for Triangle. The expected term of the options is estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rate for the expected term (from service inception to option exercise) of the options is based on the yields of U.S. Treasury instruments with lives comparable to the estimated expected option term or life. | |||||||||||
The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the CEO Option Grant for the period presented: | |||||||||||
Risk free rate | 2.18% | ||||||||||
Dividend yield | - | ||||||||||
Expected volatility | 62% | ||||||||||
Weighted average expected stock option life (years) | 6.3 | ||||||||||
The following table summarizes the status of stock options outstanding under the Rolling Plan and the CEO Option Grant, during the last three fiscal years: | |||||||||||
Number of Shares | Weighted Average Exercise Price | ||||||||||
Options outstanding - January 31, 2011 (125,833 exercisable) | 343,334 | $ | 1.60 | ||||||||
Options forfeited | -25,000 | $ | 3.00 | ||||||||
Options exercised | -82,501 | $ | 1.34 | ||||||||
Options outstanding - January 31, 2012 (142,500 exercisable) | 235,833 | $ | 1.50 | ||||||||
Options exercised | -4,167 | $ | 3.00 | ||||||||
Options outstanding - January 31, 2013 (231,666 exercisable) | 231,666 | $ | 1.48 | ||||||||
Options forfeited | -15,000 | $ | 3.00 | ||||||||
Options exercised | -108,333 | $ | 1.25 | ||||||||
Options granted | 6,000,000 | $ | 11.25 | ||||||||
Options outstanding - January 31, 2014 (108,333 exercisable) | 6,108,333 | $ | 11.07 | ||||||||
The intrinsic value of options exercised during fiscal years 2014 and 2013 was $162,000 and $12,000, respectively. The Company received approximately $162,000 for the exercise of 108,333 options in FY2014 and approximately $12,500 for the exercise of 4,167 options in FY2013. | |||||||||||
Options granted under the Rolling Plan expire five years from the grant date and have service-based vesting schedules of three years. The following table summarizes the status of all stock options outstanding as of January 31, 2014: | |||||||||||
Remaining | |||||||||||
Exercise Price | Contractual Life | Number of shares | |||||||||
per Share | (years) | Outstanding | Exercisable | ||||||||
$ | 1.25 | 0.83 | 108,333 | 108,333 | |||||||
$ | 7.50 | 9.43 | 750,000 | - | |||||||
$ | 8.50 | 9.43 | 750,000 | - | |||||||
$ | 10.00 | 9.43 | 1,500,000 | - | |||||||
$ | 12.00 | 9.43 | 1,500,000 | - | |||||||
$ | 15.00 | 9.43 | 1,500,000 | - | |||||||
6,108,333 | 108,333 | ||||||||||
Weighted average exercise price per share | $ | 11.07 | $ | 1.25 | |||||||
Weighted average remaining contractual life | 9.27 | 0.83 | |||||||||
As of January 31, 2014, all compensation expense related to stock options under the Rolling Plan had been recognized as they became fully vested in FY2013. Total compensation expense related to the CEO Option Grant of $1.1 million was recognized for January 31, 2014. The aggregate intrinsic value of all options as of January 31, 2014 was $0.8 million. As of January 31, 2014, there was approximately $18.3 million of total unrecognized compensation expense related to unvested stock options. | |||||||||||
Non-cash compensation cost related to our stock options were $1.1 million and $0.1 million for fiscal years 2014 and 2013, respectively. | |||||||||||
As of January 31, 2014, there was $14.43 million of remaining unrecognized compensation cost related to non-vested stock options. | |||||||||||
A summary of the status of the Company’s non-vested stock options as of January 31, 2014, and changes during the years ended January 31, 2014, 2013 and 2012, is presented below: | |||||||||||
Number of Shares | Weighted-Average Grant Date Fair Value | ||||||||||
Non-vested options - January 31, 2011 | 217,500 | $ | 1.10 | ||||||||
Options vested | -107,501 | $ | 1.08 | ||||||||
Less options forfeited | -16,667 | $ | 2.13 | ||||||||
Non-vested options - January 31, 2012 | 93,332 | $ | 1.02 | ||||||||
Options vested | -93,332 | $ | 1.02 | ||||||||
Non-vested options - January 31, 2013 | - | $ | - | ||||||||
Options granted | 6,000,000 | $ | 11.25 | ||||||||
Non-vested options - January 31, 2014 | 6,000,000 | $ | 11.25 | ||||||||
RockPile Share Based Compensation (Series B Units) | |||||||||||
At January 31, 2014, RockPile had 30.0 million Series A Units authorized by the LLC Agreement (as defined below) with approximately 25.5 million Series A units outstanding, all of which are owned by Triangle. Series A Units were issued to the three parties who had contributed the initial $24.0 million in RockPile’s paid-in capital prior to October 31, 2011. Triangle had contributed $20.0 million and received 20.0 million Series A Units by October 31, 2011. On December 28, 2012, Triangle acquired an aggregate of 4.0 million Series A Units from the other two original owners of Series A Units. On February 15, 2013, Triangle made an additional capital contribution of $5.0 million to acquire an additional approximately 1.5 million Series A Units. | |||||||||||
Effective October 22, 2012, RockPile’s Board of Managers approved the Second Amended and Restated Limited Liability Company Agreement, as further amended on February 20, 2013 (“RockPile LLC Agreement”) which includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Restricted Unit Agreements. The RockPile LLC Agreement, which was executed by RockPile and its members on October 31, 2012, authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number (i.e., Series B-1, Series B-2, etc.) with the right to re-issue forfeited or redeemed Series B Units. As of January 31, 2014, RockPile had granted approximately 4.1 million Series B Units, of which approximately 1.5 million were unvested at that date, to certain employees in key positions at RockPile. | |||||||||||
The Series B Units are intended to constitute interests in future profits, i.e., “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93-27 and 2001-43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be nil. RockPile’s Board of Managers may designate a “Liquidation Value” applicable to each tranche of a Series B Unit so as to constitute a net profits interest in RockPile. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile’s Board of Managers, be distributed with respect to the initial Series B tranche if, immediately prior to the issuance of a new Series B tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities of RockPile) were distributed. | |||||||||||
RockPile’s Series A Units are entitled to a return of contributed capital and an 8% preferred return on such capital before Series B Units participate in profits. The initial Series B tranche (Series B-1 Units) participates pro-rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B-1 Unit until total cumulative distributions to the Series A Units total $40.0 million. As of January 31, 2014 the $40.0 million cumulative distribution threshold had not been met. After distributions totaling $40.0 million have been made to the Series A Units, future distributions will be allocated to the Series B-1 Units until the per unit profits distributed to the Series B-1 Units is equivalent to the per unit profits distributed to the Series A Units. Thereafter, all further distributions will be distributed on a pro-rata basis. Subsequently issued Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B-1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance. | |||||||||||
Series B Units currently have from 11 to 41 months remaining until fully vested. Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and are recognized ratably over the applicable vesting period. | |||||||||||
Series B Units are valued using a waterfall valuation approach beginning with the initial asset valuation contained in the LLC Agreement with each tranche of Series B Units constituting a waterfall valuation event. Additionally, due to the limited operating history of RockPile, its private ownership and the nature of the equity grants, RockPile has made use of estimates as it relates to employee termination and forfeiture rates, used different valuation techniques including income and/or market approaches, and utilized certain peer group derived information. The assumptions used in the Black-Scholes option pricing model consist of the underlying equity value, the estimated time to liquidity which is based upon the projected exit path, volatility based upon the midpoint volatility of a publicly traded peer group, and the risk-free interest rate which is based upon the rate for zero coupon U.S. Government issues with a term equal to the expected life. | |||||||||||
A summary of RockPile’s Series B Unit activity for FY2014 is as follows: | |||||||||||
Number of Series B Units | Weighted Average Award Date Unit Fair Value | ||||||||||
Series B Units outstanding February 1, 2013 | 3,160,000 | $ | - | ||||||||
Series B-3 Unit Grants | 910,000 | $ | 0.7 | ||||||||
Series B Units outstanding January 31, 2014 | 4,070,000 | ||||||||||
A summary of RockPile’s Series B Unit vesting status for FY2014 is as follows: | |||||||||||
Remaining Vesting Period (Years) | Number of Series B Units | Vested | Unvested | ||||||||
Series B Units outstanding, February 1, 2012 | - | - | - | - | |||||||
Series B-1 Unit Grants | 0.47 | 3,100,000 | 2,566,667 | 533,333 | |||||||
Series B-2 Unit Grants | 1.58 | 60,000 | 15,000 | 45,000 | |||||||
Series B-3 Unit Grants | 3.28 | 910,000 | - | 910,000 | |||||||
Series B Units outstanding, January 31, 2014 | 4,070,000 | 2,581,667 | 1,488,333 | ||||||||
Non-cash compensation cost related to the Series B Units was $0.6 million, $0.6 million and $0 for the fiscal years ended January 31, 2014, 2013 and 2012, respectively. | |||||||||||
As of January 31, 2014, there was $0.8 million of unrecognized compensation cost related to non-vested Series B Units. We expect to recognize such cost on a pro-rata basis on the Series B Units vesting schedule during the next three fiscal years. | |||||||||||
Benefit_Plans
Benefit Plans | 12 Months Ended |
Jan. 31, 2014 | |
Benefit Plans [Abstract] | ' |
Benefit Plans | ' |
21. BENEFIT PLANS | |
In FY2013 RockPile established a 401(k) plan for the benefit of its employees. In FY2014 Triangle established a 401(k) plan for the benefit of its employees. Eligible employees may make voluntary contributions not exceeding statutory limitations to the plan. The Company began matching employee contributions in January of FY2014. The Company did not match employee contributions in the fiscal year ending January 31, 2013. | |
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Jan. 31, 2014 | |
Related Party Transactions [Abstract] | ' |
Related Party Transactions | ' |
22. RELATED PARTY TRANSACTIONS | |
On September 12, 2013, TUSA and Caliber North Dakota amended and restated two midstream services agreements which the parties originally entered into on October 1, 2012. Caliber North Dakota is a wholly-owned subsidiary of Caliber Midstream Partners, L.P., an entity in which Triangle has a 30% ownership. The two original midstream services agreements consisted of: (a) an agreement for crude oil gathering, stabilization, treating and redelivery, and (b) an agreement for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. The two agreements were revised to include an additional acreage dedication from TUSA to Caliber North Dakota and an increased firm volume commitment by Caliber North Dakota for each service line. The revenue commitment language included in the original midstream services agreements was removed and replaced by a stand-alone agreement. | |
Under the new revenue commitment agreement, TUSA maintained the commitment included in the original midstream services agreement to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber North Dakota facilities (the date that the Caliber North Dakota central facility has been substantially completed and has commenced commercial operation, estimated to occur in the first quarter of FY2015), and added a commitment to deliver additional minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota related to the increased acreage dedication and increased firm volume commitment. The additional minimum monthly revenue commitment will commence on the in-service date of the incremental Caliber North Dakota facilities, estimated to occur in the second quarter of FY2015. The minimum commitment over the term of the agreements is $405.0 million. Triangle made a $9.0 million contribution to Caliber on March 27, 2013. In accordance with the A&R Contribution Agreement, Triangle contributed an additional $9.0 million to Caliber on December 6, 2013, fulfilling its original commitment of $30.0 million. See Note 11 – Equity Investment. | |
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. Caliber Measurement also purchased Lease Automatic Custody Transfer (“LACT”) units from TUSA for $2.5 million, which is included in the balance of related party receivables in the accompanying condensed consolidated balance sheets. | |
On October 1, 2012, Triangle entered into a Services Agreement with Caliber GP and Caliber to provide administrative services to Caliber necessary to operate, manage, maintain and report the operating results of Caliber’s gathering pipelines, transportation pipelines, related equipment and other assets. Total fees paid to Triangle under this agreement during FY2014 were $1.2 million. | |
For the year ended January 31, 2014, Caliber North Dakota had $15.6 million of revenue, $15.0 million of which was from TUSA, mainly comprised of fresh water and water disposal revenues and as well connect fees. See Note 11 - Equity Investment. | |
For the year ended January 31, 2014, Triangle received $1.2 million from Caliber for administrative services supplemental to those provided by Caliber employees and pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber. | |
Significant_Changes_in_Proved_
Significant Changes in Proved Oil And Natural Gas Reserves | 12 Months Ended | ||||||||||||||
Jan. 31, 2014 | |||||||||||||||
Significant Changes In Proved Oil And Natural Gas Reserves (Abstract) | ' | ||||||||||||||
Significant Changes In Proved Oil And Natural Gas Reserves | ' | ||||||||||||||
23. SIGNIFICANT CHANGES IN PROVED OIL AND NATURAL GAS RESERVES (unaudited) | |||||||||||||||
Our proved oil and natural gas reserves at January 31, 2014 significantly increased from our proved oil and natural gas reserves at January 31, 2013. Our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams or Dunn. | |||||||||||||||
The reserve estimates presented below (expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”) and thousands of barrels of oil equivalent (“Mboe”)) were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009. | |||||||||||||||
Our reserve estimate at January 31, 2014 was audited by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Proved reserves are the estimated quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. For the purposes of preparing the proved reserves presented below, such average pricing was $93.09 per barrel of oil and $3.99 per Mcf of natural gas and $44.10 per barrel of NGL for the reserves presented as of January 31, 2014. For the reserves presented as of January 31, 2013, such average pricing was $84.76 per barrel of oil and $5.23 per Mcf of natural gas. | |||||||||||||||
% of | 31-Jan-14 | January 31, | |||||||||||||
Reserves | Oil | Gas | NGL | 2013 | % | ||||||||||
Reserve Category | (Mboe) | (Mbbls) | (MMcf) | (Mbbls) | Mboe | Mboe | Change | ||||||||
Proved Developed | 42% | 13,734 | 10,930 | 1,440 | 16,995 | 5,969 | 185% | ||||||||
Proved Undeveloped | 58% | 18,182 | 15,574 | 2,541 | 23,319 | 8,668 | 169% | ||||||||
Total Proved | 100% | 31,916 | 26,504 | 3,981 | 40,314 | 14,637 | 175% | ||||||||
The primary reason for the increases in proved reserves is the drilling and completion of wells in FY2014 in addition to acquisitions of proved reserves. Our net interest in producing wells increased 168% from 16.0 net wells at January 31, 2013 to 50.0 net wells at January 31, 2014, and our net interest in proved undeveloped locations increased 213% from 19.8 net future development wells at January 31, 2013 to 52.5 net future development wells at January 31, 2014. | |||||||||||||||
Unaudited_Supplemental_Oil_And
Unaudited Supplemental Oil And Natural Gas Disclosures | 12 Months Ended | |||||||||
Jan. 31, 2013 | ||||||||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ' | |||||||||
Unaudited Supplemental Oil And Natural Gas Disclosures | ' | |||||||||
24. UNAUDITED SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES | ||||||||||
Oil and Natural Gas Operations | ||||||||||
The following tables contain direct revenue and cost information relating to our oil and natural gas exploration and production activities in the United States and Canada for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and natural gas operations is computed using the combined statutory income tax rate for the period. We had no Canadian proved reserves, revenues or production taxes for FY2014, FY2013 and FY2012. | ||||||||||
U.S. Oil and Natural Gas Operations | Years Ended January 31, | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Oil and natural gas revenues from production (all sold to unaffiliated parties) | $ | 160,548 | $ | 39,614 | $ | 8,136 | ||||
Less operating expenses: | ||||||||||
Production taxes | 18,006 | 4,493 | 896 | |||||||
Other lease operating expenses | 14,454 | 3,469 | 901 | |||||||
Gathering, transportation and processing | 4,302 | 151 | 22 | |||||||
Impairment of oil and natural gas properties | - | - | 6,000 | |||||||
Amortization of oil and natural gas properties | 50,991 | 13,548 | 3,022 | |||||||
Accretion of asset retirement obligation | 56 | 22 | 7 | |||||||
Operating income (loss) before income tax expense | 72,739 | 17,931 | -2,712 | |||||||
Less income tax (expense) benefit at statutory rates | -27,532 | -6,697 | 1,013 | |||||||
Results of U.S. oil and natural gas operations (excluding general corporate overhead and interest expense) | $ | 45,207 | $ | 11,234 | $ | -1,699 | ||||
Amortization rate per Boe | $ | 26.43 | $ | 27.75 | $ | 31.85 | ||||
Lease Operating Expenses (per Boe) | $ | 7.49 | $ | 7.11 | $ | 9.50 | ||||
Gathering, Transportation and Processing (per Boe) | $ | 2.23 | $ | 0.31 | $ | 0.23 | ||||
Canadian Oil and Natural Gas Operations | Years Ended January 31, | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Oil and natural gas revenues | $ | - | $ | - | $ | - | ||||
Less operating expenses: | ||||||||||
Lease operating expenses | - | - | 641 | |||||||
Impairment of oil and natural gas properties | - | - | 4,416 | |||||||
Accretion and other asset retirement obligation expenses | 962 | 162 | 160 | |||||||
Operating income (loss) before income tax expense | -962 | -162 | -5,217 | |||||||
Income tax (expense) benefit | - | - | - | |||||||
Results of Canadian oil and natural gas operations (excluding general corporate overhead and interest expense) | $ | -962 | $ | -162 | $ | -5,217 | ||||
Oil and Natural Gas Reserve Information | ||||||||||
All of the Company’s estimated proved reserves are located in the Williston Basin in North Dakota and Montana. | ||||||||||
Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. | ||||||||||
The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended January 31, 2014. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2014 and January 31, 2013 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves. Ryder Scott Petroleum Consultants (“Ryder Scott”), an independent petroleum engineering firm, estimated our proved reserves as of January 31, 2012 and determined the projected future cash flows (before income taxes) from those proved reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. | ||||||||||
Crude Oil | Natural Gas | NGL | ||||||||
(in thousands) | (Mbbls) | (MMcf) | (Mbbls) | |||||||
Total proved reserves at January 31, 2011 | 1,236 | - | - | |||||||
Revisions of previous estimates | -932 | - | - | |||||||
Purchase of reserves | - | - | - | |||||||
Extensions, discoveries and other additions | 1,154 | 686 | - | |||||||
Sale of reserves | - | - | - | |||||||
Production | -93 | -12 | - | |||||||
Total proved reserves at January 31, 2012 | 1,365 | 674 | - | |||||||
Revisions of previous estimates | 665 | 1,832 | - | |||||||
Purchase of reserves | 230 | 181 | - | |||||||
Extensions, discoveries and other additions | 10,960 | 10,251 | - | |||||||
Sale of reserves | -229 | -165 | - | |||||||
Production | -452 | -188 | - | |||||||
Total proved reserves at January 31, 2013 | 12,539 | 12,585 | - | |||||||
Revisions of previous estimates | 2,727 | -859 | 1,762 | |||||||
Purchase of reserves | 6,836 | 4,714 | 690 | |||||||
Extensions, discoveries and other additions | 12,059 | 11,064 | 1,599 | |||||||
Sale of reserves | -491 | -374 | - | |||||||
Production | -1,754 | -626 | -70 | |||||||
Total proved reserves at January 31, 2014 | 31,916 | 26,504 | 3,981 | |||||||
Proved Developed Reserves included above: | ||||||||||
31-Jan-11 | 215 | - | - | |||||||
31-Jan-12 | 538 | 202 | - | |||||||
31-Jan-13 | 4,985 | 5,906 | - | |||||||
31-Jan-14 | 13,734 | 10,930 | 1,440 | |||||||
Proved Undeveloped Reserves included above: | ||||||||||
31-Jan-11 | 1,021 | - | - | |||||||
31-Jan-12 | 827 | 472 | - | |||||||
31-Jan-13 | 7,555 | 6,679 | - | |||||||
31-Jan-14 | 18,182 | 15,574 | 2,541 | |||||||
Extensions and Discoveries in FY2014 | ||||||||||
The 12.1 million barrels of oil, 11.1 billion cubic feet of natural gas, and 1.6 million barrels of natural gas liquids of proved reserves added by extensions and discoveries in North Dakota are primarily due to our increased completion of wells, particularly operated wells, and other parties completing wells offsetting our properties. In FY2014, we participated in 112 gross (28.1 net) productive wells completed, and we added 68 gross (29.6 net) new proved undeveloped well locations discussed later in this Note. | ||||||||||
Revisions in FY2014 | ||||||||||
The 2,727 Mbbls (22%) upward revision in crude oil proved reserves was primarily due to longer production histories that favorably supported the increase in proved oil reserves. The 859 MMcf reduction in natural gas reserves and the 1,762 Mbbls increase in NGL reserves reflect agreements and arrangements at the end of FY2014 to have the majority of our proved natural gas reserves processed to extract NGLs and dry residue gas that Triangle would sell to third parties. | ||||||||||
Purchases of Proved Properties in FY2014 | ||||||||||
See Note 6 for a discussion of purchases of proved properties in FY2014. | ||||||||||
Proved Undeveloped Reserves | ||||||||||
At January 31, 2014, we had proved undeveloped oil and natural gas reserves of 23,319 Mboe, up 14,651 Mboe from 8,668 Mboe at January 31, 2013. Changes in our proved undeveloped reserves are summarized in the following table: | ||||||||||
(Mboe) | Gross Wells | Net Wells | ||||||||
Proved Undeveloped Reserves at January 31, 2011 | 1,021 | 19 | 3.0 | |||||||
Net revisions | -819 | -13 | -2.6 | |||||||
Became developed reserves in fiscal year 2012 | -52 | -3 | - | |||||||
Acquisitions | - | - | - | |||||||
Extensions and discoveries of proved reserves | 755 | 14 | 2.2 | |||||||
Proved Undeveloped Reserves at January 31, 2012 | 905 | 17 | 2.6 | |||||||
Became developed reserves in fiscal year 2013 | -363 | -9 | -1.2 | |||||||
Traded for net acres in other drill spacing units | -256 | -5 | -0.7 | |||||||
Negative revisions | -36 | -1 | -0.1 | |||||||
Positive revisions | 102 | - | - | |||||||
Acquisition of additional interests in PUD location | 172 | - | 0.3 | |||||||
