Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Apr. 01, 2015 | Jul. 31, 2014 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Jan-15 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2015 | ||
Entity Registrant Name | Triangle Petroleum Corp | ||
Entity Central Index Key | 1281922 | ||
Current Fiscal Year End Date | -30 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $695,506,738 | ||
Entity Common Stock, Shares Outstanding | 75,288,381 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Jan. 31, 2015 | Jan. 31, 2014 |
In Thousands, unless otherwise specified | ||
CURRENT ASSETS | ||
Cash and equivalents | $67,871 | $81,750 |
Accounts receivable | 164,438 | 106,463 |
Commodity derivatives | 62,248 | 955 |
Other current assets | 14,952 | 5,652 |
Total current assets | 309,509 | 194,820 |
Oil and natural gas properties, at cost, full cost method of accounting: | ||
Proved properties | 1,153,584 | 629,051 |
Unproved properties and properties under development, not being amortized | 142,896 | 121,393 |
Total oil and natural gas properties | 1,296,480 | 750,444 |
Accumulated amortization | -170,390 | -67,657 |
Net oil and natural gas properties | 1,126,090 | 682,787 |
Oilfield services equipment - net | 87,549 | 46,585 |
Other property and equipment, net | 47,367 | 24,507 |
Net property, plant and equipment | 1,261,006 | 753,879 |
Deferred loan costs | 14,038 | 3,207 |
Equity investment | 64,411 | 68,536 |
Commodity derivatives | 1,192 | |
Other | 5,906 | 5,888 |
Total other assets | 84,355 | 78,823 |
Total assets | 1,654,870 | 1,027,522 |
CURRENT LIABILITIES | ||
Accounts payable and accrued capital expenditures | 176,182 | 109,599 |
Other accrued liabilities | 73,440 | 40,588 |
Current portion of long-term debt | 503 | 8,851 |
Interest payable | 2,250 | 268 |
Deferred income taxes | 19,467 | |
Total current liabilities | 271,842 | 159,306 |
LONG-TERM LIABILITIES | ||
5% convertible note | 135,877 | 129,290 |
Borrowings on credit facilities | 224,159 | 196,065 |
TUSA 6.75% notes | 429,500 | |
Other notes and mortgages payable | 10,102 | 9,002 |
Deferred income taxes | 33,974 | 8,262 |
Other | 4,398 | 2,435 |
Total liabilities | 1,109,852 | 504,360 |
COMMITMENT AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY | ||
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 85,735,827 shares issued and outstanding at January 31, 2015 and January 31, 2014, respectively | 1 | 1 |
Additional paid-in capital | 545,017 | 571,701 |
Retained earnings (accumulated deficit) | -48,540 | |
Total stockholders' equity | 545,018 | 523,162 |
Total liabilities and stockholders' equity | $1,654,870 | $1,027,522 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 |
Common stock, par value | $0.00 | $0.00 |
Common stock, shares authorized | 140,000,000 | 140,000,000 |
Common stock, shares issued | 75,174,442 | 85,735,827 |
Common stock, shares outstanding | 75,174,442 | 85,735,827 |
Convertible Notes [Member] | ||
Debt instrument, interest rate | 5.00% | 5.00% |
TUSA Senior Notes [Member] | ||
Debt instrument, interest rate | 6.75% |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
REVENUES | |||
Oil and natural gas liquids sales | $284,502 | $160,548 | $39,614 |
Oilfield services | 288,453 | 98,199 | 20,747 |
Total revenues | 572,955 | 258,747 | 60,361 |
EXPENSES: | |||
Lease operating expenses | 25,703 | 14,454 | 3,566 |
Gathering, transportation and processing | 18,520 | 4,302 | 150 |
Production taxes | 29,774 | 18,006 | 4,492 |