Additional proved undeveloped locations | 8,144 | 57 | 18.9 | |||||||
Proved Undeveloped Reserves 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 | |||||||
Proved Undeveloped Reserves at January 31, 2014 | 23,319 | 104 | 52.5 | |||||||
During FY2014, we invested approximately $74.9 million (averaging $9.4 million per net well) related to the drilling and completion of the 32 gross (7.9 net) wells that converted 3,701 Mboe of proved undeveloped reserves to proved developed reserves. | ||||||||||
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 | ||||||||||
PUD | Wells | |||||||||
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 | |||||||
104 | 104 | 52.5 | ||||||||
Standardized Measure of Discounted Future Net Cash Flows | ||||||||||
Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2014 and 2013 (i) a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves (“Standardized Measure”) and (ii) changes in the Standardized Measure for fiscal years 2014 and 2013. Under that accounting guidance: | ||||||||||
· | Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future proved reserve quantities. | |||||||||
· | Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the fiscal year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the fiscal year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. | |||||||||
· | Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end cost rates and assuming continuation of existing economic conditions. | |||||||||
· | Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and natural gas properties and (ii) net operating loss carryforwards relating to our oil and natural gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure. | |||||||||
These assumptions do not necessarily reflect the Company’s expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations. | ||||||||||
The following average prices are reflected in the calculation of the Standardized Measure: | ||||||||||
January 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Oil price per barrel | $ | 93.09 | $ | 84.76 | $ | 89.71 | ||||
Natural gas price per Mcf | $ | 3.99 | $ | 5.23 | $ | 8.19 | ||||
Natural gas liquids price per barrel | $ | 44.10 | $ | - | $ | - | ||||
Most of our natural gas sales in FY2014, FY2013 and FY2012 were for ‘wet’ natural gas sold before processing so that natural gas liquids could be extracted. Under our contracts with Caliber as of January 31, 2014, most of our proved gas reserves will be sold after gas processing, whereby our January 31, 2014 proved reserves include natural gas liquids and processed (‘dry’) natural gas for which the price is lower than wet gas. | ||||||||||
In FY2014, FY2013 and FY2012 substantially all of our oil was sold at the lease site at a “wellhead” price. The prices used in our Standardized Measures at January 31, 2013 and 2012, substantially reflect oil prices at the wellhead. In the last three months of fiscal FY2014, we began connecting operated wells to the Caliber oil gathering system and selling oil downstream using that system. Most of our oil reserves are to be sold downstream. To reflect such downstream sales in the standardized measure at January 31, 2014, the oil price for downstream sales are the sum of (a) the unweighted arithmetic average of the first-day-of-the-month wellhead price for FY2014, and (b) the additional related transportation costs per barrel at January 31, 2014 that are reflected in future operating costs. | ||||||||||
The following summary sets forth the Company’s Standardized Measure for January 31, 2014, 2013 and 2012: | ||||||||||
January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Future cash inflows | $ | 3,252,079 | $ | 1,128,676 | $ | 127,955 | ||||
Future costs: | ||||||||||
Production | -1,118,508 | -333,185 | -48,919 | |||||||
Development | -505,432 | -199,173 | -23,362 | |||||||
Future income tax expense | -364,340 | -87,313 | - | |||||||
Future net cash flows | 1,263,799 | 509,005 | 55,674 | |||||||
10% discount factor | -690,564 | -297,653 | -26,246 | |||||||
Standardized measure of discounted future net cash flows relating to proved reserves | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
The $505.4 million in estimated future development costs at January 31, 2014 includes $19.2 million of estimated future net costs (at current cost rates), net of estimated equipment salvage value, for site restoration and well plugging upon the abandonment of the wells. The $19.2 million in costs decreased the Standardized Measure by $0.3 million. | ||||||||||
The principle sources of change in the Standardized Measure are shown in the following table: | ||||||||||
January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Standardized measure, beginning of period | $ | 211,352 | $ | 29,428 | $ | 12,867 | ||||
Extensions and discoveries, net of future production and development costs | 333,140 | 193,107 | 28,414 | |||||||
Sales, net of production costs | -123,786 | -31,502 | -5,677 | |||||||
Previously estimated development costs incurred during the period | 66,724 | 10,368 | 2,084 | |||||||
Revision of quantity estimates | 73,598 | 15,910 | -9,536 | |||||||
Net change in prices, net of production costs | 19,173 | 2,779 | 1,001 | |||||||
Acquisition of reserves | 99,683 | 2,119 | - | |||||||
Divestiture of reserves | -7,341 | -3,273 | - | |||||||
Accretion of discount | 22,486 | 2,943 | 1,316 | |||||||
Changes in future development costs | 7,699 | 801 | -494 | |||||||
Change in income taxes | -91,161 | -13,509 | 290 | |||||||
Change in production timing and other | -38,332 | 2,181 | -837 | |||||||
Standardized measure, end of period | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and natural gas disclosures and use the "short-cut" method for the ceiling test calculation. Companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test limits total capitalized costs for oil and natural gas properties (net of accumulated DD&A and deferred income taxes) to no more than the sum of (i) the present value discounted at 10% of estimated future net cash flows from proved reserves, (ii) the cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized and (iv) all related tax effects. | ||||||||||
Supplemental_Disclosures_of_Ca
Supplemental Disclosures of Cash Flow Information | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Supplemental Disclosures of Cash Flow Information [Abstract] | ' | |||||||||
Supplemental Disclosures of Cash Flow Information | ' | |||||||||
25. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Cash paid during the period for: | ||||||||||
Interest expense | $ | 1,419 | $ | 75 | $ | - | ||||
Non-cash investing activities: | ||||||||||
Additions (reductions) to oil and natural gas properties through: | ||||||||||
Increased (decreased) accrued liabilities and decreased prepaid well costs | $ | 30,785 | $ | 36,654 | $ | 13,181 | ||||
Capitalized stock based compensation | $ | 1,391 | $ | 949 | $ | 211 | ||||
Issuance of common stock | $ | 3,827 | $ | 1,204 | $ | 11,780 | ||||
Change in asset retirement obligations | $ | 673 | $ | 1,869 | $ | 53 | ||||
Capitalized interest | $ | 809 | $ | - | $ | - | ||||
Purchase minority interest in RockPile | $ | - | $ | 12,349 | $ | - | ||||
Acquisition of oilfield services equipment through notes payable and liabilities | $ | 1,990 | $ | - | $ | - | ||||
Quarterly_Financial_Informatio
Quarterly Financial Information | 12 Months Ended | ||||||||||||||||||
Jan. 31, 2014 | |||||||||||||||||||
Quarterly Financial Information [Abstract] | ' | ||||||||||||||||||
Quarterly Financial Information | ' | ||||||||||||||||||
26. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||
The Company’s quarterly financial information for FY2014 and FY2013 is as follows: | |||||||||||||||||||
For the Year Ended January 31, 2014 | |||||||||||||||||||
(in thousands) | First Quarter | Second Quarter | Third Quarter* (restated) | Fourth Quarter | |||||||||||||||
Total revenue | $ | 34,294 | $ | 50,394 | $ | 88,549 | $ | 85,510 | |||||||||||
Income from operations | $ | 4,426 | $ | 13,077 | $ | 17,188 | $ | 11,975 | |||||||||||
Net income | $ | 5,211 | $ | 6,799 | $ | 47,221 | $ | 14,249 | |||||||||||
Net income attributable to common stockholders | $ | 5,211 | $ | 6,799 | $ | 47,221 | $ | 14,249 | |||||||||||
Net income per common share - basic | $ | 0.10 | $ | 0.12 | $ | 0.60 | $ | 0.17 | |||||||||||
Net income per common share - diluted | $ | 0.10 | $ | 0.12 | $ | 0.50 | $ | 0.15 | |||||||||||
For the Year Ended January 31, 2013 | |||||||||||||||||||
(in thousands) | First Quarter** | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||||
Total revenue | $ | 5,241 | $ | 10,132 | $ | 21,300 | $ | 24,028 | |||||||||||
Loss from operations | $ | -3,336 | $ | -1,389 | $ | -617 | $ | -2,828 | |||||||||||
Net loss | $ | -3,324 | $ | -1,335 | $ | -672 | $ | -9,153 | |||||||||||
Net loss attributable to common stockholders | $ | -3,028 | $ | -1,079 | $ | -598 | $ | -9,055 | |||||||||||
Net loss per common share - basic and diluted | $ | -0.07 | $ | -0.02 | $ | -0.01 | $ | -0.2 | |||||||||||
* Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | |||||||||||||||||||
** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Triangle’s April 30, 2012 Quarterly Report on Form 10-Q. | |||||||||||||||||||
Restatement | |||||||||||||||||||
During preparation of its consolidated financial statements for the fiscal year ended January 31, 2014, the Company determined that its condensed consolidated financial statements for the fiscal quarter ended October 31, 2013 included in the Company’s Form 10-Q for such period should be restated to include an error correction that recognizes the fair value of equity investment derivatives for the Class A Trigger Units, Class A Trigger Unit Warrants, and Warrants (Series 1 through Series 4) that the Company holds in Caliber. The Company intends to file restated condensed consolidated financial statements for the fiscal quarter ended October 31, 2013 under the cover of Form 10-Q/A as soon as reasonably practicable following the filing of this Annual Report on Form 10-K. The following table reflects the expected corrections on relevant financial statement captions. | |||||||||||||||||||
Condensed Consolidated Balance Sheets | |||||||||||||||||||
As of October 31, 2013 | |||||||||||||||||||
As | Adjustments | As Restated | |||||||||||||||||
(in thousands, except per share data) Selected Financial Statement Caption | Previously Reported | ||||||||||||||||||
Equity investment | $ | 22,395 | $ | 35,832 | $ | 58,227 | |||||||||||||
Total assets | 889,088 | 35,832 | 924,920 | ||||||||||||||||
Deferred tax liability | - | 5,969 | 5,969 | ||||||||||||||||
Total liabilities | 412,215 | 5,969 | 418,184 | ||||||||||||||||
Accumulated deficit | -92,651 | 29,863 | -62,788 | ||||||||||||||||
Total stockholders' equity | 476,873 | 29,863 | 506,736 | ||||||||||||||||
Total liabilities and stockholders' equity | $ | 889,088 | $ | 35,832 | $ | 924,920 | |||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||||||||||||||||
For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||
31-Oct-13 | 31-Oct-13 | ||||||||||||||||||
As | Adjustments | As Restated | As | Adjustments | As Restated | ||||||||||||||
(in thousands, except per share data) | Previously Reported | Previously Reported | |||||||||||||||||
Selected Financial Statement Caption | |||||||||||||||||||
Gain on equity investment derivative | $ | - | $ | 35,832 | $ | 35,832 | $ | - | $ | 35,832 | $ | 35,832 | |||||||
Total other income (expense) | 170 | 35,832 | 36,002 | -5,323 | 35,832 | 30,509 | |||||||||||||
Net income (loss) before income taxes | 17,358 | 35,832 | 53,190 | 29,369 | 35,832 | 65,201 | |||||||||||||
Income tax provision | - | -5,969 | -5,969 | - | -5,969 | -5,969 | |||||||||||||
Net income (loss) | 17,358 | 47,221 | 29,369 | 29,863 | 59,232 | ||||||||||||||
Net income (loss) attributable to common stockholders | 17,358 | 29,863 | 47,221 | 29,369 | 29,863 | 59,232 | |||||||||||||
Net income (loss) per common share outstanding: | |||||||||||||||||||
Basic | $ | 0.22 | $ | 0.38 | $ | 0.60 | $ | 0.47 | $ | 0.47 | $ | 0.94 | |||||||
Diluted | $ | 0.20 | $ | 0.30 | $ | 0.50 | $ | 0.43 | $ | 0.35 | $ | 0.78 | |||||||
The net restatement had no effect on cash flows from operating, investing, or financing activities. | |||||||||||||||||||
Our equity investment in Caliber consists of Class A Units and equity derivative instruments. Due to the increase in the fair value of the equity investment derivatives in the third fiscal quarter ended October 31, 2013, the Company recognized a gain in equity investment derivatives of $35.8 million in the accompanying consolidated statement of operations; see Note 11 - Equity Investment and Note 14 - Derivative Instruments. | |||||||||||||||||||
The recognition of an additional $35.8 million in other income results in an increase in net deferred tax liability of $6.0 million recorded as an adjustment to the accompanying consolidated balance sheet with a corresponding income tax provision of $6.0 million on the accompanying consolidated statement of operations; see Note 19 – Income Taxes. | |||||||||||||||||||
Subsequent_Events
Subsequent Events | 12 Months Ended |
Jan. 31, 2014 | |
Subsequent Events [Abstract] | ' |
Subsequent Events | ' |
27. SUBSEQUENT EVENTS | |
FY2015 RockPile Credit Agreement | |
On March 25, 2014, RockPile entered into the FY2015 RockPile Credit Agreement with a syndicate of lenders led by Citi 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. RockPile’s assets are pledged as collateral under the FY2015 RockPile Credit Agreement, with certain exceptions relating to real property interests. 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 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. In connection with the FY2015 RockPile Credit Agreement, RockPile withdrew funds to pay down and terminate the RockPile Credit Agreement. | |
Basis_Of_Presentation_Policy
Basis Of Presentation (Policy) | 12 Months Ended | |||
Jan. 31, 2014 | ||||
Basis Of Presentation [Abstract] | ' | |||
Use of Estimates | ' | |||
Use of Estimates | ||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management believes the major estimates and assumptions impacting our consolidated financial statements are the following: | ||||
· | estimates of proved reserves of oil and natural gas, which affect the calculations of amortization and impairment of capitalized costs of oil and natural gas properties; | |||
· | estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells; | |||
· | estimates as to the future realization of deferred income tax assets; | |||
· | the assumption required by GAAP that proved reserves and proved reserve value for measuring capitalized cost impairment be based (for each proved property) on simple averages of the preceding twelve months’ historical oil and natural gas prices on the first day of each month; | |||
· | impairment of undeveloped properties and other assets; | |||
· | depreciation of property and equipment; | |||
· | valuation of commodity derivative instruments; and | |||
· | impairment of goodwill. | |||
The estimated fair values of our unevaluated oil and natural gas properties affects our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and natural gas properties. | ||||
Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. | ||||
Principles of Consolidation | ' | |||
Principles of Consolidation | ||||
The accounts of Triangle and its wholly owned subsidiaries are presented in the accompanying consolidated financial statements. The accounts of Triangle Petroleum Corporation and its subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. | ||||
These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: (i) TUSA, incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile, organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (iv) Leaf Minerals, LLC, organized in the State of Colorado, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, and (vi) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. Additionally, Triangle Caliber Holdings LLC is a joint venture partner in Caliber Midstream Partners LP (“Caliber). The investment in Caliber is accounted for utilizing the equity method of accounting. See Note 11 – Equity Investment for further discussion on Caliber. | ||||
The Company’s 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”), used in these Notes to Consolidated Financial Statements refer to the fiscal years ended January 31, 2015, 2014, 2013, and 2012, respectively. | ||||
Certain amounts in prior years’ consolidated financial statements have been reclassified to conform to the FY2014 financial statement presentation. Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported. | ||||
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended | ||
Jan. 31, 2014 | |||
Summary Of Significant Accounting Policies [Abstract] | ' | ||
Cash And Cash Equivalents | ' | ||
Cash and Cash Equivalents | |||
Cash and cash equivalents consist of cash in banks in the United States and Canada. Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. | |||
Fair Value Of Financial Instruments | ' | ||
Fair Value of Financial Instruments | |||
The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments and equity investment derivatives (See Note 14 – Derivative Instruments), marketable securities (See Note 12 - Investment in Marketable Securities) and long-term debt (See Note 13 – Long-Term Debt). Triangle measures fair value in accordance with ASC Topic 820, Fair Value Measurement and Disclosure. ASC 820 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. | |||
The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. Commodity derivatives are recorded on the consolidated balance sheets at amounts which approximate their fair value. The Company’s equity investment derivatives are included in equity investments and recorded at amounts which approximate their fair value on the consolidated balance sheets. The carrying amount of the Company's credit facilities approximates fair value as it bears interest at variable rates over the term of the loan. The Company's 5% Convertible Promissory Note (the “Convertible Note”) issued by the Company to NGP Triangle Holdings, LLC (“NGP”) on July 31, 2012, is recorded at cost and the fair value is disclosed in Note 10 - Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. | |||
Accounts Receivable And Credit Policies | ' | ||
Accounts Receivable and Credit Policies | |||
We have certain trade receivables due under normal trade terms and primarily consisting of oil and natural gas sales receivables and trade receivables from third parties participating in the drilling, completion and production of wells we operate and wells for which RockPile provides services. Our management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. At January 31, 2014 and 2013, management had determined that no allowance for uncollectible oil and natural gas trade or sales receivables was necessary. | |||
Oilfield services accounts receivable are stated at the amount billed to customers and are ordinarily due within 30 days of the invoice date. As of the date of these consolidated financial statements, and since inception, the Company has collected all amounts owed. As a result, the Company has not provided for an allowance for doubtful accounts as of the date of the consolidated financial statements. RockPile’s current customer base is comprised of TUSA and other highly credit-worthy third-party customers. Periodically, the Company performs a review of its customer base including outstanding receivables, historical collection information, existing economic conditions and the customer’s creditworthiness to determine the need for establishing an allowance for doubtful accounts. A provision for doubtful accounts would be recorded when non-payment of amounts owed is deemed probable. | |||
Inventories | ' | ||
Inventories | |||
Inventories maintained by the Company consist of well equipment, sand, chemicals and/or ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors in evaluating net realizable value. | |||
Investment In Unconsolidated Entities | ' | ||
Investment in Unconsolidated Entities | |||
The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations and comprehensive income (loss) (after elimination of intra-company profits and losses). The carrying value of the Company’s investments in unconsolidated entities is recorded in the Equity Investment line of the Consolidated Balance Sheets. The Company records losses of the unconsolidated entities only to the extent of the Company's investment. | |||
We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. See discussion in Note 11 – Equity Investment. | |||
Concentration Of Credit Risk | ' | ||
Concentration of Credit Risk | |||
Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash. We maintain substantially all cash assets at four financial institutions - Wells Fargo Bank, RBC Canada, Citi Private Bank and Chase Bank. We periodically evaluate the credit worthiness of financial institutions, and we maintain cash accounts only in large, high quality financial institutions. We believe that credit risk associated with cash is remote. The Company often has balances in excess of the federally insured limits. | |||
The Company's receivables are comprised of oil and natural gas revenue receivables, joint interest billings receivable and receivables associated with oilfield services. The amounts are due from a number of entities. Therefore, the collectability is dependent upon the general economic conditions of a few purchasers, joint interest owners and customers. The receivables are not collateralized. To date the Company has had no bad debts. | |||
The Company's commodity derivative contracts are currently with four counterparties. The counterparties to the derivative instruments are highly rated entities. The creditworthiness of counter-parties is subject to continuing review. | |||
Oil And Natural Gas Properties | ' | ||
Oil and Natural Gas Properties | |||
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 in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively. The cost pools are amortized on a unit-of-production basis using proved oil and gas reserves. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. 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 for each full cost pool. This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) do not exceed the sum of (i) the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, (ii) the pool’s cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (iv) all related tax effects. If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense. Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. See Note 8 - Property and Equipment for disclosures regarding ceiling test impairments. | |||
Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. | |||
Under the full cost method, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | |||
Other Property And Equipment | ' | ||
Other Property and Equipment | |||
We record at cost any long-lived tangible assets that are not oil and natural gas properties. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived property and equipment, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not found or recognized any impairment losses on such other property and equipment. Depreciation is recorded using the straight-line method (to the extent of estimated salvage values) over the estimated useful lives of the related assets as follows: | |||
Depreciable | |||
Asset | Life (years) | ||
Building and improvements | 20-Oct | ||
Oilfield services equipment | 5 | ||
Vehicles | 5 | ||
Leasehold improvements | 10 | ||
Software and computers | 5-Mar | ||
Office equipment | 3 | ||
Asset Retirement Obligations | ' | ||
Asset Retirement Obligations | |||
We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base. | |||
Oil And Natural Gas Reserves | ' | ||
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 are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation or Three Forks formation in North Dakota. | |||
Our internal Senior Reservoir Engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available. | |||
Deferred Financing Costs | ' | ||
Deferred Financing Costs | |||
Deferred financing costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company's credit facilities and Convertible Note. Deferred financing costs are amortized to interest expense on a straight-line basis over the respective borrowing term. | |||
Derivatives Instruments | ' | ||
Derivative Instruments | |||
Commodity derivative | |||
Our commodity derivative contracts are measured at fair value and are included on the consolidated balance sheets as either derivative assets or liabilities. The accounting treatment for settlements and the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the contracts we entered into during the periods covered in these consolidated financial statements. Realized and unrealized gains and losses on commodity derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. Net gains and losses on commodity derivative activities are recorded based on the changes in the fair values of the derivative instruments. Cash settlements of our commodity derivative contracts are included in cash flows from operating activities in our consolidated statements of cash flows. | |||
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 in equity investment on the consolidated balance sheet. Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations. | |||
Income Taxes | ' | ||
Income Taxes | |||
Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes. We compute deferred income taxes using the liability method whereby deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. | |||
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). | |||
Contingencies | ' | ||
Contingencies | |||
A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. We have not accrued for any contingencies as of January 31, 2014. | |||
Revenue Recognition | ' | ||
Revenue Recognition | |||
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 has transferred, and/or collectability is reasonably assured and evidenced by a contract. Additionally, there were no oil or natural gas sales imbalances at January 31, 2014 2013 and 2012. | |||
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 only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment as defined in the contract, whether or not those services are actually utilized. To the extent customers utilize more than the contracted minimum, they are invoiced for such excess at rates defined in the contract. As of January 31, 2014, the Company has not entered into any pressure pumping term contracts with third parties. | |||
Under the full cost method, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | |||
Share-Based Compensation | ' | ||
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. | |||
Earnings Per Share | ' | ||
Earnings per Share | |||
Basic earnings per share (EPS) is computed by dividing net gain (or loss) available to common stock (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS gives effect to all dilutive instruments outstanding during the period including convertible debt, restricted stock units, stock options and warrants, using the treasury stock method. In computing diluted EPS, the average stock price for the period is used in determining the number of shares assumed to be purchased from the exercise of stock options or warrants. Diluted EPS excludes instruments if their effect is anti-dilutive. | |||
Business Combinations | ' | ||
Business Combinations | |||
Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair values at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of the net assets acquired and their tax basis. Any excess of purchase price over the fair value of the net assets acquired is recognized as goodwill. Associated transaction costs are expensed when incurred. | |||
Goodwill | ' | ||
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 would be a significant decline to 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 to fair value of a reporting unit is more likely than not, 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 a reporting unit based on discounted future probability-weighted cash flows. If Step 1 indicates that the carrying value of a reporting unit is in excess of 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 calculated in Step 2. Our goodwill represents consideration paid in excess of the fair value of the identifiable net assets acquired in a business combination. Our goodwill results from the October 16, 2013 acquisition of Team Well Service, Inc. by RockPile and is preliminary (see Note 9 – Intangible Assets and Goodwill). We review goodwill for impairment annually, or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of the reporting unit could be less than its carrying amount. | |||
Intangible Assets | ' | ||
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. | |||
Off Balance Sheet Arrangements | ' | ||
Off Balance Sheet Arrangements | |||
We have no significant off balance sheet arrangements. | |||
Segment Information | ' | ||
Segment Information | |||
In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have 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 exploration and production operating segment is responsible for finding and producing oil and natural gas. The oilfield services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties. See Note 4 - Segment Reporting. | |||
Recent Accounting Developments | ' | ||
Recent Accounting Developments | |||
No significant accounting standards applicable to Triangle have been issued during FY2014. | |||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended | ||
Jan. 31, 2014 | |||
Summary Of Significant Accounting Policies [Abstract] | ' | ||
Property And Equipment Useful Lives | ' | ||
Depreciable | |||
Asset | Life (years) | ||
Building and improvements | 20-Oct | ||
Oilfield services equipment | 5 | ||
Vehicles | 5 | ||
Leasehold improvements | 10 | ||
Software and computers | 5-Mar | ||
Office equipment | 3 | ||
Segment_Reporting_Tables
Segment Reporting (Tables) | 12 Months Ended | |||||||||||||||||||||||
Jan. 31, 2014 | ||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||||||||||
Schedule Of Segment Reporting | ' | |||||||||||||||||||||||
For the year ended January 31, 2014 | ||||||||||||||||||||||||
(in thousands) | Exploration and Production | Oilfield Services | Corporate and Other (1) | Eliminations and Other | Consolidated Total | |||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Oil and natural gas sales | $ | 160,548 | $ | - | $ | - | $ | - | $ | 160,548 | ||||||||||||||
Oilfield services for third parties | - | 102,606 | - | -4,407 | 98,199 | |||||||||||||||||||
Intersegment revenues | - | 91,019 | - | -91,019 | - | |||||||||||||||||||
Other | - | - | 1,192 | -1,192 | - | |||||||||||||||||||
Total revenues | 160,548 | 193,625 | 1,192 | -96,618 | 258,747 | |||||||||||||||||||
Expenses | ||||||||||||||||||||||||
Production taxes and other lease operating | 32,460 | - | - | - | 32,460 | |||||||||||||||||||
Gathering, transportation and processing | 4,302 | - | - | - | 4,302 | |||||||||||||||||||
Depreciation and amortization | 51,065 | 8,905 | 620 | -3,542 | 57,048 | |||||||||||||||||||
Accretion and other asset retirement obligation expenses | 1,018 | - | - | - | 1,018 | |||||||||||||||||||
Cost of oilfield services | - | 142,339 | - | -60,012 | 82,327 | |||||||||||||||||||
General and Administrative: | ||||||||||||||||||||||||
Stock-based compensation | 1,127 | 590 | 6,113 | - | 7,830 | |||||||||||||||||||
Other general and administrative | 7,777 | 11,116 | 8,203 | - | 27,096 | |||||||||||||||||||
Total operating expenses | 97,749 | 162,950 | 14,936 | -63,554 | 212,081 | |||||||||||||||||||
Income (loss) from operations | 62,799 | 30,675 | -13,744 | -33,064 | 46,666 | |||||||||||||||||||
Other income (expense), net | 125 | -991 | 37,805 | -2,184 | 34,755 | |||||||||||||||||||
Net income (loss) before income taxes | $ | 62,924 | $ | 29,684 | $ | 24,061 | $ | -35,248 | $ | 81,421 | ||||||||||||||
Total Assets | $ | 821,042 | $ | 126,114 | $ | 177,500 | $ | -97,072 | $ | 1,027,584 | ||||||||||||||
Net oil and natural gas properties | $ | 730,718 | $ | - | $ | - | $ | -47,931 | $ | 682,787 | ||||||||||||||
Oilfield services equipment - net | $ | - | $ | 46,586 | $ | - | $ | - | $ | 46,586 | ||||||||||||||
Other property and equipment - net | $ | 1,594 | $ | 18,912 | $ | 4,001 | $ | - | $ | 24,507 | ||||||||||||||
Total Liabilities | $ | 318,875 | $ | 64,017 | $ | 141,671 | $ | -20,141 | $ | 504,422 | ||||||||||||||
-1 | Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or oilfield services segments. These subsidiaries have limited activity. | |||||||||||||||||||||||
For the year ended January 31, 2013 | ||||||||||||||||||||||||
(in thousands) | Exploration and Production | Oilfield Services | Corporate and Other (1) | Eliminations and Other | Consolidated Total | |||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Oil and natural gas sales | $ | 39,614 | $ | - | $ | - | $ | - | $ | 39,614 | ||||||||||||||
Oilfield services for third parties | - | 22,535 | - | -1,788 | 20,747 | |||||||||||||||||||
Intersegment revenues | - | 34,672 | - | -34,672 | - | |||||||||||||||||||
Other | 248 | - | 975 | -883 | 340 | |||||||||||||||||||
Total revenues | 39,862 | 57,207 | 975 | -37,343 | 60,701 | |||||||||||||||||||
Expenses | ||||||||||||||||||||||||
Production taxes and other lease operating | 8,058 | - | - | - | 8,058 | |||||||||||||||||||
Gathering, transportation and processing | 150 | - | - | - | 150 | |||||||||||||||||||
Depreciation and amortization | 13,578 | 2,857 | 378 | -1,732 | 15,081 | |||||||||||||||||||
Accretion and other asset retirement obligation expenses | 184 | - | - | - | 184 | |||||||||||||||||||
Cost of oilfield services | - | 39,534 | - | -22,928 | 16,606 | |||||||||||||||||||
General and Administrative: | ||||||||||||||||||||||||
Stock-based compensation | 2,507 | 617 | 3,342 | - | 6,466 | |||||||||||||||||||
Other general and administrative | 6,838 | 11,130 | 4,358 | - | 22,326 | |||||||||||||||||||
Total operating expenses | 31,315 | 54,138 | 8,078 | -24,660 | 68,871 | |||||||||||||||||||
Income (loss) from operations | 8,547 | 3,069 | -7,103 | -12,683 | -8,170 | |||||||||||||||||||
Other income (expense), net | -6,318 | 4 | - | - | -6,314 | |||||||||||||||||||
Net income (loss) before income taxes | $ | 2,229 | $ | 3,073 | $ | -7,103 | $ | -12,683 | $ | -14,484 | ||||||||||||||
Total Assets | $ | 362,878 | $ | 38,668 | $ | 40,220 | $ | -13,445 | $ | 428,321 | ||||||||||||||
Net oil and natural gas properties | $ | 310,557 | $ | - | $ | - | $ | -11,800 | $ | 298,757 | ||||||||||||||
Oilfield services equipment - net | $ | - | $ | 18,878 | $ | - | $ | - | $ | 18,878 | ||||||||||||||
Other property and equipment - net | $ | 1,597 | $ | 12,443 | $ | 1,739 | $ | - | $ | 15,779 | ||||||||||||||
Total Liabilities | $ | 91,134 | $ | 11,845 | $ | 125,364 | $ | -1,644 | $ | 226,699 | ||||||||||||||
-1 | Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or oilfield services segments. These subsidiaries have limited activity. | |||||||||||||||||||||||
Oil_And_Natural_Gas_Properties1
Oil And Natural Gas Properties (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Oil And Natural Gas Properties [Abstract] | ' | ||||||||||||
Capitalized Costs Relating To Oil And Gas Producing Activities | ' | ||||||||||||
January 31, | January 31, | ||||||||||||
(in thousands) | 2014 | 2013 | |||||||||||
Oil and natural gas properties, full cost method: | |||||||||||||
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, full cost method | 750,444 | 315,423 | |||||||||||
Less accumulated amortization | -67,657 | -16,666 | |||||||||||
Net carrying value of oil and natural gas properties | $ | 682,787 | $ | 298,757 | |||||||||
Schedule Of Capitalized Costs Incurred | ' | ||||||||||||
Years Ended January 31, | |||||||||||||
(in thousands) | 2014 | 2013 | 2012 | ||||||||||
Costs incurred during the year | |||||||||||||
Acquisition of properties: | |||||||||||||
Proved | $ | 80,201 | $ | 623 | $ | - | |||||||
Unproved | 41,377 | 20,570 | 87,226 | ||||||||||
Exploration | 96,731 | 55,583 | 40,728 | ||||||||||
Development | 216,046 | 91,666 | 4,706 | ||||||||||
Oil and natural gas expenditures | 434,355 | 168,442 | 132,660 | ||||||||||
Asset retirement obligation, net | 676 | 370 | 3 | ||||||||||
$ | 435,031 | $ | 168,812 | $ | 132,663 | ||||||||
Costs Not Being Amortized | ' | ||||||||||||
Type of Capitalized Cost | |||||||||||||
(in thousands) | Total | Acquisition | Exploration | Capitalized Interest | |||||||||
Capitalized at January 31, 2014 | |||||||||||||
Not yet being amortized | $ | 121,393 | $ | 108,147 | $ | 10,225 | $ | 3,021 | |||||
Incurred in fiscal year 2014 | $ | 54,623 | $ | 41,377 | $ | 10,225 | $ | 3,021 | |||||
Incurred in fiscal year 2013 | $ | 15,618 | $ | 15,618 | $ | - | $ | - | |||||
Incurred in fiscal year 2012 | $ | 44,620 | $ | 44,620 | $ | - | $ | - | |||||
Incurred in prior years | $ | 6,532 | $ | 6,532 | $ | - | $ | - | |||||
Acquisitions_Tables
Acquisitions (Tables) | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Acquisitions [Abstract] | ' | ||||||
Summary Of Purchase Price And Preliminary Estimated Values Of Assets Acquired And Liabilities Assumed | ' | ||||||
Preliminary purchase price: | |||||||
Consideration given | |||||||
Cash | $ | 83,805 | |||||
Total consideration given | $ | 83,805 | |||||
Preliminary fair value allocation of purchase price: | |||||||
Oil and natural gas properties: | |||||||
Proved properties | $ | 50,200 | |||||
Unproved properties | 32,976 | ||||||
Total oil and natural gas properties | 83,176 | ||||||
Accounts payable | 761 | ||||||
Asset retirement obligation assumed | -132 | ||||||
Fair value of net assets acquired | $ | 83,805 | |||||
Proforma Schedule For Oil And Natural Gas Acquisition | ' | ||||||
For the Year Ended | |||||||
January 31, | |||||||
(in thousands, except per share data) | 2014 | 2013 | |||||
Operating revenues | $ | 272,548 | $ | 63,167 | |||
Net income (loss) | $ | 80,086 | $ | -13,903 | |||
Earnings (loss) per common share | |||||||
Basic | $ | 1.07 | $ | -0.25 | |||
Diluted | $ | 0.93 | $ | -0.25 | |||
Weighted average common shares outstanding: | |||||||
Basic | 75,046,511 | 55,794,054 | |||||
Diluted | 91,025,500 | 55,794,054 | |||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Asset Retirement Obligations [Abstract] | ' | |||||||||
Asset Retirement Obligations | ' | |||||||||
For the Year Ended | ||||||||||
31-Jan-14 | ||||||||||
(in thousands) | USA | Canada | Total | |||||||
Balance, January 31, 2013 | $ | 1,973 | $ | 1,449 | $ | 3,422 | ||||
Liabilities incurred | 944 | - | 944 | |||||||
Revision of estimates | -188 | 962 | 774 | |||||||
Sale of assets | -83 | - | -83 | |||||||
Liabilities settled | -132 | -352 | -484 | |||||||
Accretion | 56 | - | 56 | |||||||
Balance, January 31, 2014 | 2,570 | 2,059 | 4,629 | |||||||
Less current portion of obligations | -1,361 | -1,972 | -3,333 | |||||||
Long-term asset retirement obligations | $ | 1,209 | $ | 87 | $ | 1,296 | ||||
For the Year Ended | ||||||||||
31-Jan-13 | ||||||||||
(in thousands) | USA | Canada | Total | |||||||
Balance, January 31, 2012 | $ | 83 | $ | 1,540 | $ | 1,623 | ||||
Liabilities incurred | 1,769 | - | 1,769 | |||||||
Revision of estimates | 147 | - | 147 | |||||||
Sale of assets | -48 | - | -48 | |||||||
Liabilities settled | - | -253 | -253 | |||||||
Accretion | 22 | 162 | 184 | |||||||
Balance, January 31, 2013 | 1,973 | 1,449 | 3,422 | |||||||
Less current portion of obligations | -1,500 | -1,449 | -2,949 | |||||||
Long-term asset retirement obligations | $ | 473 | $ | - | $ | 473 | ||||
Property_And_Equipment_Tables
Property And Equipment (Tables) | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Property And Equipment [Abstract] | ' | ||||||
Schedule Of Oil And Gas Property And Equipment | ' | ||||||
January 31, | January 31, | ||||||
(in thousands) | 2014 | 2013 | |||||
Land | $ | 2,512 | $ | 2,520 | |||
Building and leasehold improvements | 18,388 | 4,805 | |||||
Oilfield service equipment | 56,355 | 22,255 | |||||
Vehicles | 2,288 | 1,240 | |||||
Software, computers and office equipment | 3,016 | 1,190 | |||||
Total Depreciable Assets | $ | 82,559 | $ | 32,010 | |||
Accumulated depreciation | -12,799 | -3,339 | |||||
Depreciable assets, net | $ | 69,760 | $ | 28,671 | |||
Assets not placed in service | 1,333 | 5,986 | |||||
Total oilfield service equipment and other property & equipment, net | $ | 71,093 | $ | 34,657 | |||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Fair Value Measurements [Abstract] | ' | ||||||||||||
Schedule Of Fair Value, Assets And Liabilities Measured On Recurring Basis | ' | ||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Derivative assets | $ | - | $ | 2,147 | $ | 39,734 | $ | 41,881 | |||||
Liabilities: | |||||||||||||
Earn-out liability | $ | - | $ | -1,139 | $ | - | $ | -1,139 | |||||
Note payable | $ | - | $ | -9,002 | $ | - | $ | -9,002 | |||||
Rollforward Of Level 3 Financial Liabilities | ' | ||||||||||||
(in thousands) | Convertible Notes | Class A Triggering Units | Warrants (1) | ||||||||||
Beginning balance, February 1, 2012 | $ | - | $ | - | $ | - | |||||||
Sale of Convertible Notes | -120,000 | - | - | ||||||||||
Interest paid in-kind | -3,023 | - | - | ||||||||||
Total net unrecognized loss | -9,877 | - | - | ||||||||||
Ending balance, January 31, 2013 | $ | -132,900 | $ | - | $ | - | |||||||
Initial recognition of equity investment derivative assets | - | 38,091 | 1,643 | ||||||||||
Interest paid in-kind | -6,267 | - | - | ||||||||||
Total net unrecognized gain (loss) | -30,003 | - | - | ||||||||||
Ending balance, January 31, 2014 | $ | -169,170 | $ | 38,091 | $ | 1,643 | |||||||
-1 | Includes Class A Triggering Units, and Series 1 and Series 2 Warrants. | ||||||||||||
Equity_Investment_Tables
Equity Investment (Tables) | 12 Months Ended | ||||||||
Jan. 31, 2014 | |||||||||
Equity Investment [Abstract] | ' | ||||||||
Schedule Of Equity Investment In Caliber | ' | ||||||||
(in thousands, except units) | Units | Price | Investment | ||||||
Balance - January 31, 2013 | $ | $ | 11,768 | ||||||
Class A Units | 3,000,000 | $ | 10.00 | 18,000 | |||||
Class A Trigger Units | 4,000,000 | $ | - | 38,091 | |||||
Class A Trigger Unit Warrants | 1,600,000 | $ | 14.69 | 234 | |||||
Series 1 Warrants | 4,000,000 | $ | 14.69 | 926 | |||||
Series 2 Warrants | 2,400,000 | $ | 24.00 | 254 | |||||
Series 3 Warrants | 3,000,000 | $ | 24.00 | 207 | |||||
Series 4 Warrants | 2,000,000 | $ | 30.00 | 22 | |||||
Distributions | -3,150 | ||||||||
Equity investment share of net income for the year | 2,184 | ||||||||
Balance - January 31, 2014 | $ | 68,536 | |||||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||
Jan. 31, 2014 | |||||||
Long-Term Debt [Abstract] | ' | ||||||
Schedule Of Debt | ' | ||||||
(in thousands) | 31-Jan-14 | 31-Jan-13 | |||||
TUSA credit facility | $ | 183,000 | $ | 25,000 | |||
RockPile credit facility | 21,515 | - | |||||
Less current portion of RockPile credit facility | -8,450 | - | |||||
Long-term portion of credit facilities | 196,065 | 25,000 | |||||
5% Convertible Note | 129,290 | 123,023 | |||||
RockPile notes payable | 9,403 | - | |||||
Less current portion of RockPile notes payable | -401 | - | |||||
Total long-term debt | 334,357 | 148,023 | |||||
Total current portion of debt | 8,851 | - | |||||
Total debt | $ | 343,208 | $ | 148,023 | |||
Commodity_Derivative_Instrumen1
Commodity Derivative Instruments (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2014 | |||||||||||||
Commodity Derivative Instruments [Abstract] | ' | ||||||||||||
Summary Of Derivative Instruments | ' | ||||||||||||
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. | |||||||||||||
Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value | ' | ||||||||||||
(in thousands) | As of January 31, 2014 | ||||||||||||
Underlying Commodity | Balance Sheet Classification | Gross Amount of Recognized Assets (Liabilities) | Gross Amount of Offset | Net Amount of Assets (Liabilities) | |||||||||
Crude oil derivative contract | Current asset | $ | 1,066 | $ | -111 | $ | 955 | ||||||
Crude oil derivative contract | Long-term assets | $ | 1,192 | $ | - | $ | 1,192 | ||||||
Equity investment derivatives | Long-term assets | $ | 39,734 | $ | - | $ | 39,734 | ||||||
(in thousands) | As of January 31, 2013 | ||||||||||||
Underlying Commodity | Balance Sheet Classification | Gross Amount of Recognized Assets (Liabilities) | Gross Amount of Offset | Net Amount of Assets (Liabilities) | |||||||||
Crude oil derivative contract | Current assets | $ | 1,305 | $ | -702 | $ | 603 | ||||||
Crude oil derivative contract | Long-term liabilities | $ | -292 | $ | - | $ | -292 | ||||||
Commitments_And_Contingencies_
Commitments And Contingencies (Tables) | 12 Months Ended | |||
Jan. 31, 2014 | ||||
Commitments And Contingencies [Abstract] | ' | |||
Schedule Of Annual Rentals per Year | ' | |||
Fiscal year ending January 31, | Annual rental amount | |||
2015 | $ | 1,180 | ||
2016 | $ | 1,207 | ||
2017 | $ | 1,234 | ||
2018 | $ | 1,108 | ||
2019 | $ | 617 | ||
Schedule Of Commitments For Future Expenditures | ' | |||
Fiscal year ending January 31, | Annual rental amount | |||
2015 | $ | 1,752 | ||
2016 | $ | 582 | ||
2017 | $ | 441 | ||
2018 | $ | 360 | ||
2019 | $ | 200 | ||
Thereafter | $ | 655 | ||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2013 | ||||||||||
Earnings Per Share [Abstract] | ' | |||||||||
Computations Of Basic And Diluted Net Loss Per Share | ' | |||||||||
2014 | 2013 | 2012 | ||||||||
Net income (loss) attributable to common stockholders | $ | 73,480 | $ | -13,760 | $ | -24,278 | ||||
Effect of debt conversion | 3,392 | - | - | |||||||
Net income (loss) attributable to common stockholders after effect of debt conversion | 76,872 | -13,760 | -24,278 | |||||||
Basic weighted average common shares outstanding | 68,578,553 | 44,475,201 | 40,707,957 | |||||||
Effect of dilutive securities | 15,978,989 | - | - | |||||||
Diluted weighted average common shares outstanding | 84,557,542 | 44,475,201 | 40,707,957 | |||||||
Basic net income (loss) per share | $ | 1.07 | $ | -0.31 | $ | -0.6 | ||||
Diluted net income (loss) per share | $ | 0.91 | $ | -0.31 | $ | -0.6 | ||||
2014 | 2013 | 2012 | ||||||||
Anti-dilutive shares | 5,250,000 | 4,500,000 | - | |||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Income Taxes [Abstract] | ' | |||||||||
Schedule Of Income Tax Expense (Benefit) | ' | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Current tax expense (benefit) | $ | - | $ | - | $ | - | ||||
Deferred tax expense (benefit) | ||||||||||
Federal | 7,324 | -2,137 | -6,189 | |||||||
State | 617 | -223 | -175 | |||||||
Foreign | - | -83 | -1,510 | |||||||
Valuation allowance - United States and Canada | - | 2,443 | 7,874 | |||||||
Income tax expense (benefit) | $ | 7,941 | $ | - | $ | - | ||||
Income (loss) before income taxes | $ | 81,421 | $ | -14,484 | $ | -24,423 | ||||
Effective income tax rate | 10% | 0% | 0% | |||||||