Depreciation and amortization | 124,055 | 58,011 | 15,081 |
Accretion of asset retirement obligations | 167 | 56 | 184 |
Oilfield services | 216,596 | 82,327 | 16,606 |
General and administrative, net of amounts capitalized | 62,757 | 34,629 | 28,543 |
Total operating expenses | 477,572 | 211,785 | 68,622 |
INCOME FROM OPERATIONS | 95,383 | 46,962 | -8,261 |
OTHER INCOME (EXPENSE): | |||
Interest expense, net | -25,100 | -7,132 | -2,672 |
Amortization of deferred loan costs | -3,149 | -554 | -146 |
Gain on extinguishment of debt | 6,610 | ||
Commodity derivatives gains (losses) | 64,050 | 1,082 | -3,570 |
Equity investment income (loss) | 81 | -283 | |
Gain on equity investment derivatives | 553 | 39,785 | |
Other income | 469 | 1,278 | 448 |
Total other income (expense) | 43,514 | 34,459 | -6,223 |
INCOME (LOSS) BEFORE INCOME TAXES | 138,897 | 81,421 | -14,484 |
Income tax provision | 45,500 | 7,941 | |
NET INCOME (LOSS) | 93,397 | 73,480 | -14,484 |
Less: net loss attributable to the noncontrolling interest in subsidiary | 724 | ||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS | $93,397 | $73,480 | ($13,760) |
Earnings (loss) per common share outstanding: | |||
Basic | $1.12 | $1.07 | ($0.31) |
Diluted | $0.97 | $0.91 | ($0.31) |
Weighted average common shares outstanding: | |||
Basic | 83,611 | 68,579 | 44,475 |
Diluted | 101,032 | 84,558 | 44,475 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $93,397 | $73,480 | ($14,484) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation and amortization | 124,055 | 58,011 | 15,081 |
Share-based compensation | 7,919 | 7,830 | 6,637 |
Interest expense not paid in cash | 6,587 | 6,267 | 3,023 |
Amortization of deferred loan costs | 3,149 | 554 | 146 |
Gain on extinguishment of debt | -6,610 | ||
Accretion of asset retirement obligations | 167 | 56 | 184 |
Commodity derivatives (gains) losses | -64,050 | -1,082 | 3,570 |
Settlements on commodity derivative instruments | 11,422 | -4,643 | |
Equity investment income (loss) | -81 | 283 | |
Gain on equity investment derivatives | -553 | -39,785 | |
Gain on securities held for investment | -1,040 | -204 | |
Deferred income taxes | 45,500 | 7,941 | |
Changes in related current assets and current liabilities: | |||
Accounts receivable | -65,448 | -65,929 | -30,295 |
Other current assets | -9,926 | -3,579 | -2,694 |
Accounts payable and accrued liabilities | 57,233 | 44,840 | 21,762 |
Asset retirement expenditures | -2,206 | -484 | -253 |
Other | 262 | -1 | 8 |
Cash provided by operating activities | 200,817 | 82,436 | 2,764 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Oil and natural gas expenditures | -359,102 | -279,531 | -114,625 |
Acquisitions of oil and natural gas properties | -138,778 | -121,578 | -21,193 |
Purchase of oil field services equipment | -59,624 | -27,414 | -16,535 |
Purchase of other property and equipment | -26,739 | -10,928 | -14,684 |
Sale of oil and natural gas properties | 1,500 | 3,265 | |
Acquisition of oilfield services companies | -7,715 | ||
Equity investment in Caliber Midstream Partners, L.P. | -18,000 | -12,001 | |
Purchase of equity investment derivative contracts | -3,889 | ||
Equity investment cash distribution | 6,080 | 3,150 | |
Sale of marketable securities | 6,105 | ||
Other | -356 | 345 | -50 |
Cash used in investing activities | -577,019 | -455,566 | -179,712 |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from credit facilities | 504,159 | 211,820 | 41,700 |
Repayments of credit facilities | -484,515 | -32,306 | -16,700 |