Reconciliation Of Income Tax Expense (Benefit) | ' | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Federal statutory tax expense (benefit) | $ | 28,498 | $ | -5,069 | $ | -8,361 | ||||
State income tax expense / (benefit), net of federal income tax benefit | 2,324 | -361 | -565 | |||||||
Permanent differences | 3,221 | 2,280 | 132 | |||||||
Difference in foreign tax rates | 164 | 28 | 600 | |||||||
Effect of tax rate change | -258 | -71 | 83 | |||||||
Credits | -100 | - | - | |||||||
Changes in valuation allowance | -26,364 | 2,443 | 7,874 | |||||||
Other | 456 | 750 | 237 | |||||||
Provision for income taxes | $ | 7,941 | $ | - | $ | - | ||||
Components Of Deferred Tax Assets And Liabilities | ' | |||||||||
2014 | 2013 | |||||||||
(in thousands) | ||||||||||
Current: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | $ | 1,071 | $ | - | ||||||
Accruals | 102 | - | ||||||||
Hedging assets | - | 1,342 | ||||||||
Total current assets | 1,173 | 1,342 | ||||||||
Valuation allowance | -492 | -1,342 | ||||||||
Total current assets after valuation allowance | 681 | - | ||||||||
Liabilities: | ||||||||||
Hedging liabilities | -361 | - | ||||||||
Total current liabilities | -361 | - | ||||||||
Net current deferred income tax asset | $ | 321 | $ | |||||||
Non-Current: | ||||||||||
Assets: | ||||||||||
Canadian oil and natural gas properties | 6,080 | 6,095 | ||||||||
United States net losses carried forward | 33,129 | 37,816 | ||||||||
Canadian net losses carried forward | 1,905 | 1,726 | ||||||||
Asset retirement obligations | 416 | 1,102 | ||||||||
Stock-based compensation | 3,105 | 1,356 | ||||||||
Investment in RockPile | - | - | ||||||||
Investment in Caliber | - | 106 | ||||||||
Property and equipment | 157 | 157 | ||||||||
Hedging assets | - | - | ||||||||
Other | 1,864 | 673 | ||||||||
Total non-current assets | 46,656 | 49,031 | ||||||||
Valuation allowance | -8,165 | -33,679 | ||||||||
Total non-current assets after valuation allowance | 38,491 | 15,352 | ||||||||
Liabilities: | ||||||||||
United States oil and natural gas properties | -29,536 | -15,275 | ||||||||
Investment in Caliber | -16,766 | |||||||||
Hedging liabilities | -451 | |||||||||
Other | - | -77 | ||||||||
Total deferred non-current income tax liability | -46,753 | -15,352 | ||||||||
Net non-current deferred income tax liability | $ | -8,262 | $ | - | ||||||
ShareBased_Compensation_Tables
Share-Based Compensation (Tables) | 12 Months Ended | ||||||||||
Jan. 31, 2014 | |||||||||||
Non-Cash Stock-Based Compensation Cost | ' | ||||||||||
Years Ended January 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Restricted stock units | $ | 7,496 | $ | 6,639 | $ | 7,512 | |||||
Stock options | 1,135 | 60 | 81 | ||||||||
Stock issued pursuant to termination agreements | - | 99 | 185 | ||||||||
RockPile stock based compensation related to Series B Units | 590 | 617 | - | ||||||||
9,221 | 7,415 | 7,778 | |||||||||
Less amounts capitalized to oil and natural gas properties | -1,391 | -949 | -211 | ||||||||
Compensation expense | $ | 7,830 | $ | 6,466 | $ | 7,567 | |||||
Restricted Stock Units Outstanding | ' | ||||||||||
Number of Shares | Weighted- Average Award Date Fair Value | ||||||||||
Restricted stock units outstanding - January 31, 2011 | 509,636 | $ | 5.61 | ||||||||
Units granted in fiscal year 2012 | 2,645,110 | $ | 7.06 | ||||||||
Units forfeited in fiscal year 2012 | -134,000 | $ | 6.81 | ||||||||
Units that vested during in fiscal year 2012 | -532,404 | $ | 6.20 | ||||||||
Restricted stock units outstanding - January 31, 2012 | 2,488,342 | $ | 7.02 | ||||||||
Units granted in fiscal year 2013 | 1,041,400 | $ | 6.37 | ||||||||
Units forfeited in fiscal year 2013 | -5,600 | $ | 7.59 | ||||||||
Units that vested during in fiscal year 2013 | -1,000,057 | $ | 6.90 | ||||||||
Restricted stock units outstanding - January 31, 2013 | 2,524,085 | $ | 6.68 | ||||||||
Units granted in fiscal year 2014 | 1,440,133 | $ | 6.95 | ||||||||
Units forfeited in fiscal year 2014 | -141,909 | $ | 6.58 | ||||||||
Units that vested during in fiscal year 2014 | -946,681 | $ | 6.71 | ||||||||
Restricted stock units outstanding - January 31, 2014 | 2,875,628 | $ | 6.62 | ||||||||
CEO Option Grant Plan Fair Value Assumptions | ' | ||||||||||
Risk free rate | 2.18% | ||||||||||
Dividend yield | - | ||||||||||
Expected volatility | 62% | ||||||||||
Weighted average expected stock option life (years) | 6.3 | ||||||||||
Stock Options Outstanding Under The Rolling Plan | ' | ||||||||||
Number of Shares | Weighted Average Exercise Price | ||||||||||
Options outstanding - January 31, 2011 (125,833 exercisable) | 343,334 | $ | 1.60 | ||||||||
Options forfeited | -25,000 | $ | 3.00 | ||||||||
Options exercised | -82,501 | $ | 1.34 | ||||||||
Options outstanding - January 31, 2012 (142,500 exercisable) | 235,833 | $ | 1.50 | ||||||||
Options exercised | -4,167 | $ | 3.00 | ||||||||
Options outstanding - January 31, 2013 (231,666 exercisable) | 231,666 | $ | 1.48 | ||||||||
Options forfeited | -15,000 | $ | 3.00 | ||||||||
Options exercised | -108,333 | $ | 1.25 | ||||||||
Options granted | 6,000,000 | $ | 11.25 | ||||||||
Options outstanding - January 31, 2014 (108,333 exercisable) | 6,108,333 | $ | 11.07 | ||||||||
Stock Options Outstanding By Exercise Price | ' | ||||||||||
Remaining | |||||||||||
Exercise Price | Contractual Life | Number of shares | |||||||||
per Share | (years) | Outstanding | Exercisable | ||||||||
$ | 1.25 | 0.83 | 108,333 | 108,333 | |||||||
$ | 7.50 | 9.43 | 750,000 | - | |||||||
$ | 8.50 | 9.43 | 750,000 | - | |||||||
$ | 10.00 | 9.43 | 1,500,000 | - | |||||||
$ | 12.00 | 9.43 | 1,500,000 | - | |||||||
$ | 15.00 | 9.43 | 1,500,000 | - | |||||||
6,108,333 | 108,333 | ||||||||||
Weighted average exercise price per share | $ | 11.07 | $ | 1.25 | |||||||
Weighted average remaining contractual life | 9.27 | 0.83 | |||||||||
Summary Of Non-Vested Options | ' | ||||||||||
Number of Shares | Weighted-Average Grant Date Fair Value | ||||||||||
Non-vested options - January 31, 2011 | 217,500 | $ | 1.10 | ||||||||
Options vested | -107,501 | $ | 1.08 | ||||||||
Less options forfeited | -16,667 | $ | 2.13 | ||||||||
Non-vested options - January 31, 2012 | 93,332 | $ | 1.02 | ||||||||
Options vested | -93,332 | $ | 1.02 | ||||||||
Non-vested options - January 31, 2013 | - | $ | - | ||||||||
Options granted | 6,000,000 | $ | 11.25 | ||||||||
Non-vested options - January 31, 2014 | 6,000,000 | $ | 11.25 | ||||||||
Summary Of Series B Unit Activity | ' | ||||||||||
Number of Series B Units | Weighted Average Award Date Unit Fair Value | ||||||||||
Series B Units outstanding February 1, 2013 | 3,160,000 | $ | - | ||||||||
Series B-3 Unit Grants | 910,000 | $ | 0.7 | ||||||||
Series B Units outstanding January 31, 2014 | 4,070,000 | ||||||||||
Summary Of Series B Unit Vesting Status | ' | ||||||||||
Remaining Vesting Period (Years) | Number of Series B Units | Vested | Unvested | ||||||||
Series B Units outstanding, February 1, 2012 | - | - | - | - | |||||||
Series B-1 Unit Grants | 0.47 | 3,100,000 | 2,566,667 | 533,333 | |||||||
Series B-2 Unit Grants | 1.58 | 60,000 | 15,000 | 45,000 | |||||||
Series B-3 Unit Grants | 3.28 | 910,000 | - | 910,000 | |||||||
Series B Units outstanding, January 31, 2014 | 4,070,000 | 2,581,667 | 1,488,333 | ||||||||
CEO Option Grant [Member] | ' | ||||||||||
Stock Options Outstanding By Exercise Price | ' | ||||||||||
Name of Tranche | Number of Shares | Exercise Price | |||||||||
“$7.50 Tranche” | 750,000 | $7.50 per share | |||||||||
“$8.50 Tranche” | 750,000 | $8.50 per share | |||||||||
“$10.00 Tranche” | 1,500,000 | $10.00 per share | |||||||||
“$12.00 Tranche” | 1,500,000 | $12.00 per share | |||||||||
“$15.00 Tranche” | 1,500,000 | $15.00 per share | |||||||||
Recovered_Sheet1
Significant Changes In Proved Oil And Natural Gas Reserves (Tables) | 12 Months Ended | ||||||||||||||
Jan. 31, 2014 | |||||||||||||||
Significant Changes In Proved Oil And Natural Gas Reserves (Abstract) | ' | ||||||||||||||
Proved Oil And Natural Gas Reserves | ' | ||||||||||||||
% of | 31-Jan-14 | January 31, | |||||||||||||
Reserves | Oil | Gas | NGL | 2013 | % | ||||||||||
Reserve Category | (Mboe) | (Mbbls) | (MMcf) | (Mbbls) | Mboe | Mboe | Change | ||||||||
Proved Developed | 42% | 13,734 | 10,930 | 1,440 | 16,995 | 5,969 | 185% | ||||||||
Proved Undeveloped | 58% | 18,182 | 15,574 | 2,541 | 23,319 | 8,668 | 169% | ||||||||
Total Proved | 100% | 31,916 | 26,504 | 3,981 | 40,314 | 14,637 | 175% | ||||||||
Unaudited_Supplemental_Oil_And1
Unaudited Supplemental Oil And Natural Gas Disclosures (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Summary Of Changes In Estimated Proved Reserves | ' | |||||||||
Crude Oil | Natural Gas | NGL | ||||||||
(in thousands) | (Mbbls) | (MMcf) | (Mbbls) | |||||||
Total proved reserves at January 31, 2011 | 1,236 | - | - | |||||||
Revisions of previous estimates | -932 | - | - | |||||||
Purchase of reserves | - | - | - | |||||||
Extensions, discoveries and other additions | 1,154 | 686 | - | |||||||
Sale of reserves | - | - | - | |||||||
Production | -93 | -12 | - | |||||||
Total proved reserves at January 31, 2012 | 1,365 | 674 | - | |||||||
Revisions of previous estimates | 665 | 1,832 | - | |||||||
Purchase of reserves | 230 | 181 | - | |||||||
Extensions, discoveries and other additions | 10,960 | 10,251 | - | |||||||
Sale of reserves | -229 | -165 | - | |||||||
Production | -452 | -188 | - | |||||||
Total proved reserves at January 31, 2013 | 12,539 | 12,585 | - | |||||||
Revisions of previous estimates | 2,727 | -859 | 1,762 | |||||||
Purchase of reserves | 6,836 | 4,714 | 690 | |||||||
Extensions, discoveries and other additions | 12,059 | 11,064 | 1,599 | |||||||
Sale of reserves | -491 | -374 | - | |||||||
Production | -1,754 | -626 | -70 | |||||||
Total proved reserves at January 31, 2014 | 31,916 | 26,504 | 3,981 | |||||||
Proved Developed Reserves included above: | ||||||||||
31-Jan-11 | 215 | - | - | |||||||
31-Jan-12 | 538 | 202 | - | |||||||
31-Jan-13 | 4,985 | 5,906 | - | |||||||
31-Jan-14 | 13,734 | 10,930 | 1,440 | |||||||
Proved Undeveloped Reserves included above: | ||||||||||
31-Jan-11 | 1,021 | - | - | |||||||
31-Jan-12 | 827 | 472 | - | |||||||
31-Jan-13 | 7,555 | 6,679 | - | |||||||
31-Jan-14 | 18,182 | 15,574 | 2,541 | |||||||
Summary Of Status Of Proved Undeveloped Reserves | ' | |||||||||
(Mboe) | Gross Wells | Net Wells | ||||||||
Proved Undeveloped Reserves at January 31, 2011 | 1,021 | 19 | 3.0 | |||||||
Net revisions | -819 | -13 | -2.6 | |||||||
Became developed reserves in fiscal year 2012 | -52 | -3 | - | |||||||
Acquisitions | - | - | - | |||||||
Extensions and discoveries of proved reserves | 755 | 14 | 2.2 | |||||||
Proved Undeveloped Reserves at January 31, 2012 | 905 | 17 | 2.6 | |||||||
Became developed reserves in fiscal year 2013 | -363 | -9 | -1.2 | |||||||
Traded for net acres in other drill spacing units | -256 | -5 | -0.7 | |||||||
Negative revisions | -36 | -1 | -0.1 | |||||||
Positive revisions | 102 | - | - | |||||||
Acquisition of additional interests in PUD location | 172 | - | 0.3 | |||||||
Additional proved undeveloped locations | 8,144 | 57 | 18.9 | |||||||
Proved Undeveloped Reserves 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 | |||||||
Proved Undeveloped Reserves at January 31, 2014 | 23,319 | 104 | 52.5 | |||||||
Schedule Of Proved Undeveloped Drilling Locations | ' | |||||||||
Development | ||||||||||
PUD | Wells | |||||||||
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 | |||||||
104 | 104 | 52.5 | ||||||||
Schedule Of Prices Used In Calculation Of Standardized Measure | ' | |||||||||
January 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Oil price per barrel | $ | 93.09 | $ | 84.76 | $ | 89.71 | ||||
Natural gas price per Mcf | $ | 3.99 | $ | 5.23 | $ | 8.19 | ||||
Natural gas liquids price per barrel | $ | 44.10 | $ | - | $ | - | ||||
Summary Of Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves | ' | |||||||||
January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Future cash inflows | $ | 3,252,079 | $ | 1,128,676 | $ | 127,955 | ||||
Future costs: | ||||||||||
Production | -1,118,508 | -333,185 | -48,919 | |||||||
Development | -505,432 | -199,173 | -23,362 | |||||||
Future income tax expense | -364,340 | -87,313 | - | |||||||
Future net cash flows | 1,263,799 | 509,005 | 55,674 | |||||||
10% discount factor | -690,564 | -297,653 | -26,246 | |||||||
Standardized measure of discounted future net cash flows relating to proved reserves | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
Schedule Of Principle Sources Of Change In Standardized Measure | ' | |||||||||
January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Standardized measure, beginning of period | $ | 211,352 | $ | 29,428 | $ | 12,867 | ||||
Extensions and discoveries, net of future production and development costs | 333,140 | 193,107 | 28,414 | |||||||
Sales, net of production costs | -123,786 | -31,502 | -5,677 | |||||||
Previously estimated development costs incurred during the period | 66,724 | 10,368 | 2,084 | |||||||
Revision of quantity estimates | 73,598 | 15,910 | -9,536 | |||||||
Net change in prices, net of production costs | 19,173 | 2,779 | 1,001 | |||||||
Acquisition of reserves | 99,683 | 2,119 | - | |||||||
Divestiture of reserves | -7,341 | -3,273 | - | |||||||
Accretion of discount | 22,486 | 2,943 | 1,316 | |||||||
Changes in future development costs | 7,699 | 801 | -494 | |||||||
Change in income taxes | -91,161 | -13,509 | 290 | |||||||
Change in production timing and other | -38,332 | 2,181 | -837 | |||||||
Standardized measure, end of period | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
United States [Member] | ' | |||||||||
Schedule Of Direct Revenue And Cost Information Relating To Oil And Gas Exploration And Production Activities | ' | |||||||||
U.S. Oil and Natural Gas Operations | Years Ended January 31, | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Oil and natural gas revenues from production (all sold to unaffiliated parties) | $ | 160,548 | $ | 39,614 | $ | 8,136 | ||||
Less operating expenses: | ||||||||||
Production taxes | 18,006 | 4,493 | 896 | |||||||
Other lease operating expenses | 14,454 | 3,469 | 901 | |||||||
Gathering, transportation and processing | 4,302 | 151 | 22 | |||||||
Impairment of oil and natural gas properties | - | - | 6,000 | |||||||
Amortization of oil and natural gas properties | 50,991 | 13,548 | 3,022 | |||||||
Accretion of asset retirement obligation | 56 | 22 | 7 | |||||||
Operating income (loss) before income tax expense | 72,739 | 17,931 | -2,712 | |||||||
Less income tax (expense) benefit at statutory rates | -27,532 | -6,697 | 1,013 | |||||||
Results of U.S. oil and natural gas operations (excluding general corporate overhead and interest expense) | $ | 45,207 | $ | 11,234 | $ | -1,699 | ||||
Amortization rate per Boe | $ | 26.43 | $ | 27.75 | $ | 31.85 | ||||
Lease Operating Expenses (per Boe) | $ | 7.49 | $ | 7.11 | $ | 9.50 | ||||
Gathering, Transportation and Processing (per Boe) | $ | 2.23 | $ | 0.31 | $ | 0.23 | ||||
Canada [Member] | ' | |||||||||
Schedule Of Direct Revenue And Cost Information Relating To Oil And Gas Exploration And Production Activities | ' | |||||||||
Canadian Oil and Natural Gas Operations | Years Ended January 31, | |||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Oil and natural gas revenues | $ | - | $ | - | $ | - | ||||
Less operating expenses: | ||||||||||
Lease operating expenses | - | - | 641 | |||||||
Impairment of oil and natural gas properties | - | - | 4,416 | |||||||
Accretion and other asset retirement obligation expenses | 962 | 162 | 160 | |||||||
Operating income (loss) before income tax expense | -962 | -162 | -5,217 | |||||||
Income tax (expense) benefit | - | - | - | |||||||
Results of Canadian oil and natural gas operations (excluding general corporate overhead and interest expense) | $ | -962 | $ | -162 | $ | -5,217 | ||||
Supplemental_Disclosures_of_Ca1
Supplemental Disclosures of Cash Flow Information (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2014 | ||||||||||
Supplemental Disclosures of Cash Flow Information [Abstract] | ' | |||||||||
Schedule of Supplemetal Cash Flow Disclosures | ' | |||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2014 | 2013 | 2012 | |||||||
Cash paid during the period for: | ||||||||||
Interest expense | $ | 1,419 | $ | 75 | $ | - | ||||
Non-cash investing activities: | ||||||||||
Additions (reductions) to oil and natural gas properties through: | ||||||||||
Increased (decreased) accrued liabilities and decreased prepaid well costs | $ | 30,785 | $ | 36,654 | $ | 13,181 | ||||
Capitalized stock based compensation | $ | 1,391 | $ | 949 | $ | 211 | ||||
Issuance of common stock | $ | 3,827 | $ | 1,204 | $ | 11,780 | ||||
Change in asset retirement obligations | $ | 673 | $ | 1,869 | $ | 53 | ||||
Capitalized interest | $ | 809 | $ | - | $ | - | ||||
Purchase minority interest in RockPile | $ | - | $ | 12,349 | $ | - | ||||
Acquisition of oilfield services equipment through notes payable and liabilities | $ | 1,990 | $ | - | $ | - | ||||
Quarterly_Financial_Informatio1
Quarterly Financial Information (Tables) | 12 Months Ended | ||||||||||||||||||
Jan. 31, 2014 | |||||||||||||||||||
Quarterly Financial Information [Abstract] | ' | ||||||||||||||||||
Schedule Of Quarterly Financial Information | ' | ||||||||||||||||||
For the Year Ended January 31, 2014 | |||||||||||||||||||
(in thousands) | First Quarter | Second Quarter | Third Quarter* (restated) | Fourth Quarter | |||||||||||||||
Total revenue | $ | 34,294 | $ | 50,394 | $ | 88,549 | $ | 85,510 | |||||||||||
Income from operations | $ | 4,426 | $ | 13,077 | $ | 17,188 | $ | 11,975 | |||||||||||
Net income | $ | 5,211 | $ | 6,799 | $ | 47,221 | $ | 14,249 | |||||||||||
Net income attributable to common stockholders | $ | 5,211 | $ | 6,799 | $ | 47,221 | $ | 14,249 | |||||||||||
Net income per common share - basic | $ | 0.10 | $ | 0.12 | $ | 0.60 | $ | 0.17 | |||||||||||
Net income per common share - diluted | $ | 0.10 | $ | 0.12 | $ | 0.50 | $ | 0.15 | |||||||||||
For the Year Ended January 31, 2013 | |||||||||||||||||||
(in thousands) | First Quarter** | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||||
Total revenue | $ | 5,241 | $ | 10,132 | $ | 21,300 | $ | 24,028 | |||||||||||
Loss from operations | $ | -3,336 | $ | -1,389 | $ | -617 | $ | -2,828 | |||||||||||
Net loss | $ | -3,324 | $ | -1,335 | $ | -672 | $ | -9,153 | |||||||||||
Net loss attributable to common stockholders | $ | -3,028 | $ | -1,079 | $ | -598 | $ | -9,055 | |||||||||||
Net loss per common share - basic and diluted | $ | -0.07 | $ | -0.02 | $ | -0.01 | $ | -0.2 | |||||||||||
* Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | |||||||||||||||||||
** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Triangle’s April 30, 2012 Quarterly Report on Form 10-Q. | |||||||||||||||||||
Schedule Of Expected Error Correction | ' | ||||||||||||||||||
Condensed Consolidated Balance Sheets | |||||||||||||||||||
As of October 31, 2013 | |||||||||||||||||||
As | Adjustments | As Restated | |||||||||||||||||
(in thousands, except per share data) Selected Financial Statement Caption | Previously Reported | ||||||||||||||||||
Equity investment | $ | 22,395 | $ | 35,832 | $ | 58,227 | |||||||||||||
Total assets | 889,088 | 35,832 | 924,920 | ||||||||||||||||
Deferred tax liability | - | 5,969 | 5,969 | ||||||||||||||||
Total liabilities | 412,215 | 5,969 | 418,184 | ||||||||||||||||
Accumulated deficit | -92,651 | 29,863 | -62,788 | ||||||||||||||||
Total stockholders' equity | 476,873 | 29,863 | 506,736 | ||||||||||||||||
Total liabilities and stockholders' equity | $ | 889,088 | $ | 35,832 | $ | 924,920 | |||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||||||||||||||||
For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||
31-Oct-13 | 31-Oct-13 | ||||||||||||||||||
As | Adjustments | As Restated | As | Adjustments | As Restated | ||||||||||||||
(in thousands, except per share data) | Previously Reported | Previously Reported | |||||||||||||||||
Selected Financial Statement Caption | |||||||||||||||||||
Gain on equity investment derivative | $ | - | $ | 35,832 | $ | 35,832 | $ | - | $ | 35,832 | $ | 35,832 | |||||||
Total other income (expense) | 170 | 35,832 | 36,002 | -5,323 | 35,832 | 30,509 | |||||||||||||
Net income (loss) before income taxes | 17,358 | 35,832 | 53,190 | 29,369 | 35,832 | 65,201 | |||||||||||||
Income tax provision | - | -5,969 | -5,969 | - | -5,969 | -5,969 | |||||||||||||
Net income (loss) | 17,358 | 47,221 | 29,369 | 29,863 | 59,232 | ||||||||||||||
Net income (loss) attributable to common stockholders | 17,358 | 29,863 | 47,221 | 29,369 | 29,863 | 59,232 | |||||||||||||
Net income (loss) per common share outstanding: | |||||||||||||||||||
Basic | $ | 0.22 | $ | 0.38 | $ | 0.60 | $ | 0.47 | $ | 0.47 | $ | 0.94 | |||||||
Diluted | $ | 0.20 | $ | 0.30 | $ | 0.50 | $ | 0.43 | $ | 0.35 | $ | 0.78 | |||||||
Description_Of_Business_Narrat
Description Of Business (Narrative) (Details) | 12 Months Ended |
Jan. 31, 2014 | |
item | |
Description Of Business [Abstract] | ' |
Number of major focus lines of business | 3 |
Basis_Of_Presentation_Details
Basis Of Presentation (Details) | Jan. 31, 2014 |
Minimum [Member] | ' |
Basis Of Presentation [Line Items] | ' |
Equity method ownership percentage | 20.00% |
Maximum [Member] | ' |
Basis Of Presentation [Line Items] | ' |
Equity method ownership percentage | 50.00% |
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
segment | ||
Accounting Policies [Line Items] | ' | ' |
Convertible note, interest rate | 5.00% | 5.00% |
Allowance for doubtful accounts | $0 | $0 |
Number of days invoice is due billed to customers | '30 days | ' |
Gain (loss) recognized on disposition | 0 | ' |
Total proved reserves categorized as proved undeveloped | 58.00% | ' |
Contingency accrual | 0 | ' |
Oil and gas imbalance | 0 | ' |
Number of reportable segments | 2 | ' |
Pressure Pumping And Related Services [Member] | ' | ' |
Accounting Policies [Line Items] | ' | ' |
Contract obligations | $0 | ' |
Summary_Of_Significant_Account4
Summary Of Significant Accounting Policies (Property And Equipment Useful Lives) (Details) | 12 Months Ended |
Jan. 31, 2014 | |
Oilfield Service Equipment [Member] | ' |
Estimated useful life | '5 years |
Vehicles [Member] | ' |
Estimated useful life | '5 years |
Leasehold Improvements [Member] | ' |
Estimated useful life | '10 years |
Office Equipment [Member] | ' |
Estimated useful life | '3 years |
Minimum [Member] | Building And Improvements [Member] | ' |
Estimated useful life | '10 years |
Minimum [Member] | Software And Computers [Member] | ' |
Estimated useful life | '3 years |
Maximum [Member] | Building And Improvements [Member] | ' |
Estimated useful life | '20 years |
Maximum [Member] | Software And Computers [Member] | ' |
Estimated useful life | '5 years |
Segment_Reporting_Narrative_De
Segment Reporting (Narrative) (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
segment | ||
Segment Reporting [Abstract] | ' | ' |
Number of reportable segments | 2 | ' |
Deferred income | $4.40 | $1.80 |
Segment_Reporting_Schedule_Of_
Segment Reporting (Schedule Of Segment Reporting) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||||||
Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | ' | $160,548,000 | $39,614,000 | $8,136,000 | ||||||
Oilfield services for third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | 98,199,000 | 20,747,000 | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 340,000 | ' | ||||||
Total revenues | 85,510,000 | 88,549,000 | [1] | 50,394,000 | 34,294,000 | 24,028,000 | 21,300,000 | 10,132,000 | 5,241,000 | [2] | ' | 258,747,000 | 60,701,000 | 8,136,000 | ||||
EXPENSES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Production taxes and other lease operating | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,460,000 | 8,058,000 | ' | ||||||
Gathering, transportation and processing | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,302,000 | 150,000 | 22,000 | ||||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | ' | 57,048,000 | 15,081,000 | 3,114,000 | ||||||
Accretion and other asset retirement obligation expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,018,000 | 184,000 | 167,000 | ||||||
Cost of oilfield services | ' | ' | ' | ' | ' | ' | ' | ' | ' | 82,327,000 | 16,606,000 | ' | ||||||
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,830,000 | 6,466,000 | 7,567,000 | ||||||
Other general and administrative | ' | ' | ' | ' | ' | ' | ' | ' | ' | 27,096,000 | 22,326,000 | ' | ||||||
Total operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 212,081,000 | 68,871,000 | 33,111,000 | ||||||
INCOME (LOSS) FROM OPERATIONS | 11,975,000 | 17,188,000 | [1] | 13,077,000 | 4,426,000 | -2,828,000 | -617,000 | -1,389,000 | -3,336,000 | [2] | ' | 46,666,000 | -8,170,000 | -24,975,000 | ||||
Other income (expense), net | ' | 36,002,000 | ' | ' | ' | ' | ' | ' | 30,509,000 | 34,755,000 | -6,314,000 | 552,000 | ||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | ' | 53,190,000 | ' | ' | ' | ' | ' | ' | 65,201,000 | 81,421,000 | -14,484,000 | -24,423,000 | ||||||
Total assets | 1,027,584,000 | 924,920,000 | ' | ' | 428,321,000 | ' | ' | ' | 924,920,000 | 1,027,584,000 | 428,321,000 | ' | ||||||
Net oil and natural gas properties | 682,787,000 | ' | ' | ' | 298,757,000 | ' | ' | ' | ' | 682,787,000 | 298,757,000 | ' | ||||||
Oilfield services equipment, net | 46,586,000 | ' | ' | ' | 18,878,000 | ' | ' | ' | ' | 46,586,000 | 18,878,000 | ' | ||||||
Other property and equipment, net | 24,507,000 | ' | ' | ' | 15,779,000 | ' | ' | ' | ' | 24,507,000 | 15,779,000 | ' | ||||||
Total liabilities | 504,422,000 | 418,184,000 | ' | ' | 226,699,000 | ' | ' | ' | 418,184,000 | 504,422,000 | 226,699,000 | ' | ||||||
Eliminations And Other [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Oilfield services for third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4,407,000 | -1,788,000 | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,192,000 | -883,000 | ' | ||||||
Total revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | -96,618,000 | -37,343,000 | ' | ||||||
EXPENSES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3,542,000 | -1,732,000 | ' | ||||||
Cost of oilfield services | ' | ' | ' | ' | ' | ' | ' | ' | ' | -60,012,000 | -22,928,000 | ' | ||||||
Total operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | -63,554,000 | -24,660,000 | ' | ||||||
INCOME (LOSS) FROM OPERATIONS | ' | ' | ' | ' | ' | ' | ' | ' | ' | -33,064,000 | -12,683,000 | ' | ||||||
Other income (expense), net | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,184,000 | ' | ' | ||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | ' | ' | ' | ' | ' | ' | ' | ' | ' | -35,248,000 | -12,683,000 | ' | ||||||
Total assets | -97,072,000 | ' | ' | ' | -13,445,000 | ' | ' | ' | ' | -97,072,000 | -13,445,000 | ' | ||||||
Net oil and natural gas properties | -47,931,000 | ' | ' | ' | -11,800,000 | ' | ' | ' | ' | -47,931,000 | -11,800,000 | ' | ||||||
Total liabilities | -20,141,000 | ' | ' | ' | -1,644,000 | ' | ' | ' | ' | -20,141,000 | -1,644,000 | ' | ||||||
Intersegment Revenues [Member] | Eliminations And Other [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | -91,019,000 | -34,672,000 | ' | ||||||
Exploration and Production [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | ' | 160,548,000 | 39,614,000 | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 248,000 | ' | ||||||
Total revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 160,548,000 | 39,862,000 | ' | ||||||
EXPENSES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Production taxes and other lease operating | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,460,000 | 8,058,000 | ' | ||||||
Gathering, transportation and processing | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,302,000 | 150,000 | ' | ||||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | ' | 51,065,000 | 13,578,000 | ' | ||||||
Accretion and other asset retirement obligation expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,018,000 | 184,000 | ' | ||||||
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,127,000 | 2,507,000 | ' | ||||||
Other general and administrative | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,777,000 | 6,838,000 | ' | ||||||
Total operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 97,749,000 | 31,315,000 | ' | ||||||
INCOME (LOSS) FROM OPERATIONS | ' | ' | ' | ' | ' | ' | ' | ' | ' | 62,799,000 | 8,547,000 | ' | ||||||
Other income (expense), net | ' | ' | ' | ' | ' | ' | ' | ' | ' | 125,000 | -6,318,000 | ' | ||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | ' | ' | ' | ' | ' | ' | ' | ' | ' | 62,924,000 | 2,229,000 | ' | ||||||
Total assets | 821,042,000 | ' | ' | ' | 362,878,000 | ' | ' | ' | ' | 821,042,000 | 362,878,000 | ' | ||||||
Net oil and natural gas properties | 730,718,000 | ' | ' | ' | 310,557,000 | ' | ' | ' | ' | 730,718,000 | 310,557,000 | ' | ||||||
Other property and equipment, net | 1,594,000 | ' | ' | ' | 1,597,000 | ' | ' | ' | ' | 1,594,000 | 1,597,000 | ' | ||||||
Total liabilities | 318,875,000 | ' | ' | ' | 91,134,000 | ' | ' | ' | ' | 318,875,000 | 91,134,000 | ' | ||||||
Oilfield Services [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Oilfield services for third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | 102,606,000 | 22,535,000 | ' | ||||||
Total revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 193,625,000 | 57,207,000 | ' | ||||||
EXPENSES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,905,000 | 2,857,000 | ' | ||||||
Cost of oilfield services | ' | ' | ' | ' | ' | ' | ' | ' | ' | 142,339,000 | 39,534,000 | ' | ||||||
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 590,000 | 617,000 | ' | ||||||
Other general and administrative | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,116,000 | 11,130,000 | ' | ||||||
Total operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 162,950,000 | 54,138,000 | ' | ||||||
INCOME (LOSS) FROM OPERATIONS | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,675,000 | 3,069,000 | ' | ||||||
Other income (expense), net | ' | ' | ' | ' | ' | ' | ' | ' | ' | -991,000 | 4,000 | ' | ||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29,684,000 | 3,073,000 | ' | ||||||
Total assets | 126,114,000 | ' | ' | ' | 38,668,000 | ' | ' | ' | ' | 126,114,000 | 38,668,000 | ' | ||||||
Oilfield services equipment, net | 46,586,000 | ' | ' | ' | 18,878,000 | ' | ' | ' | ' | 46,586,000 | 18,878,000 | ' | ||||||
Other property and equipment, net | 18,912,000 | ' | ' | ' | 12,443,000 | ' | ' | ' | ' | 18,912,000 | 12,443,000 | ' | ||||||
Total liabilities | 64,017,000 | ' | ' | ' | 11,845,000 | ' | ' | ' | ' | 64,017,000 | 11,845,000 | ' | ||||||
Oilfield Services [Member] | Intersegment Revenues [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | 91,019,000 | 34,672,000 | ' | ||||||
Corporate And Other [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
REVENUES | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,192,000 | [3] | 975,000 | [3] | ' | ||||
Total revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,192,000 | [3] | 975,000 | [3] | ' | ||||
EXPENSES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | ' | 620,000 | [3] | 378,000 | [3] | ' | ||||
Stock-based compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,113,000 | [3] | 3,342,000 | [3] | ' | ||||
Other general and administrative | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,203,000 | [3] | 4,358,000 | [3] | ' | ||||
Total operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,936,000 | [3] | 8,078,000 | [3] | ' | ||||
INCOME (LOSS) FROM OPERATIONS | ' | ' | ' | ' | ' | ' | ' | ' | ' | -13,744,000 | [3] | -7,103,000 | [3] | ' | ||||
Other income (expense), net | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,805,000 | [3] | ' | ' | |||||
NET INCOME (LOSS) BEFORE INCOME TAXES | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,061,000 | [3] | -7,103,000 | [3] | ' | ||||
Total assets | 177,500,000 | [3] | ' | ' | ' | 40,220,000 | [3] | ' | ' | ' | ' | 177,500,000 | [3] | 40,220,000 | [3] | ' | ||
Other property and equipment, net | 4,001,000 | [3] | ' | ' | ' | 1,739,000 | [3] | ' | ' | ' | ' | 4,001,000 | [3] | 1,739,000 | [3] | ' | ||
Total liabilities | $141,671,000 | [3] | ' | ' | ' | $125,364,000 | [3] | ' | ' | ' | ' | $141,671,000 | [3] | $125,364,000 | [3] | ' | ||
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | |||||||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. | |||||||||||||||||
[3] | Corporate and Other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or oilfield services segments. These subsidiaries have limited activity. |
Oil_And_Natural_Gas_Properties2
Oil And Natural Gas Properties (Narrative) (Details) (USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' | ' | ' |
Total consideration to purchase oil and gas properties | $434,400,000 | $168,400,000 | ' |
Consideration transferred cash and working capital for oil and gas properties | 432,000,000 | 167,200,000 | ' |
Issuance of common stock for oil and gas properties | 2,400,000 | 1,200,000 | ' |
Capitalized internal land and geology department costs | 3,700,000 | 2,000,000 | ' |
Costs not being amortized | 121,400,000 | ' | ' |
Duration for Unproved property costs to be reclassified to proved property costs | '5 years | ' | ' |
Depreciation and amortization expense for oil and gas properties | 50,100,000 | 13,500,000 | 3,000,000 |
Depreciation and amortization expense for oil and gas properties per BOE | 26.43 | 27.75 | 31.85 |
Unproved Leaseholds [Member] | ' | ' | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' | ' | ' |
Total consideration to purchase oil and gas properties | 121,600,000 | 20,100,000 | ' |
Unevaluated Wells In Progress [Member] | ' | ' | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' | ' | ' |
Costs not being amortized | $8,900,000 | ' | ' |
Oil_And_Natural_Gas_Properties3
Oil And Natural Gas Properties (Schedule Of Aggregate Costs Incurred) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
Property And Equipment [Abstract] | ' | ' |
Proved properties | $629,051 | $220,894 |
Unproved properties and properties under development, not being amortized | 121,393 | 94,529 |
Oil and natural gas properties total | 750,444 | 315,423 |
Less accumulated amortization | -67,657 | -16,666 |
Net oil and natural gas properties | 682,787 | 298,757 |
Capitalized interest | $809 | ' |
Oil_And_Natural_Gas_Properties4
Oil And Natural Gas Properties (Schedule Of Capitalized Costs Incurred) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Property And Equipment [Abstract] | ' | ' | ' |
Proved | $80,201 | $623 | ' |
Unproved | 41,377 | 20,570 | 87,226 |
Exploration | 96,731 | 55,583 | 40,728 |
Development | 216,046 | 91,666 | 4,706 |
Oil and natural gas expenditures | 434,355 | 168,442 | 132,660 |
Asset retirement obligation, net | 676 | 370 | 3 |
Total costs incurred | $435,031 | $168,812 | $132,663 |
Oil_And_Natural_Gas_Properties5
Oil And Natural Gas Properties (Costs Not Being Amortized) (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Jan. 31, 2014 |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | $121,400 |
Not Yet Being Amortized [Member] | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | 121,393 |
Acquisition | 108,147 |
Exploration | 10,225 |
Capitalized Interest | 3,021 |
Incurred In Fiscal Year 2014 [Member] | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | 54,623 |
Acquisition | 41,377 |
Exploration | 10,225 |
Capitalized Interest | 3,021 |
Incurred In Fiscal Year 2013 [Member] | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | 15,618 |
Acquisition | 15,618 |
Incurred In Fiscal Year 2012 [Member] | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | 44,620 |
Acquisition | 44,620 |
Incurred In Prior Years [Member] | ' |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ' |
Total | 6,532 |
Acquisition | $6,532 |
Acquisitions_Narrative_Details
Acquisitions (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | 1 Months Ended | |||||||||||||
Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Aug. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Aug. 28, 2013 | Jan. 31, 2014 | Oct. 31, 2013 | |||
Kodiak Oil And Natural Gas Property [Member] | Kodiak Oil And Natural Gas Property [Member] | Kodiak Oil And Natural Gas Property [Member] | Kodiak Oil And Natural Gas Property [Member] | Team Well Service, Inc. [Member] | Team Well Service, Inc. [Member] | ||||||||||||||
acre | acre | Rockpile [Member] | |||||||||||||||||
item | |||||||||||||||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Date of acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28-Aug-13 | ' | ' | 16-Oct-13 | ' | ||
Number of acres purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,600 | ' | ' | ||
Cash paid for acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $83,805,000 | ' | ' | ' | $6,800,000 | ||
Revenues | 85,510,000 | 88,549,000 | [1] | 50,394,000 | 34,294,000 | 24,028,000 | 21,300,000 | 10,132,000 | 5,241,000 | [2] | 258,747,000 | 60,701,000 | 8,136,000 | ' | 8,200,000 | ' | ' | ' | ' |
Acquisition transaction costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | ' | ' | ' | ' | ||
Total consideration for acquisition | ' | ' | ' | ' | ' | ' | ' | ' | 434,400,000 | 168,400,000 | ' | ' | 83,805,000 | ' | ' | ' | ' | ||
Number of leasehold interest acres that could be exchanged | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600 | ' | ' | ' | ' | ' | ||
Pro forma depreciation, amortization and accretion expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 2,000,000 | ' | ' | ' | ||
Unsecured note payable | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 800,000 | ||
Earn-out payments | ' | ' | ' | ' | ' | ' | ' | ' | 1,139,000 | ' | ' | ' | ' | ' | ' | ' | 1,500,000 | ||
Percentage of liabilty accrued for assumed earn out payments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ||
Debt instrument, face amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ||
Debt instrument, stated interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | ||
Number of annual earn out payments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ||
Earn-out payments equal to percentage of revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ||
Maximum annual earn-out payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | ||
Maximum revenue earn out payment is based | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ||
Identifiable intangible assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000 | ||
Goodwill | $1,680,000 | ' | ' | ' | ' | ' | ' | ' | $1,680,000 | ' | ' | ' | ' | ' | ' | ' | $1,700,000 | ||
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | ||||||||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Acquisitions_Schedule_Of_Purch
Acquisitions (Schedule Of Purchase Price Allocation) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
Property, Plant and Equipment [Line Items] | ' | ' |
Total consideration given | $434,400 | $168,400 |
Kodiak Oil And Natural Gas Property [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Cash | 83,805 | ' |
Total consideration given | 83,805 | ' |
Proved properties | 50,200 | ' |
Unproved properties | 32,976 | ' |
Total oil and natural gas properties | 83,176 | ' |
Accounts payable | 761 | ' |
Asset retirement obligation assumed | -132 | ' |
Fair value of net assets acquired | $83,805 | ' |
Acquisitions_Schedule_of_Profo
Acquisitions (Schedule of Proforma) (Details) (Kodiak Oil And Natural Gas Property [Member], USD $) | 12 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
Kodiak Oil And Natural Gas Property [Member] | ' | ' |
Business Acquisition [Line Items] | ' | ' |
Operating revenue | $272,548 | $63,167 |
Net income (loss) | $80,086 | ($13,903) |
Earnings (loss) per common share, basic | $1.07 | ($0.25) |
Earnings (loss) per common share, diluted | $0.93 | ($0.25) |
Weighted average common shares outstanding, basic | 75,046,511 | 55,794,054 |
Weighted average common shares outstanding, diluted | 91,025,500 | 55,794,054 |
Asset_Retirement_Obligations_N
Asset Retirement Obligations (Narrative) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Asset Retirement Obligations [Line Items] | ' | ' | ' |
Accretion and other asset retirement obligation expenses | $1,018 | $184 | $167 |
Asset retirement obligations, current | 3,333 | 2,949 | ' |
Reclamation Of Man Made Ponds And Plugging And Abandonment Of Well Bores [Member] | ' | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' | ' |
Asset retirement obligations, current | 2,000 | ' | ' |
Plug And Abandon Vertical Wells [Member] | ' | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' | ' |
Asset retirement obligations, current | 1,300 | ' | ' |
Canada [Member] | ' | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' | ' |
Asset retirement obligations, current | 1,972 | 1,449 | ' |
Canada [Member] | Internal Engineering Re-assessment [Member] | ' | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' | ' |
Accretion and other asset retirement obligation expenses | $1,000 | ' | ' |
Asset_Retirement_Obligations_S
Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 |
Asset Retirement Obligations [Line Items] | ' | ' |
Balance, beginning of period | $3,422 | $1,623 |
Liabilities incurred | 944 | 1,769 |
Revision of estimates | 774 | 147 |
Sales of assets | -83 | -48 |
Liabilities settled | -484 | -253 |
Accretion | 56 | 184 |
Balance, end of period | 4,629 | 3,422 |
Less current portion of obligations | -3,333 | -2,949 |
Long-term asset retirement obligations | 1,296 | 473 |
United States [Member] | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' |
Balance, beginning of period | 1,973 | 83 |
Liabilities incurred | 944 | 1,769 |
Revision of estimates | -188 | 147 |
Sales of assets | -83 | -48 |
Liabilities settled | -132 | ' |
Accretion | 56 | 22 |
Balance, end of period | 2,570 | 1,973 |
Less current portion of obligations | -1,361 | -1,500 |
Long-term asset retirement obligations | 1,209 | 473 |
Canada [Member] | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' |
Balance, beginning of period | 1,449 | 1,540 |
Revision of estimates | 962 | ' |
Liabilities settled | -352 | -253 |
Accretion | ' | 162 |
Balance, end of period | 2,059 | 1,449 |
Less current portion of obligations | -1,972 | -1,449 |
Long-term asset retirement obligations | $87 | ' |
Property_And_Equipment_Narrati
Property And Equipment (Narrative) (Details) (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment [Line Items] | ' | ' |
Depreciable asset, gross | $82,559 | $32,010 |
Depreciable assets, net | 69,760 | 28,671 |
Oilfield Service Equipment [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Depreciable asset, gross | 56,355 | 22,255 |
Depreciable assets, net | $46,600 | ' |
Property_And_Equipment_Propert
Property And Equipment (Property And Equipment) (Details) (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | $82,559 | $32,010 |
Accumulated depreciation | -12,799 | -3,339 |
Depreciable assets, net | 69,760 | 28,671 |
Assets not placed in service | 1,333 | 5,986 |
Total oilfield service equipment and other property and equipment, net | 71,093 | 34,657 |
Land [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | 2,512 | 2,520 |
Building And Leasehold Improvements [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | 18,388 | 4,805 |
Oilfield Service Equipment [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | 56,355 | 22,255 |
Depreciable assets, net | 46,600 | ' |
Vehicles [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | 2,288 | 1,240 |
Software, Computers And Office Equipment [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Total Depreciable Assets | $3,016 | $1,190 |
Intangible_Assets_And_Goodwill1
Intangible Assets And Goodwill (Details) (USD $) | 12 Months Ended | |
Jan. 31, 2014 | Jan. 31, 2013 | |
Finite-Lived Intangible Assets [Line Items] | ' | ' |
Intangible assets | $3,862,000 | ' |
Goodwill | 1,680,000 | ' |
Intangible assets and goodwill | ' | 0 |
Amortization expense | 100,000 | 0 |
Trade Names [Member] | ' | ' |
Finite-Lived Intangible Assets [Line Items] | ' | ' |
Intangible assets | 1,000,000 | ' |
Useful lives | '5 years | ' |
Developed Technology [Member] | ' | ' |
Finite-Lived Intangible Assets [Line Items] | ' | ' |
Intangible assets | 600,000 | ' |
Useful lives | '10 years | ' |
Non-competition Agreement [Member] | ' | ' |
Finite-Lived Intangible Assets [Line Items] | ' | ' |
Intangible assets | 100,000 | ' |
Useful lives | '5 years | ' |
Customer Relationships [Member] | ' | ' |
Finite-Lived Intangible Assets [Line Items] | ' | ' |
Intangible assets | $2,200,000 | ' |
Useful lives | '10 years | ' |
Fair_Value_Measurements_Narrat
Fair Value Measurements (Narrative) (Details) (USD $) | Jan. 31, 2014 | Sep. 30, 2013 | Aug. 28, 2013 | Aug. 02, 2013 | Jul. 31, 2012 |
In Millions, except Per Share data, unless otherwise specified | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' |
Common stock closing price | $7.61 | $6.25 | $7.20 | $7.50 | $5.59 |
Carrying Amount [Member] | ' | ' | ' | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' |
Credit facility | $183 | ' | ' | ' | ' |
Convertible note | 129.3 | ' | ' | ' | ' |
Estimated Fair Value [Member] | ' | ' | ' | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' |
Convertible note | $169.20 | ' | ' | ' | ' |
Fair_Value_Measurements_Schedu
Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) (USD $) | 12 Months Ended |
Jan. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' |
Derivative assets | $41,881,000 |
Earn-out liability | -1,139,000 |
Note payable | -9,002,000 |
Fair Value, Inputs, Level 2 [Member] | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' |
Derivative assets | 2,147,000 |
Earn-out liability | -1,139,000 |
Note payable | -9,002,000 |
Fair Value, Inputs, Level 3 [Member] | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' |
Derivative assets | $39,734,000 |
Fair_Value_Measurements_Rollfo
Fair Value Measurements (Rollforward Of Level 3 Financial Liabilities) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | |
Interest paid in-kind | $6,267 | $2,738 | |
Fair Value, Inputs, Level 3 [Member] | Convertible Notes [Member] | ' | ' | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | |
Beginning balance | -132,900 | ' | |
Sale of Convertible Notes | ' | -120,000 | |
Interest paid in-kind | -6,267 | -3,023 | |
Total net unrecognized gain (loss) | -30,003 | -9,877 | |
Ending balance | -169,170 | -132,900 | |
Fair Value, Inputs, Level 3 [Member] | Class A Triggering Units [Member] | ' | ' | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | |
Initial recognition of equity investment derivative assets | 38,091 | ' | |
Ending balance | 38,091 | ' | |
Fair Value, Inputs, Level 3 [Member] | Warrants [Member] | ' | ' | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | |
Initial recognition of equity investment derivative assets | 1,643 | [1] | ' |
Ending balance | $1,643 | [1] | ' |
[1] | Includes Class A Triggering Units, and Series 1 and Series 2 Warrants. |
Equity_Investment_Details
Equity Investment (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||||
Jan. 31, 2014 | Jan. 31, 2013 | Oct. 31, 2013 | Sep. 12, 2013 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | Sep. 30, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | |
Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | ||||
FREIF Caliber Holdings [Member] | FREIF Caliber Holdings [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Class A Units [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Series 5 Warrant $32.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | Class A Trigger Unit, Class A Trigger Unit Warrants And Warrants [Member] | |||||
Forecast [Member] | Forecast [Member] | Forecast [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | FREIF Caliber Holdings [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | ||||||||||
Forecast [Member] | Forecast [Member] | Forecast [Member] | |||||||||||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contribution to joint venture | $18,000,000 | ' | ' | ' | $70,000,000 | $80,000,000 | $30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Units received | ' | ' | ' | ' | 7,000,000 | 8,000,000 | 3,000,000 | ' | ' | ' | 4,000,000 | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Trigger Units received | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments Class A trigger units converted | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' |
Equity method investment, Class A units held | ' | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method ownership percentage | ' | ' | ' | 30.00% | ' | 68.00% | ' | 30.00% | ' | ' | 32.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investment | 68,536,000 | 11,768,000 | 58,227,000 | ' | ' | ' | ' | 68,536,000 | 11,768,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss from equity investment | ' | -283,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income (loss) from equity method investments before adjustment for intra-company profits and losses | ' | ' | ' | ' | ' | ' | ' | 2,184,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investment cash distribution | 3,150,000 | ' | ' | ' | ' | ' | ' | 3,150,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, warrants received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 4,000,000 | 1,600,000 | 2,400,000 | 2,400,000 | 1,600,000 | 1,600,000 | ' | 5,000,000 | 3,000,000 | 3,000,000 | 3,000,000 | 2,000,000 | 2,000,000 | ' |
Equity method investments, warrant excercise price | ' | ' | ' | ' | ' | ' | $14.69 | ' | ' | ' | ' | ' | $14.69 | $14.69 | $14.69 | $24 | $24 | $14.69 | $14.69 | ' | $32 | $24 | $24 | $24 | $30 | $30 | ' |
Increase in equity method investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $18,000,000 | ' | $926,000 | ' | ' | $254,000 | ' | $234,000 | ' | ' | ' | ' | $207,000 | ' | $22,000 | $39,700,000 |
Equity_Investment_Schedule_Of_
Equity Investment (Schedule Of Equity Investment In Caliber) (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2014 | Oct. 31, 2013 | Oct. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | Sep. 30, 2013 | Jan. 31, 2014 |
Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | |||
Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Class A Units [Member] | Class A Triggering Units [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | |||
Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investment, Beginning balance | $11,768 | $58,227 | ' | $11,768 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Units received | ' | ' | 3,000,000 | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A units exercise price | ' | ' | ' | ' | $10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Trigger Units received | ' | ' | 4,000,000 | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, warrants received | ' | ' | ' | ' | ' | ' | 1,600,000 | 1,600,000 | 4,000,000 | 4,000,000 | 2,400,000 | 2,400,000 | 3,000,000 | 3,000,000 | 3,000,000 | 2,000,000 | 2,000,000 |
Equity method investments, warrant excercise price | ' | ' | $14.69 | ' | ' | ' | $14.69 | $14.69 | $14.69 | $14.69 | $24 | $24 | $24 | $24 | $24 | $30 | $30 |
Increase in equity method investment | ' | ' | ' | ' | 18,000 | 38,091 | ' | 234 | ' | 926 | ' | 254 | ' | ' | 207 | ' | 22 |
Distributions | -3,150 | ' | ' | -3,150 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investment share of net income for the year | ' | ' | ' | 2,184 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investment, Ending balance | $68,536 | $58,227 | ' | $68,536 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Investment_In_Marketable_Secur1
Investment In Marketable Securities (Details) (USD $) | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | |
acre | acre | ||
Investment In Marketable Securities [Abstract] | ' | ' | ' |
Number of securities received for sale of oil and natural gas leases | 851,315 | ' | 851,315 |
Number of acres sold in oil and gas leases | 1,590 | ' | 1,590 |
Value of shares received for oil and gas leases | $4,900,000 | ' | ' |
Proceeds from available for sale securities | ' | 6,105,000 | ' |
Unrealized gain on available for sale securities | ' | $200,000 | $1,100,000 |
Longterm_Debt_Schedule_Of_Debt
Long-term Debt (Schedule Of Debt) (Details) (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ' | ' |
Long-term portion of credit facilities | $196,065 | $25,000 |
5% Convertible Note | 129,290 | 123,023 |
Total long-term debt | 334,357 | 148,023 |
Total current portion of debt | 8,851 | ' |
Total debt | 343,208 | 148,023 |
TUSA [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Credit facility | 183,000 | 25,000 |
Rockpile [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Credit facility | 21,515 | ' |
Less current portion | -8,450 | ' |
Notes payable | 9,403 | ' |
Total current portion of notes payable | ($401) | ' |
Longterm_Debt_TUSA_Credit_Faci
Long-term Debt (TUSA Credit Facility Narrative) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Jan. 31, 2014 | Jan. 13, 2014 | Jan. 12, 2014 |
item | |||
Long-Term Debt [Abstract] | ' | ' | ' |
Credit facility, maximum borrowing capacity | ' | $320 | $275 |
Loan hedge percentage of anticipated production | 85.00% | ' | ' |
Credit facility, maturity date | 16-Oct-18 | ' | ' |
Credit facility, margin on dollar amount based on usage | 0.25% | ' | ' |
Number of new lenders under credit facility | 3 | ' | ' |
Credit facility, amount outstanding | $183 | ' | ' |
Credit Facility, term | '5 years | ' | ' |
Credit facility, ratio of current assets to current liabilities defined by credit facility | 1 | ' | ' |
Credit facility, ratio of consolidated debt to consolidated EBITDAX | 4 | ' | ' |
Longterm_Debt_Convertible_Note
Long-term Debt (Convertible Note Narrative) (Details) (USD $) | 1 Months Ended | |||
In Millions, except Per Share data, unless otherwise specified | Jul. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Nov. 16, 2012 |
Long-Term Debt [Abstract] | ' | ' | ' | ' |
Convertible note, conversion ratio | 1 | ' | ' | ' |
Convertible note, conversion price | ' | ' | ' | $8 |
Convertible note, interest rate | ' | 5.00% | 5.00% | ' |
Accrued interest | ' | $9.30 | ' | ' |
Longterm_Debt_Rockpile_Debt_Na
Long-term Debt (Rockpile Debt Narrative) (Details) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||
Jan. 31, 2014 | Jan. 13, 2014 | Jan. 12, 2014 | Jan. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Mar. 25, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Mar. 25, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Nov. 18, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Feb. 15, 2013 | Jan. 31, 2014 | Dec. 11, 2013 | Feb. 15, 2013 | Jan. 31, 2014 | Dec. 11, 2013 | Jan. 31, 2014 | Dec. 11, 2013 | Nov. 20, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Feb. 15, 2013 | Jan. 31, 2014 | Oct. 16, 2013 | |
Federal Funds Rate [Member] | Letter of Credit [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Equipment Term Loan Facility [Member] | Equipment Term Loan Facility [Member] | Capex Term Loan Facility [Member] | Revolving Credit Facility [Member] | Construction Loan Residential Units [Member] | Construction Loan Residential Units [Member] | Construction Loan Residential Units [Member] | Construction Loan Administrative And Maintenance Building [Member] | Construction Loan Administrative And Maintenance Building [Member] | Construction Loan Administrative And Maintenance Building [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Notes Payable to Banks [Member] | Notes Payable to Banks [Member] | Notes Payable, Other Payables [Member] | Notes Payable, Other Payables [Member] | |||||
Eurodollar Rate Plus 1% [Member] | Letter of Credit [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | RockPile Notes Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Notes Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Mortgage Payable to Dacotah Bank [Member] | RockPile Hauch Apartments Mortgage [Member] | RockPile Hauch Apartments Mortgage [Member] | RockPile Notes Payable to Dacotah Bank [Member] | RockPile Notes Payable to Dacotah Bank [Member] | RockPile Notes Payable to Sellers of Team Well Service, Inc. [Member] | RockPile Notes Payable to Sellers of Team Well Service, Inc. [Member] | |||||||||
Eurodollar Rate Plus 1% [Member] | Eurodollar [Member] | Eurodollar Rate Plus 1% [Member] | Eurodollar [Member] | agreement | item | agreement | agreement | ||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, maximum borrowing capacity | ' | $320,000,000 | $275,000,000 | ' | ' | ' | $27,500,000 | $100,000,000 | ' | ' | ' | $150,000,000 | ' | ' | ' | ' | ' | $18,000,000 | ' | $2,000,000 | $7,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, amount outstanding | 183,000,000 | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,700,000 | 2,000,000 | 3,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, maturity date | 16-Oct-18 | ' | ' | ' | ' | ' | 25-Feb-16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, principal payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000 | ' | 100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, basis spread on interest rate | ' | ' | ' | ' | 0.50% | ' | ' | ' | 1.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | 4.50% | 4.00% | ' | ' | ' | ' | ' | ' | 2.80% | ' | ' | 2.70% | ' | ' | ' | ' |
Credit facility, interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.75% | 4.75% | 4.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrued interest | 9,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Notes payable | ' | ' | ' | ' | ' | ' | 9,403,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitment fee percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.13% | 0.50% | ' | ' | ' | 0.38% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facility, margin on dollar amount based on usage | 0.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.25% | 3.25% | ' | 1.50% | 2.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Notes payable interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.75% | ' | 1.00% | ' |
Number of unsecured loans | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | 2 | ' | 2 |
Debt instrument, face amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,600,000 | ' | 2,600,000 | 3,300,000 | ' | 4,500,000 | ' | ' | 1,500,000 | ' | ' | ' | ' | 500,000 |
Debt instrument, stated interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.75% | ' | 1.00% | ' |
Debt term | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 years | ' | ' | '15 years | ' | ' | ' | ' |
Interest rate at period end | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.75% | ' | ' | 4.75% | ' | ' | ' | ' |
Number of units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ' |
Purchase price of apartment building | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,800,000 | ' | ' | ' | ' | ' |
Debt instrument, maturity date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Dec-28 | ' | ' | ' | 31-Dec-13 | ' | 16-Oct-16 | ' |
Carrying value of debt | $343,208,000 | ' | ' | $148,023,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,600,000 | ' | ' | $4,500,000 | ' | ' | ' | ' | $1,500,000 | ' | ' | $900,000 | ' |
Commodity_Derivative_Instrumen2
Commodity Derivative Instruments (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | 10 Months Ended | 12 Months Ended | 17 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||||
In Thousands, except Share data, unless otherwise specified | Oct. 31, 2013 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jul. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Oct. 31, 2012 | Jan. 31, 2014 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | Sep. 30, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 |
Class A Triggering Units [Member] | Class A Triggering Units [Member] | Class A Triggering Units [Member] | Series 1 And Series 2 Warrants [Member] | Series 1, Series 2, Series 3 and Series 4 Warrants [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | |||||
item | Triangle Caliber Holdings LLC [Member] | Class A Triggering Units [Member] | Class A Units [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Class A Trigger Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 1 Warrant $14.69 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Series 2 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 3 Warrant $24.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | Series 4 Warrant $30.00 Strike Price [Member] | Forecast [Member] | Forecast [Member] | Class A Triggering Units [Member] | Series 1, Series 2, Series 3 and Series 4 Warrants [Member] | Class A Triggering Units [Member] | Series 1, Series 2, Series 3 and Series 4 Warrants [Member] | |||||||||
Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Triangle Caliber Holdings LLC [Member] | Series 1 Warrant $14.69 Strike Price [Member] | ||||||||||||||||
Triangle Caliber Holdings LLC [Member] | |||||||||||||||||||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (loss) from derivative activities | ' | ' | $1,082 | ($3,570) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain on equity investment derivative | $35,832 | $35,832 | $39,785 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Trigger Units received | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A Units received | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' |
Number of producer wells to trigger conversion of Class A Trigger Units | ' | ' | ' | ' | ' | 162 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of revenue from third party volumes equal to distributable cash flow to trigger conversion of Class A Trigger Unit | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of consecutive quarters revenue attributable to third party volumes equal 50% of distributable cash flow to trigger conversion of Class A Trigger Unit | ' | ' | ' | ' | ' | '1 year 6 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of non-consecutive quarters revenue attributable to third party volumes equal 50% of distributable cash flow to trigger conversion of Class A Trigger Unit | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, Class A units exercise price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average cost of capital | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.30% | ' | 11.60% | ' |
Probability of conversion of units | ' | ' | ' | ' | 5.00% | ' | 100.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investments, warrants received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | 1,600,000 | 4,000,000 | 4,000,000 | 2,400,000 | 2,400,000 | 3,000,000 | 3,000,000 | 3,000,000 | 2,000,000 | 2,000,000 | ' | 1,600,000 | ' | ' | ' | ' |
Equity method investments, warrant excercise price | ' | ' | ' | ' | ' | ' | ' | ' | ' | $14.69 | ' | ' | $14.69 | $14.69 | $14.69 | $14.69 | $24 | $24 | $24 | $24 | $24 | $30 | $30 | ' | $14.69 | ' | ' | ' | ' |
Equity Method Investments, warrant floor price | ' | ' | ' | ' | ' | ' | ' | ' | $5 | ' | ' | ' | $5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Warrant expiration date | ' | ' | ' | ' | ' | 1-Oct-24 | ' | 1-Oct-24 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Warrant underlying value | ' | ' | ' | ' | ' | ' | ' | ' | $10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected term of warrants | ' | ' | ' | ' | ' | '12 years | ' | ' | '12 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Warrant expected volitality rate | ' | ' | ' | ' | ' | 25.00% | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Risk-free interest rates over the expected warrant terms | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.50% | 0.40% | 1.20% | 3.00% |
Commodity_Derivative_Instrumen3
Commodity Derivative Instruments (Summary Of Derivative Instruments) (Details) | 12 Months Ended | |
Jan. 31, 2014 | ||
bbl | ||
Fiscal 2015 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
End date | 'Fiscal 2015 | |
Contract type | 'Collar | |
Basis | 'NYMEX | [1] |
Quantity, (bbls) | 3,282 | |
Fiscal 2015 Swap [Member] | ' | |
Derivative [Line Items] | ' | |
End date | 'Fiscal 2015 | |
Contract type | 'Swap | |
Basis | 'NYMEX | [1] |
Quantity, (bbls) | 1,084 | |
Weighted average price | 95.66 | |
Fiscal 2016 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
End date | 'Fiscal 2016 | |
Contract type | 'Collar | |
Basis | 'NYMEX | [1] |
Quantity, (bbls) | 1,373 | |
Put strike price | 80 | |
Minimum [Member] | Fiscal 2015 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
Put strike price | 80 | |
Call strike price | 94.4 | |
Minimum [Member] | Fiscal 2016 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
Call strike price | 94.5 | |
Maximum [Member] | Fiscal 2015 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
Put strike price | 91.25 | |
Call strike price | 101.2 | |
Maximum [Member] | Fiscal 2016 Collar [Member] | ' | |
Derivative [Line Items] | ' | |
Call strike price | 96.65 | |
[1] | NYMEX refers to quoted prices on the New York Mercantile Exchange. |
Commodity_Derivative_Instrumen4
Commodity Derivative Instruments (Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value) (Details) (USD $) | Jan. 31, 2014 | Jan. 31, 2013 |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative Assets | $41,881,000 | ' |
Crude Oil Derivative Contract [Member] | Current Assets [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 1,066,000 | 1,305,000 |
Derivative Asset, Fair Value, Gross Liability | -111,000 | -702,000 |
Derivative Assets | 955,000 | 603,000 |
Crude Oil Derivative Contract [Member] | Long-Term Assets [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 1,192,000 | ' |
Derivative Assets | 1,192,000 | ' |
Crude Oil Derivative Contract [Member] | Long-Term Liabilities [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative Liability, Fair Value, Gross Liability | ' | -292,000 |
Derivative Liabilities | ' | -292,000 |
Equity Investment Derivative [Member] | Long-Term Assets [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 39,734,000 | ' |
Derivative Assets | $39,734,000 | ' |
Recovered_Sheet2
Commitments and Contingencies (Narrative) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Long-term Purchase Commitment [Line Items] | ' | ' | ' |
Lease operating expense | $0.80 | $0.50 | $0.20 |
Early contract termination fee | 11.5 | ' | ' |
Contingent liability for bonus payout to CEO | $0 | ' | ' |
Caliber Midstream Partners, L.P. [Member] | Chief Executive Officer [Member] | ' | ' | ' |
Long-term Purchase Commitment [Line Items] | ' | ' | ' |
Percentage bonus payout of gain on sale of subisdiary | 5.00% | ' | ' |
Rockpile [Member] | Chief Executive Officer [Member] | ' | ' | ' |
Long-term Purchase Commitment [Line Items] | ' | ' | ' |
Percentage bonus payout of gain on sale of subisdiary | 3.50% | ' | ' |
Commitments_And_Contingencies_1
Commitments And Contingencies (Schedule Of Annual Rentals Per Year) (Details) (USD $) | Jan. 31, 2014 |
In Thousands, unless otherwise specified | |
Commitments And Contingencies [Abstract] | ' |
2015 | $1,180 |
2016 | 1,207 |
2017 | 1,234 |
2018 | 1,108 |
2019 | $617 |
Commitments_And_Contingencies_2
Commitments And Contingencies (Rockpile Annual Various Future Expenditures) (Details) (Rockpile [Member], USD $) | Jan. 31, 2014 |
In Thousands, unless otherwise specified | |
Rockpile [Member] | ' |
Long-term Purchase Commitment [Line Items] | ' |
2015 | $1,752 |
2016 | 582 |
2017 | 441 |
2018 | 360 |
2019 | 200 |
Thereafter | $655 |
Capital_Stock_Details
Capital Stock (Details) (USD $) | 0 Months Ended | 2 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 2 Months Ended | 12 Months Ended | ||||
Aug. 28, 2013 | Aug. 02, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | Jan. 31, 2012 | Jul. 31, 2012 | Jan. 31, 2014 | Mar. 08, 2013 | Aug. 08, 2013 | Sep. 30, 2013 | Jan. 31, 2014 | |
item | Triangle USA Petroleum Corporation [Member] | Private Placement [Member] | Public Offering [Member] | Public Offering [Member] | Restricted Stock Units (RSUs) [Member] | ||||||
item | |||||||||||
Capital Stock [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of affiliates | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' |
Common stock issued, shares | 11,350,000 | 325,000 | 17,250,000 | ' | ' | ' | 5,000 | 9,300,000 | 15,000,000 | ' | 664,483 |
Share price, new issues | $7.20 | $7.50 | $6.25 | $7.61 | ' | $5.59 | $7.24 | $6 | $6.25 | ' | ' |
Common stock issued, value | $81,700,000 | $2,400,000 | $107,800,000 | ' | ' | ' | ' | $55,800,000 | ' | ' | ' |
Common shares issued, costs | 900,000 | ' | 6,000,000 | 7,072,000 | 7,570,000 | ' | ' | 100,000 | ' | ' | ' |
Shares issued, share based compensation | ' | ' | ' | 108,333 | ' | ' | ' | ' | ' | ' | ' |
Proceeds from issuance of common stock | 80,800,000 | ' | ' | 245,333,000 | 142,313,000 | ' | ' | ' | ' | 107,800,000 | ' |
Proceeds from the issuance of private placement net of transaction costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | 101,800,000 | ' |
Over-allotment option period for underwriters | ' | ' | ' | ' | ' | ' | ' | ' | '30 days | ' | ' |
Shares issued for over-allotment to underwriters | ' | ' | ' | ' | ' | ' | ' | ' | 2,250,000 | ' | ' |
Threshold of ownership of acquired common stock for termination of preemptive offering rights | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' |
Threshold of ownership of common stock for termination of preemptive offering rights | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' |
Threshold of common stock value for right of affiliate to designate member of board of directors | ' | ' | ' | $150,000,000 | ' | ' | ' | ' | ' | ' | ' |
Number of board of director members that may be designated by affiliate after common stock value threshold met | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' |
Consolidated leverage ratio | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' |
Significant_Customers_Details
Significant Customers (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | ||
customer | |||||||||||||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | $160,548 | $39,614 | $8,136 | ||
Total revenues | 85,510 | 88,549 | [1] | 50,394 | 34,294 | 24,028 | 21,300 | 10,132 | 5,241 | [2] | 258,747 | 60,701 | 8,136 |
Number of significant customers | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ||
Crude Oil [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | 155,000 | ' | ' | ||
Number of customers | ' | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' | ||
Natural Gas Liquids [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of customers | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ||
Natural Gas [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of customers | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ||
Triangle USA Petroleum Corporation [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of wells | 31 | ' | ' | ' | ' | ' | ' | ' | 31 | ' | ' | ||
Customer One [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | 83,100 | ' | ' | ||
Customer Two [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | 63,900 | ' | ' | ||
Wells Operated By Triangle [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of wells | 54 | ' | ' | ' | ' | ' | ' | ' | 54 | ' | ' | ||
Wells Operated By Triangle [Member] | Crude Oil [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Oil and natural gas sales | ' | ' | ' | ' | ' | ' | ' | ' | $117,500 | ' | ' | ||
Wells Operated By Six Third Parties [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenue, Major Customer [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of wells | 50 | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ||
Number of third parties | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | ||
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | ||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Earnings_Per_Share_Narrative_D
Earnings Per Share (Narrative) (Details) (USD $) | 12 Months Ended | |
Jan. 31, 2014 | Jan. 31, 2013 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ' | ' |
Anitdilutive securities excluded from calculation of diluted net income | 5,250,000 | 4,500,000 |
CEO Options [Member] | ' | ' |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ' | ' |
Exercise price per share, lower limit | 8.5 | ' |
Exercise price per share, upper limit | 15 | ' |
Earnings_Per_Share_Computation
Earnings Per Share (Computations Of Basic And Diluted Net Loss Per Share) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | ||
Earnings Per Share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income (loss) attributable to common stockholders | $14,249 | $47,221 | [1] | $6,799 | $5,211 | ($9,055) | ($598) | ($1,079) | ($3,028) | [2] | $59,232 | $73,480 | ($13,760) | ($24,278) |
Effect of debt conversion | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,392 | ' | ' | ||
Net income (loss) attributable to common shareholders after effect of debt conversion | ' | ' | ' | ' | ' | ' | ' | ' | ' | $76,872 | ($13,760) | ($24,278) | ||
Basic weighted average common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | 68,578,553 | 44,475,201 | 40,707,957 | ||
Effect of dilutive securities | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,978,989 | ' | ' | ||
Diluted weighted average common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | 84,557,542 | 44,475,201 | 40,707,957 | ||
Basic net income (loss) per share | $0.17 | $0.60 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.94 | $1.07 | ($0.31) | ($0.60) | |
Diluted net income (loss) per share | $0.15 | $0.50 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.78 | $0.91 | ($0.31) | ($0.60) | |
Anti-dilutive shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,250,000 | 4,500,000 | ' | ||
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | |||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Income_Taxes_Narrative_Details
Income Taxes (Narrative) (Details) (USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Federal statutory rate | 35.00% | 35.00% | 35.00% |
Difference in foreign tax rates | $164,000 | $28,000 | $600,000 |
US effective tax rate | 37.90% | ' | ' |
Canadian effective tax rate | 25.00% | ' | ' |
Unrecognized Tax Benefits | 0 | 0 | ' |
Unrecognized tax benefits | 0 | 0 | ' |
Provision for uncertain tax positions | 0 | 0 | ' |
Domestic Tax Authority [Member] | ' | ' | ' |
Duration of cumulative income for deferred tax assets | '3 years | ' | ' |
Net operating loss carryforward | 91,500,000 | ' | ' |
Net operating loss carryforwards that do not benefit financial statements | 3,900,000 | ' | ' |
Foreign Tax Authority [Member] | ' | ' | ' |
Net operating loss carryforward | $7,600,000 | ' | ' |
Minimum [Member] | Domestic Tax Authority [Member] | ' | ' | ' |
Duration of expected taxable income (loss) for deferred tax asset | '4 years | ' | ' |
Minimum [Member] | Foreign Tax Authority [Member] | ' | ' | ' |
Duration of expected taxable income (loss) for deferred tax asset | '4 years | ' | ' |
Maximum [Member] | Domestic Tax Authority [Member] | ' | ' | ' |
Duration of expected taxable income (loss) for deferred tax asset | '5 years | ' | ' |
Maximum [Member] | Foreign Tax Authority [Member] | ' | ' | ' |
Duration of expected taxable income (loss) for deferred tax asset | '5 years | ' | ' |
Income_Taxes_Schedule_Of_Incom
Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Oct. 31, 2013 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Income Taxes [Abstract] | ' | ' | ' | ' | ' |
Deferred income tax expense (benefit), Federal | ' | ' | $7,324 | ($2,137) | ($6,189) |
Deferred income tax expense (benefit), State | ' | ' | 617 | -223 | -175 |
Deferred income tax expense (benefit), Foreign | ' | ' | ' | -83 | -1,510 |
Valuation allowance - United States and Canada | ' | ' | -26,364 | 2,443 | 7,874 |
Income tax expense (benefit) | 5,969 | 5,969 | 7,941 | ' | ' |
Income (loss) before income taxes | $53,190 | $65,201 | $81,421 | ($14,484) | ($24,423) |
Effective income tax rate | ' | ' | 10.00% | 0.00% | 0.00% |
Income_Taxes_Reconciliation_Of
Income Taxes (Reconciliation Of Income Tax Benefit) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Oct. 31, 2013 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Income Taxes [Abstract] | ' | ' | ' | ' | ' |
Federal statutory tax expense (benefit) | ' | ' | $28,498 | ($5,069) | ($8,361) |
State income tax expense / (benefit), net of federal income tax benefit | ' | ' | 2,324 | -361 | -565 |
Permanent differences | ' | ' | 3,221 | 2,280 | 132 |
Difference in foreign tax rates | ' | ' | 164 | 28 | 600 |
Effect of tax rate change | ' | ' | -258 | -71 | 83 |
Credits | ' | ' | -100 | ' | ' |
Changes in valuation allowance | ' | ' | -26,364 | 2,443 | 7,874 |
Other | ' | ' | 456 | 750 | 237 |
Income tax expense (benefit) | $5,969 | $5,969 | $7,941 | ' | ' |
Income_Taxes_Components_Of_Def
Income Taxes (Components Of Deferred Tax Asset) (Details) (USD $) | Jan. 31, 2014 | Oct. 31, 2013 | Jan. 31, 2013 |
In Thousands, unless otherwise specified | |||
Deferred Tax Assets And Liabilities [Line Items] | ' | ' | ' |
Asset retirement obligations | $1,071 | ' | ' |
Accurals | 102 | ' | ' |
Hedging assets | ' | ' | 1,342 |
Total current assets | 1,173 | ' | 1,342 |
Valuation allowance | -492 | ' | -1,342 |
Total current assets after valuation allowance | 681 | ' | ' |
Hedging liabilities | -361 | ' | ' |
Total current liabilities | -361 | ' | ' |
Net current deferred income tax asset | 321 | ' | ' |
Canadian oil and natural gas properties | 6,080 | ' | 6,095 |
United States net losses carried forward | 33,129 | ' | 37,816 |
Canadian net losses carried forward | 1,905 | ' | 1,726 |
Asset retirement obligations | 416 | ' | 1,102 |
Stock-based compensation | 3,105 | ' | 1,356 |
Property and equipment | 157 | ' | 157 |
Other | 1,864 | ' | 673 |
Total non-current assets | 46,656 | ' | 49,031 |
Valuation allowance | -8,165 | ' | -33,679 |
Total non-current assets after valuation allowance | 38,491 | ' | 15,352 |
United States oil and natural gas properties | -29,536 | ' | -15,275 |
Investment in Caliber | -16,766 | ' | ' |
Hedging liabilities | -451 | ' | ' |
Other | ' | ' | -77 |
Total deferred non-current income tax liability | -46,753 | ' | -15,352 |
Deferred income tax liability | -8,262 | 5,969 | ' |
Caliber Midstream Partners [Member] | ' | ' | ' |
Deferred Tax Assets And Liabilities [Line Items] | ' | ' | ' |
Investment in | ' | ' | $106 |
ShareBased_Compensation_Narrat
Share-Based Compensation (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||
Aug. 28, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2013 | Jan. 31, 2014 | Feb. 15, 2013 | Dec. 28, 2012 | Oct. 31, 2011 | Oct. 31, 2011 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | |
Restricted Stock Units (RSUs) [Member] | Restricted Stock Units (RSUs) [Member] | Restricted Stock Units (RSUs) [Member] | Restricted Stock Units (RSUs) [Member] | CEO Option Grant [Member] | Employee Stock Option [Member] | Employee Stock Option [Member] | Rockpile Series A Units [Member] | Rockpile Series A Units [Member] | Rockpile Series A Units [Member] | Rockpile Series A Units [Member] | Rockpile Series A Units [Member] | Rockpile Series A Units [Member] | Series B Units [Member] | Series B Units [Member] | Series B Units [Member] | Series B Units [Member] | 2011 Omnibus Incentive Plan [Member] | Rolling Plan [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | First And Second Anniversary Of Tranche [Member] | Third Anniversary Of Tranche [Member] | Fourth Anniversary Of Tranche [Member] | Fifth Anniversary Of Tranche [Member] | |||||
Three Parties [Member] | Rockpile [Member] | Restricted Stock Units (RSUs) [Member] | Series B Units [Member] | Restricted Stock Units (RSUs) [Member] | Series B Units [Member] | Rolling Plan [Member] | |||||||||||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum authorized shares may be issued as percent of issued and outstanding shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expiration period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' |
Maximum shares reserved under Plan | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | 5,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based awards vesting period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '0 years | ' | ' | '3 years | '1 year | '11 months | '5 years | '41 months | ' | ' | ' | ' | ' | ' | ' | ' |
Stock-based compensation | ' | $7,830,000 | $6,466,000 | $7,567,000 | $7,500,000 | $6,600,000 | ' | ' | $1,100,000 | $1,100,000 | $100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation | ' | ' | ' | ' | 14,400,000 | ' | ' | ' | 18,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation, recognition period | ' | ' | ' | ' | '2 years 4 months 28 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Vesting percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 50.00% | 20.00% | 10.00% |
Intrinsic value of options exercised | ' | 162,000 | 12,000 | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from exercise of options | ' | 162,000 | 12,500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of options exercised | ' | 108,333 | 4,167 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 108,333 | 4,167 | 82,501 | ' | ' | ' | ' |
Unrecognized compensation cost related to awards | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,430,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of units held | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of held units outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contributed capital | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | 20,000,000 | 24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of units received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500,000 | 4,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Compensation expense before capitalized amount | ' | 9,221,000 | 7,415,000 | 7,778,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000 | 600,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exercise of stock options, shares | ' | 108,333 | 4,167 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 108,333 | 4,167 | 82,501 | ' | ' | ' | ' |
Units granted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from issuance of common stock | 80,800,000 | 245,333,000 | ' | 142,313,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Units granted, number of units | ' | ' | ' | ' | 1,440,133 | 1,041,400 | 2,645,110 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock based compensation capitalized to oil and natural gas properties | ' | 1,391,000 | 949,000 | 211,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unvested units | ' | ' | ' | ' | 2,875,628 | 2,524,085 | 2,488,342 | 509,636 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,070,000 | 3,160,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unvested B units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,488,333 | ' | ' | 1,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred return on investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total grant date fair value of vested share-based payment award | ' | ' | ' | ' | 6,400,000 | 6,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maxiumum amount of distributions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock, shares issued | ' | 85,735,827 | 46,733,011 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes), shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,230 | 24,000 | ' | ' | ' | ' |
ShareBased_Compensation_NonCas
Share-Based Compensation (Non-Cash Stock-Based Compensation Cost) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Compensation expense before capitalized amount | $9,221 | $7,415 | $7,778 |
Less amounts capitalized to oil and natural gas properties | -1,391 | -949 | -211 |
Stock-based compensation | 7,830 | 6,466 | 7,567 |
Restricted Stock Units (RSUs) [Member] | ' | ' | ' |
Compensation expense before capitalized amount | 7,496 | 6,639 | 7,512 |
Employee Stock Option [Member] | ' | ' | ' |
Compensation expense before capitalized amount | 1,135 | 60 | 81 |
Stock Issued Pursuant to Termination Agreements [Member] | ' | ' | ' |
Compensation expense before capitalized amount | ' | 99 | 185 |
RockPile Stock Based Compensation Related to Series [Member] | ' | ' | ' |
Compensation expense before capitalized amount | $590 | $617 | ' |
ShareBased_Compensation_Restri
Share-Based Compensation (Restricted Stock Units Outstanding) (Details) (Restricted Stock Units (RSUs) [Member], USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Restricted Stock Units (RSUs) [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Outstanding, Unvested Beginning Balance | 2,524,085 | 2,488,342 | 509,636 |
Outstanding, Weighted-Average Award Date Fair Value, Beginning Balance | $6.68 | $7.02 | $5.61 |
Units granted, number of units | 1,440,133 | 1,041,400 | 2,645,110 |
Units granted, Weighted Average Award Date Fair Value | $6.95 | $6.37 | $7.06 |
Units forfeited, Number of Shares | -141,909 | -5,600 | -134,000 |
Units forfeited, Weighted Average Award Date Fair Value | $6.58 | $7.59 | $6.81 |
Units that vested, Number of Shares | -946,681 | -1,000,057 | -532,404 |
Units that vested, Weighted Average Award Date Fair Value | $6.71 | $6.90 | $6.20 |
Outstanding, Unvested Ending Balance | 2,875,628 | 2,524,085 | 2,488,342 |
Outstanding, Weighted-Average Grant Date Fair Value, Ending Balance | $6.62 | $6.68 | $7.02 |
ShareBased_Compensation_CEO_Op
Share-Based Compensation (CEO Option Grant Plan Summary) (Details) (CEO Option Grant [Member], USD $) | Jan. 31, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 6,000,000 |
$7.50 Tranche [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 750,000 |
Exercise price per share | 7.5 |
$8.50 Tranche [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 750,000 |
Exercise price per share | 8.5 |
$10.00 Tranche [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 1,500,000 |
Exercise price per share | 10 |
$12.00 Tranche [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 1,500,000 |
Exercise price per share | 12 |
$15.00 Tranche [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Number of shares authorized by Tranche | 1,500,000 |
Exercise price per share | 15 |
ShareBased_Compensation_CEO_Op1
Share-Based Compensation (CEO Option Grant Plan Fair Value Assumptions) (Details) (CEO Option Grant [Member]) | 12 Months Ended |
Jan. 31, 2014 | |
CEO Option Grant [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Risk free rate | 2.18% |
Dividend yield | ' |
Expected volatility | 62.00% |
Weighted average expected stock option life (years) | '6 years 3 months 18 days |
ShareBased_Compensation_Stock_
Share-Based Compensation (Stock Options Outstanding) (Details) (USD $) | 12 Months Ended | |||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' |
Options exercised | -108,333 | -4,167 | ' | ' |
Employee Stock Option [Member] | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' |
Options granted | 6,000,000 | ' | ' | ' |
Options outstanding, ending balance | 6,108,333 | ' | ' | ' |
Weighted average exercise price, options outstanding ending balance | $11.07 | ' | ' | ' |
Rolling Plan And CEO Option Grant [Member] | Employee Stock Option [Member] | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' |
Options outstanding, beginning balance | 231,666 | 235,833 | 343,334 | ' |
Less: options forfeited | -15,000 | ' | -25,000 | ' |
Options exercised | -108,333 | -4,167 | -82,501 | ' |
Options granted | 6,000,000 | ' | ' | ' |
Options outstanding, ending balance | 6,108,333 | 231,666 | 235,833 | ' |
Weighted average exercise price, options outstanding beginning balance | $1.48 | $1.50 | $1.60 | ' |
Weighted average exercise price, options forfeited | $3 | ' | $3 | ' |
Weighted average exercise price, options exercised | $1.25 | $3 | $1.34 | ' |
Weighted average exercise price, options granted | $11.25 | ' | ' | ' |
Weighted average exercise price, options outstanding ending balance | $11.07 | $1.48 | $1.50 | ' |
Options exercisable | 108,333 | 231,666 | 142,500 | 125,833 |
ShareBased_Compensation_Stock_1
Share-Based Compensation (Stock Options Outstanding By Exercise Price) (Details) (Employee Stock Option [Member], USD $) | 12 Months Ended |
Jan. 31, 2014 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Outstanding options | 6,108,333 |
Number of shares exercise | 108,333 |
Weighted average exercise price per share | $11.07 |
Weighted average remaining contractual life (years) | '9 years 3 months 7 days |
Weighted average exercise price per share (exercisable) | $1.25 |
Weighted average remaining contractual life (years) (exercisable) | '9 months 29 days |
$1.25 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $1.25 |
Remaining contractual life | '9 months 29 days |
Outstanding options | 108,333 |
Number of shares exercise | 108,333 |
$7.50 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $7.50 |
Remaining contractual life | '9 years 5 months 5 days |
Outstanding options | 750,000 |
$8.50 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $8.50 |
Remaining contractual life | '9 years 5 months 5 days |
Outstanding options | 750,000 |
$10.00 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $10 |
Remaining contractual life | '9 years 5 months 5 days |
Outstanding options | 1,500,000 |
$12.00 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $12 |
Remaining contractual life | '9 years 5 months 5 days |
Outstanding options | 1,500,000 |
$15.00 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise price per share | $15 |
Remaining contractual life | '9 years 5 months 5 days |
Outstanding options | 1,500,000 |
ShareBased_Compensation_NonVes
Share-Based Compensation (Non-Vested Stock Options Outstanding) (Details) (Employee Stock Option [Member], USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Employee Stock Option [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Non-vested options, beginning balance | ' | 93,332 | 217,500 |
Options granted | 6,000,000 | ' | ' |
Options vested | ' | -93,332 | -107,501 |
Options forfeited | ' | ' | -16,667 |
Non-vested options, ending balance | 6,000,000 | ' | 93,332 |
Weighted-Average Grant Date Fair Value, beginning balance | ' | $1.02 | $1.10 |
Weighted-Average Grant Date Fair Value, Option granted | $11.25 | ' | ' |
Weighted-Average Grant Date Fair Value, Options vested | ' | $1.02 | $1.08 |
Weighted-Average Grant Date Fair Value, Options forfeited | ' | ' | $2.13 |
Weighted-Average Grant Date Fair Value, ending balance | $11.25 | ' | $1.02 |
ShareBased_Compensation_Summar
Share-Based Compensation (Summary Of Series B Unit Activity) (Details) (USD $) | 12 Months Ended | 12 Months Ended | ||||
Jan. 31, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2014 | Jan. 31, 2014 | |
Series B Units [Member] | Series B Units [Member] | Series B Units [Member] | Series B-1 Unit [Member] | Series B-2 Unit [Member] | Series B-3 Unit [Member] | |
Outstanding, Unvested Beginning Balance | ' | 4,070,000 | 3,160,000 | ' | ' | ' |
Units granted | ' | ' | ' | 3,100,000 | 60,000 | 910,000 |
Outstanding, Unvested Ending Balance | ' | 4,070,000 | 3,160,000 | ' | ' | ' |
Weighted average award date unit fair value | ' | ' | ' | ' | ' | $0.70 |
Remaining vesting period | '0 years | ' | ' | '5 months 19 days | '1 year 6 months 29 days | '3 years 3 months 11 days |
ShareBased_Compensation_Summar1
Share-Based Compensation (Summary Of Series B Unit Vesting Status) (Details) | 12 Months Ended | |
Jan. 31, 2014 | Jan. 31, 2012 | |
Series B Units [Member] | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' |
Remaining vesting period | ' | '0 years |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number | 4,070,000 | ' |
Outstanding, Number of Units, Ending Balance | 4,070,000 | ' |
Outstanding, Vested, Beginning Balance | 2,581,667 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | ' | '0 years |
Outstanding, Vested, Ending Balance | 2,581,667 | ' |
Outstanding, Unvested, Ending Balance | 1,488,333 | ' |
Series B-1 Unit [Member] | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' |
Remaining vesting period | '5 months 19 days | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 3,100,000 | ' |
Grants, Number of Units | 3,100,000 | ' |
Grants, Number of Vested Units | 2,566,667 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | '5 months 19 days | ' |
Grants, Number of Unvested Units | 533,333 | ' |
Series B-2 Unit [Member] | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' |
Remaining vesting period | '1 year 6 months 29 days | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 60,000 | ' |
Grants, Number of Units | 60,000 | ' |
Grants, Number of Vested Units | 15,000 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | '1 year 6 months 29 days | ' |
Grants, Number of Unvested Units | 45,000 | ' |
Series B-3 Unit [Member] | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' |
Remaining vesting period | '3 years 3 months 11 days | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 910,000 | ' |
Grants, Number of Units | 910,000 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | '3 years 3 months 11 days | ' |
Grants, Number of Unvested Units | 910,000 | ' |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | ||||||||||||||
Sep. 12, 2013 | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Sep. 12, 2013 | Jan. 31, 2014 | Sep. 12, 2013 | Jan. 31, 2014 | Dec. 06, 2013 | Mar. 27, 2013 | Jan. 31, 2014 | |||
agreement | Caliber Measurement Services LLC - Lease Automatic Custody Transfer [Member] | TUSA [Member] | Caliber Midstream LP [Member] | Caliber Midstream LP [Member] | Caliber North Dakota LLC [Member] | Caliber North Dakota LLC [Member] | Caliber North Dakota LLC [Member] | ||||||||||||||
Triangle Caliber Holdings LLC [Member] | |||||||||||||||||||||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of midstream agreements with Caliber North Dakota LLC | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Equity method ownership percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30.00% | 30.00% | ' | ' | ' | ||
Term of midstream agreements with Caliber | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 years | ||
Minmum commitment over term of agreements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $405,000,000 | ||
Additional contributions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 9,000,000 | ' | ||
Contributions commitment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ||
Transaction amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500,000 | ' | ' | ' | ' | ' | ' | ||
Revenues from related parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revenues | ' | $85,510,000 | $88,549,000 | [1] | $50,394,000 | $34,294,000 | $24,028,000 | $21,300,000 | $10,132,000 | $5,241,000 | [2] | $258,747,000 | $60,701,000 | $8,136,000 | ' | $15,000,000 | ' | ' | ' | ' | $15,600,000 |
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | ||||||||||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Significant_Changes_in_Proved_1
Significant Changes in Proved Oil And Natural Gas Reserves (Narrative) (Details) | 12 Months Ended | |
Jan. 31, 2014 | Jan. 31, 2013 | |
item | item | |
Reserve Quantities [Line Items] | ' | ' |
Productive oil wells, number of wells, net | 50 | 16 |
Percentage of increase (decrease) in productive oil wells, net | ' | 168.00% |
Number of proved undeveloped locations for which wells were drilled, net | 52.5 | 19.8 |
Percentage of increase (decrease) in future development oil wells, net | ' | 213.00% |
Crude Oil Reserves [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Industry average, sales price per unit | 93.09 | 84.76 |
Natural Gas Reserves [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Industry average, sales price per unit | 3.99 | 5.23 |
Natural Gas Liquids [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Industry average, sales price per unit | 44.1 | ' |
Significant_Changes_in_Proved_2
Significant Changes in Proved Oil And Natural Gas Reserves (Proved Oil And Gas Reserves) (Details) | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 |
MBbls | MBbls | MBbls | MBbls | |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Proved Developed, Percentage of Reserves | 42.00% | ' | ' | ' |
Proved Developed, (Mboe) | 16,995 | 5,969 | ' | ' |
Proved Developed, Percentage change in reserves | 185.00% | ' | ' | ' |
Proved Undeveloped, Percentage of Reserves | 58.00% | ' | ' | ' |
Proved Undeveloped, (Mboe) | 23,319 | 8,668 | ' | ' |
Proved Undeveloped, Percentage change in reserves | 169.00% | ' | ' | ' |
Total Proved, Percentage of Reserves | 100.00% | ' | ' | ' |
Total Proved, (Mboe) | 40,314 | 14,637 | ' | ' |
Total Proved, Percentage change in reserves | 175.00% | ' | ' | ' |
Crude Oil Reserves [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Proved Developed, Volume | 13,734 | 4,985 | 538 | 215 |
Proved Undeveloped, Volume | 18,182 | 7,555 | 827 | 1,021 |
Total Proved, Volume | 31,916 | 12,539 | 1,365 | 1,236 |
Natural Gas Reserves [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Proved Developed, Volume | 10,930 | 5,906 | 202 | ' |
Proved Undeveloped, Volume | 15,574 | 6,679 | 472 | ' |
Total Proved, Volume | 26,504 | 12,585 | 674 | ' |
Natural Gas Liquids [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Proved Developed, Volume | 1,440 | ' | ' | ' |
Proved Undeveloped, Volume | 2,541 | ' | ' | ' |
Total Proved, Volume | 3,981 | ' | ' | ' |
Unaudited_Supplemental_Oil_And2
Unaudited Supplemental Oil And Natural Gas Disclosures (Narrative) (Details) (USD $) | 12 Months Ended | |||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 | |
MBoe | MBoe | MBoe | MBoe | |
item | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Productive wells, gross | 112 | ' | ' | ' |
Productive wells, net | 28.1 | ' | ' | ' |
New proved undeveloped, gross | 68 | ' | ' | ' |
New proved undeveloped, net | 29 | ' | ' | ' |
Percentage of revisions of previous estimates | 22.00% | ' | ' | ' |
Proved Undeveloped Reserve BOE 1 | 23,319 | 8,668 | 905 | 1,021 |
Net increase and decrease on proved undeveloped reserve BOE 1 | 14,651 | ' | ' | ' |
Proved undeveloped reserves, conversion to proved developed reserves | 3,701 | 363 | 52 | ' |
Investment in drilling and completion of wells | $74,900,000 | ' | ' | ' |
Investment in drilling and completion per well | 9,400,000 | ' | ' | ' |
Estimated future development costs | 505,432,000 | 199,173,000 | 23,362,000 | ' |
Estimated future net costs | 1,263,799,000 | 509,005,000 | 55,674,000 | ' |
Decrease in standardize measure | 300,000 | ' | ' | ' |
Net Of Equipment Salvage Value [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Estimated future net costs | $19,200,000 | ' | ' | ' |
Gross Wells [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Proved undeveloped wells, became developed during period | 32 | 9 | 3 | ' |
Net Wells [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Proved undeveloped wells, became developed during period | 7.9 | 1.2 | ' | ' |
Crude Oil Reserves [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Proved reserves added by extensions and discoveries | 12,059 | 10,960 | 1,154 | ' |
Revisions of previous estimates | 2,727 | 665 | -932 | ' |
Natural Gas Reserves [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Proved reserves added by extensions and discoveries | 11,064 | 10,251 | 686 | ' |
Revisions of previous estimates | -859 | 1,832 | ' | ' |
Natural Gas Liquids Reserves [Member] | ' | ' | ' | ' |
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ' | ' | ' | ' |
Proved reserves added by extensions and discoveries | 1,599 | ' | ' | ' |
Revisions of previous estimates | 1,762 | ' | ' | ' |
Unaudited_Supplemental_Oil_And3
Unaudited Supplemental Oil And Natural Gas Disclosures (Schedule Of Direct Revenue And Cost Information Relating To Oil And Gas Exploration And Production Activities ) (Details) (USD $) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' |
Gathering, transportation and processing | $4,302,000 | $150,000 | $22,000 |
Amortization of oil and natural gas properties | 50,100,000 | 13,500,000 | 3,000,000 |
Amortization rate per Boe | 26.43 | 27.75 | 31.85 |
United States [Member] | ' | ' | ' |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' |
Oil and natural gas revenues from production (all sold to unaffiliated parties) | 160,548 | 39,614 | 8,136 |
Production taxes | 18,006 | 4,493 | 896 |
Other lease operating expenses | 14,454 | 3,469 | 901 |
Gathering, transportation and processing | 4,302 | 151 | 22 |
Impairment of oil and natural gas properties | ' | ' | 6,000 |
Amortization of oil and natural gas properties | 50,991 | 13,548 | 3,022 |
Accretion of asset retirement obligation | 56 | 22 | 7 |
Operating income (loss) before income tax expense | 72,739 | 17,931 | -2,712 |
Less income tax (expense) benefit at statutory rates | -27,532 | -6,697 | 1,013 |
Results of oil and natural gas operations (excluding general corporate overhead and interest expense) | 45,207 | 11,234 | -1,699 |
Amortization rate per Boe | 26.43 | 27.75 | 31.85 |
Lease Operating Expenses (per Boe) | 7.49 | 7.11 | 9.5 |
Gathering, Transportation and Processing (per Boe) | 2.23 | 0.31 | 0.23 |
Canada [Member] | ' | ' | ' |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' |
Other lease operating expenses | ' | ' | 641,000 |
Impairment of oil and natural gas properties | ' | ' | 4,416,000 |
Accretion of asset retirement obligation | 962,000 | 162,000 | 160,000 |
Operating income (loss) before income tax expense | -962,000 | -162,000 | -5,217,000 |
Results of oil and natural gas operations (excluding general corporate overhead and interest expense) | ($962,000) | ($162,000) | ($5,217,000) |
Unaudited_Supplemental_Oil_And4
Unaudited Supplemental Oil And Natural Gas Disclosures (Summary Of Changes In Estimated Proved Reserves) (Details) | 12 Months Ended | |||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 | |
MBbls | MBbls | MBbls | MBbls | |
Crude Oil Reserves [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Total proved reserves, beginning balance | 12,539 | 1,365 | 1,236 | ' |
Revisions of previous estimates | 2,727 | 665 | -932 | ' |
Purchase of reserves | 6,836 | 230 | ' | ' |
Extensions, discoveries and other additions | 12,059 | 10,960 | 1,154 | ' |
Sale of reserves | -491 | -229 | ' | ' |
Production | -1,754 | -452 | -93 | ' |
Total proved reserves, ending balance | 31,916 | 12,539 | 1,365 | ' |
Proved Developed, Volume | 13,734 | 4,985 | 538 | 215 |
Proved Undeveloped, Volume | 18,182 | 7,555 | 827 | 1,021 |
Natural Gas Reserves [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Total proved reserves, beginning balance | 12,585 | 674 | ' | ' |
Revisions of previous estimates | -859 | 1,832 | ' | ' |
Purchase of reserves | 4,714 | 181 | ' | ' |
Extensions, discoveries and other additions | 11,064 | 10,251 | 686 | ' |
Sale of reserves | -374 | -165 | ' | ' |
Production | -626 | -188 | -12 | ' |
Total proved reserves, ending balance | 26,504 | 12,585 | 674 | ' |
Proved Developed, Volume | 10,930 | 5,906 | 202 | ' |
Proved Undeveloped, Volume | 15,574 | 6,679 | 472 | ' |
Natural Gas Liquids Reserves [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Revisions of previous estimates | 1,762 | ' | ' | ' |
Purchase of reserves | 690 | ' | ' | ' |
Extensions, discoveries and other additions | 1,599 | ' | ' | ' |
Production | -70 | ' | ' | ' |
Total proved reserves, ending balance | 3,981 | ' | ' | ' |
Proved Developed, Volume | 1,440 | ' | ' | ' |
Proved Undeveloped, Volume | 2,541 | ' | ' | ' |
Unaudited_Supplemental_Oil_And5
Unaudited Supplemental Oil And Natural Gas Disclosures (Summary Of Changes In Proved Undeveloped Reserves) (Details) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
MBoe | MBoe | MBoe | |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved undeveloped reserve (BOE) beginning balance | 8,668 | 905 | 1,021 |
Net revisions | ' | ' | -819 |
Became developed reserves during fiscal year | -3,701 | -363 | -52 |
Traded for net acres in drill spacing units | -353 | -256 | ' |
Negative revisions | -31 | -36 | ' |
Positive revisions | 115 | 102 | ' |
Acquisition of additional interests in PUD location | 5,466 | 172 | ' |
Additional proved undeveloped locations | 13,155 | 8,144 | ' |
Extensions and discoveries of proved reserves | ' | ' | 755 |
Proved undeveloped reserve (BOE) ending balance | 23,319 | 8,668 | 905 |
Gross Wells [Member] | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved undeveloped wells, beginning balance | 59 | 17 | 19 |
Proved undeveloped wells, net revisions | ' | ' | -13 |
Proved undeveloped wells, became developed during period | -32 | -9 | -3 |
Proved undeveloped wells, extensions and discoveries | ' | ' | 14 |
Proved undeveloped wells, traded for net acres in other drill spacing units | -4 | -5 | ' |
Proved undeveloped wells, negative revisions | ' | -1 | ' |
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 13 | ' | ' |
Proved undeveloped wells, additional proved undeveloped locations | 68 | 57 | ' |
Proved undeveloped wells, ending balance | 104 | 59 | 17 |
Net Wells [Member] | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved undeveloped wells, beginning balance | 19.8 | 2.6 | 3 |
Proved undeveloped wells, net revisions | ' | ' | -2.6 |
Proved undeveloped wells, became developed during period | -7.9 | -1.2 | ' |
Proved undeveloped wells, extensions and discoveries | ' | ' | 2.2 |
Proved undeveloped wells, traded for net acres in other drill spacing units | -0.8 | -0.7 | ' |
Proved undeveloped wells, negative revisions | ' | -0.1 | ' |
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 11.8 | 0.3 | ' |
Proved undeveloped wells, additional proved undeveloped locations | 29.6 | 18.9 | ' |
Proved undeveloped wells, ending balance | 52.5 | 19.8 | 2.6 |
Unaudited_Supplemental_Oil_And6
Unaudited Supplemental Oil And Natural Gas Disclosures (Summary Of Status Of Proved Undeveloped Reserves) (Details) | 12 Months Ended |
Jan. 31, 2014 | |
item | |
PUD Locations [Member] | ' |
Development Wells Drilled [Line Items] | ' |
Proved undeveloped locations for operated wells to be drilled and completed by December 31, 2018 | 85 |
Proved undeveloped locations non-operated wells in-progress at January 31, 2014 and are expected to be completed in fiscal year 2015 | 2 |
Proved undeveloped locations non-operated wells with drilling permits | 2 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2016 | 15 |
Proved undeveloped locations additions to proved undeveloped reserves | 104 |
Development Wells Gross [Member] | ' |
Development Wells Drilled [Line Items] | ' |
Proved undeveloped locations for operated wells to be drilled and completed by December 31, 2018 | 85 |
Proved undeveloped locations non-operated wells in-progress at January 31, 2014 and are expected to be completed in fiscal year 2015 | 2 |
Proved undeveloped locations non-operated wells with drilling permits | 2 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2016 | 15 |
Proved undeveloped locations additions to proved undeveloped reserves | 104 |
Development Wells Net [Member] | ' |
Development Wells Drilled [Line Items] | ' |
Proved undeveloped locations for operated wells to be drilled and completed by December 31, 2018 | 51.3 |
Proved undeveloped locations non-operated wells in-progress at January 31, 2014 and are expected to be completed in fiscal year 2015 | ' |
Proved undeveloped locations non-operated wells with drilling permits | 0.2 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2016 | 1 |
Proved undeveloped locations additions to proved undeveloped reserves | 52.5 |
Unaudited_Supplemental_Oil_And7
Unaudited Supplemental Oil And Natural Gas Disclosures (Schedule Of Prices Used In Calculation Of Standardized Measure) (Details) | 12 Months Ended | ||
Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ' | ' | ' |
Oil price per barrel | 93.09 | 84.76 | 89.71 |
Natural gas price per Mcf | 3.99 | 5.23 | 8.19 |
Natural gas liquids price per barrel | 44.1 | ' | ' |
Unaudited_Supplemental_Oil_And8
Unaudited Supplemental Oil And Natural Gas Disclosures (Summary Of Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ' | ' | ' |
Future cash inflows | $3,252,079 | $1,128,676 | $127,955 |
Future costs: | ' | ' | ' |
Production | -1,118,508 | -333,185 | -48,919 |
Development | -505,432 | -199,173 | -23,362 |
Future income tax expense | -364,340 | -87,313 | ' |
Future net cash flows | 1,263,799 | 509,005 | 55,674 |
10% discount factor | -690,564 | -297,653 | -26,246 |
Standardized measure of discounted future net cash flows relating to proved reserves | $573,235 | $211,352 | $29,428 |
Unaudited_Supplemental_Oil_And9
Unaudited Supplemental Oil And Natural Gas Disclosures (Schedule Of Principle Sources Of Change In Standardized Measure) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ' | ' | ' |
Standardized measure, beginning of period | $211,352 | $29,428 | $12,867 |
Extensions and discoveries, net of future production and development costs | 333,140 | 193,107 | 28,414 |
Sales, net of production costs | -123,786 | -31,502 | -5,677 |
Previously estimated development costs incurred during the period | 66,724 | 10,368 | 2,084 |
Revision of quantity estimates | 73,598 | 15,910 | -9,536 |
Net change in prices, net of production costs | 19,173 | 2,779 | 1,001 |
Acquisition of reserves | 99,683 | 2,119 | ' |
Divestitures of reserves | -7,341 | -3,273 | ' |
Accretion of discount | 22,486 | 2,943 | 1,316 |
Changes in future development costs | 7,699 | 801 | -494 |
Change in income taxes | -91,161 | -13,509 | 290 |
Change in production timing and other | -38,332 | 2,181 | -837 |
Standardized measure, end of period | $573,235 | $211,352 | $29,428 |
Recovered_Sheet3
Supplemental Disclosures Of Cash Flow Information (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Supplemental Disclosures of Cash Flow Information [Abstract] | ' | ' | ' |
Interest expense | $1,419 | $75 | ' |
Increased (decreased) accrued liabilities and decreased prepaid well costs | 30,785 | 36,654 | 13,181 |
Capitalized stock-based compensation | 1,391 | 949 | 211 |
Issuance of common stock | 3,827 | 1,204 | 11,780 |
Change in asset retirement obligations | 673 | 1,869 | 53 |
Capitalized interest | 809 | ' | ' |
Purchase minority interest in Rockpile | ' | 12,349 | ' |
Acquisition of oilfield services equipment through notes payable and liabilities | $1,990 | ' | ' |
Quarterly_Financial_Informatio2
Quarterly Financial Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended |
In Thousands, unless otherwise specified | Oct. 31, 2013 | Oct. 31, 2013 | Jan. 31, 2014 | Apr. 30, 2012 |
Maximum [Member] | ||||
Percentage variance between reported periods | ' | ' | ' | 2.00% |
Gain on equity investment derivative | $35,832 | $35,832 | $39,785 | ' |
Deferred tax expense (benefit) | ' | ' | $7,941 | ' |
Quarterly_Financial_Informatio3
Quarterly Financial Information (Schedule Of Quarterly Financial Information) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | ||
Quarterly Financial Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total revenue | $85,510 | $88,549 | [1] | $50,394 | $34,294 | $24,028 | $21,300 | $10,132 | $5,241 | [2] | ' | $258,747 | $60,701 | $8,136 |
Income (loss) from operations | 11,975 | 17,188 | [1] | 13,077 | 4,426 | -2,828 | -617 | -1,389 | -3,336 | [2] | ' | 46,666 | -8,170 | -24,975 |
Net income (loss) | 14,249 | 47,221 | [1] | 6,799 | 5,211 | -9,153 | -672 | -1,335 | -3,324 | [2] | 59,232 | 73,480 | -14,484 | -24,423 |
Net income (loss) attributable to common stockholders | $14,249 | $47,221 | [1] | $6,799 | $5,211 | ($9,055) | ($598) | ($1,079) | ($3,028) | [2] | $59,232 | $73,480 | ($13,760) | ($24,278) |
Net income (loss) per common share - basic | $0.17 | $0.60 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.94 | $1.07 | ($0.31) | ($0.60) | |
Net income (loss) per common share - diluted | $0.15 | $0.50 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.78 | $0.91 | ($0.31) | ($0.60) | |
Net income (loss) per common share - basic and diluted | ' | ' | ' | ' | ($0.20) | ($0.01) | ($0.02) | ($0.07) | [2] | ' | ' | ' | ' | |
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | |||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Quarterly_Financial_Informatio4
Quarterly Financial Information (Schedule Of Expected Error Correction) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2013 | Oct. 31, 2012 | Jul. 31, 2012 | Apr. 30, 2012 | Oct. 31, 2013 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | Jan. 31, 2011 | ||
Equity investment | $68,536 | $58,227 | ' | ' | $11,768 | ' | ' | ' | $58,227 | $68,536 | $11,768 | ' | ' | ||
Total assets | 1,027,584 | 924,920 | ' | ' | 428,321 | ' | ' | ' | 924,920 | 1,027,584 | 428,321 | ' | ' | ||
Deferred tax liability | -8,262 | 5,969 | ' | ' | ' | ' | ' | ' | 5,969 | -8,262 | ' | ' | ' | ||
Total liabilities | 504,422 | 418,184 | ' | ' | 226,699 | ' | ' | ' | 418,184 | 504,422 | 226,699 | ' | ' | ||
Accumulated deficit | -48,540 | -62,788 | ' | ' | -122,020 | ' | ' | ' | -62,788 | -48,540 | -122,020 | ' | ' | ||
Total stockholders' equity | 523,162 | 506,736 | ' | ' | 201,622 | ' | ' | ' | 506,736 | 523,162 | 201,622 | 209,795 | 75,806 | ||
Total liabilities and stockholders' equity | 1,027,584 | 924,920 | ' | ' | 428,321 | ' | ' | ' | 924,920 | 1,027,584 | 428,321 | ' | ' | ||
Gain on equity investment derivative | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | 39,785 | ' | ' | ' | ||
Total other income (expense) | ' | 36,002 | ' | ' | ' | ' | ' | ' | 30,509 | 34,755 | -6,314 | 552 | ' | ||
Net income (loss) before income taxes | ' | 53,190 | ' | ' | ' | ' | ' | ' | 65,201 | 81,421 | -14,484 | -24,423 | ' | ||
Income tax provision | ' | -5,969 | ' | ' | ' | ' | ' | ' | -5,969 | -7,941 | ' | ' | ' | ||
Net income (loss) | 14,249 | 47,221 | [1] | 6,799 | 5,211 | -9,153 | -672 | -1,335 | -3,324 | [2] | 59,232 | 73,480 | -14,484 | -24,423 | ' |
Net income (loss) attributable to common stockholders | 14,249 | 47,221 | [1] | 6,799 | 5,211 | -9,055 | -598 | -1,079 | -3,028 | [2] | 59,232 | 73,480 | -13,760 | -24,278 | ' |
Net income (loss) per common share - basic | $0.17 | $0.60 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.94 | $1.07 | ($0.31) | ($0.60) | ' | |
Net income (loss) per common share - diluted | $0.15 | $0.50 | [1] | $0.12 | $0.10 | ' | ' | ' | ' | $0.78 | $0.91 | ($0.31) | ($0.60) | ' | |
As Previously Reported [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Equity investment | ' | 22,395 | ' | ' | ' | ' | ' | ' | 22,395 | ' | ' | ' | ' | ||
Total assets | ' | 889,088 | ' | ' | ' | ' | ' | ' | 889,088 | ' | ' | ' | ' | ||
Total liabilities | ' | 412,215 | ' | ' | ' | ' | ' | ' | 412,215 | ' | ' | ' | ' | ||
Accumulated deficit | ' | -92,651 | ' | ' | ' | ' | ' | ' | -92,651 | ' | ' | ' | ' | ||
Total stockholders' equity | ' | 476,873 | ' | ' | ' | ' | ' | ' | 476,873 | ' | ' | ' | ' | ||
Total liabilities and stockholders' equity | ' | 889,088 | ' | ' | ' | ' | ' | ' | 889,088 | ' | ' | ' | ' | ||
Total other income (expense) | ' | 170 | ' | ' | ' | ' | ' | ' | -5,323 | ' | ' | ' | ' | ||
Net income (loss) before income taxes | ' | 17,358 | ' | ' | ' | ' | ' | ' | 29,369 | ' | ' | ' | ' | ||
Net income (loss) | ' | 17,358 | ' | ' | ' | ' | ' | ' | 29,369 | ' | ' | ' | ' | ||
Net income (loss) attributable to common stockholders | ' | 17,358 | ' | ' | ' | ' | ' | ' | 29,369 | ' | ' | ' | ' | ||
Net income (loss) per common share - basic | ' | $0.22 | ' | ' | ' | ' | ' | ' | $0.47 | ' | ' | ' | ' | ||
Net income (loss) per common share - diluted | ' | $0.20 | ' | ' | ' | ' | ' | ' | $0.43 | ' | ' | ' | ' | ||
Adjustments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Equity investment | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Total assets | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Deferred tax liability | ' | 5,969 | ' | ' | ' | ' | ' | ' | 5,969 | ' | ' | ' | ' | ||
Total liabilities | ' | 5,969 | ' | ' | ' | ' | ' | ' | 5,969 | ' | ' | ' | ' | ||
Accumulated deficit | ' | 29,863 | ' | ' | ' | ' | ' | ' | 29,863 | ' | ' | ' | ' | ||
Total stockholders' equity | ' | 29,863 | ' | ' | ' | ' | ' | ' | 29,863 | ' | ' | ' | ' | ||
Total liabilities and stockholders' equity | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Gain on equity investment derivative | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Total other income (expense) | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Net income (loss) before income taxes | ' | 35,832 | ' | ' | ' | ' | ' | ' | 35,832 | ' | ' | ' | ' | ||
Income tax provision | ' | -5,969 | ' | ' | ' | ' | ' | ' | -5,969 | ' | ' | ' | ' | ||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 29,863 | ' | ' | ' | ' | ||
Net income (loss) attributable to common stockholders | ' | $29,863 | ' | ' | ' | ' | ' | ' | $29,863 | ' | ' | ' | ' | ||
Net income (loss) per common share - basic | ' | $0.38 | ' | ' | ' | ' | ' | ' | $0.47 | ' | ' | ' | ' | ||
Net income (loss) per common share - diluted | ' | $0.30 | ' | ' | ' | ' | ' | ' | $0.35 | ' | ' | ' | ' | ||
[1] | Restated to reflect the gain on equity investment derivatives in the third quarter of fiscal year 2014 as discussed below. | ||||||||||||||
[2] | ** In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle's consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle's April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of FY2013 vary slightly (by less than 2%) from the corresponding amounts reported in Trianglebs April 30, 2012 Quarterly Report on Form 10-Q. |
Subsequent_Events_Narrative_De
Subsequent Events (Narrative) (Details) (USD $) | Jan. 13, 2014 | Jan. 12, 2014 | Mar. 25, 2014 | Jan. 31, 2014 | Mar. 25, 2014 |
In Millions, unless otherwise specified | Rockpile [Member] | Rockpile [Member] | Rockpile [Member] | ||
Subsequent Event [Member] | |||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' |
Credit facility, maximum borrowing capacity | $320 | $275 | $100 | $27.50 | $100 |
Credit facility, increase in maximum borrowing capacity | ' | ' | ' | ' | $150 |