Proceeds from notes payable | 450,527 | 14,430 | 120,000 |
Repayments of other notes and mortgages payable | -416 | -5,876 | |
Early extinguishment of repurchased debt | -13,890 | ||
Debt issuance costs | -13,980 | -2,670 | -1,270 |
Proceeds from issuance of common stock | 245,369 | ||
Stock offering costs | -7,072 | ||
Payments to settle tax on vested restricted stock units | -2,854 | -2,058 | -1,884 |
Issuance of common stock on exercise of options | 135 | 162 | 13 |
Common stock repurchased and retired | -76,843 | ||
Purchase of minority interest In RockPile | -609 | ||
Other | -36 | ||
Cash provided by financing activities | 362,323 | 421,763 | 141,250 |
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS | -13,879 | 48,633 | -35,698 |
CASH AND EQUIVALENTS, BEGINNING OF PERIOD | 81,750 | 33,117 | 68,815 |
CASH AND EQUIVALENTS, END OF PERIOD | $67,871 | $81,750 | $33,117 |
Consolidated_Statement_of_Stoc
Consolidated Statement of Stockholders' Equity (USD $) | Common Stock [Member] | Additional Paid-In Capital [Member] | Accumulated Deficit [Member] | Non-controlling Interest In Subsidiary [Member] | Total |
Balance at Jan. 31, 2012 | $1,000 | $314,199,000 | ($108,260,000) | $3,855,000 | $209,795,000 |
Balance, shares at Jan. 31, 2012 | 43,515,958 | ||||
Shares issued for the purchase of oil and natural gas properties, value | 1,204,000 | 1,204,000 | |||
Shares issued for the purchase of oil and natural gas properties, shares | 225,000 | ||||
Shares issued for services | 73,000 | 73,000 | |||
Shares issued for services, shares | 10,000 | ||||
Exercise of stock options, value | 13,000 | 13,000 | |||
Exercise of stock options, shares | 4,167 | ||||
Vesting of restricted stock units (net of shares surrendered for taxes) | -1,884,000 | -1,884,000 | |||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 774,941 | ||||
Common shares issued pursuant to termination agreements (net of shares surrendered for taxes), value | 99,000 | 99,000 | |||
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes), shares | 17,230 | ||||
Acquire minority interest in subsidiary | 2,522,000 | -3,131,000 | -609,000 | ||
Acquire minority interest in subsidiary, shares | 2,185,715 | ||||
Stock-based compensation | 7,415,000 | 7,415,000 | |||
Net income (loss) for the year | -13,760,000 | -724,000 | -14,484,000 | ||
Balance at Jan. 31, 2013 | 1,000 | 323,641,000 | -122,020,000 | 201,622,000 | |
Balance, shares at Jan. 31, 2013 | 46,733,011 | ||||
Common stock issued, value | 245,369,000 | 245,369,000 | |||
Common stock issued, shares | 37,905,000 | ||||
Shares issued for the purchase of oil and natural gas properties, value | 2,438,000 | 2,438,000 | |||
Shares issued for the purchase of oil and natural gas properties, shares | 325,000 | ||||
Stock offering costs | -7,072,000 | -7,072,000 | |||
Exercise of stock options, value | 162,000 | 162,000 | |||
Exercise of stock options, shares | 108,333 | ||||
Vesting of restricted stock units (net of shares surrendered for taxes) | -2,058,000 | -2,058,000 | |||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 664,483 | ||||
Stock-based compensation | 9,221,000 | 9,221,000 | |||
Net income (loss) for the year | 73,480,000 | 73,480,000 | |||
Balance at Jan. 31, 2014 | 1,000 | 571,701,000 | -48,540,000 | 523,162,000 | |
Balance, shares at Jan. 31, 2014 | 85,735,827 | 85,735,827 | |||
Exercise of stock options, value | 135,000 | 135,000 | |||
Exercise of stock options, shares | 108,333 | ||||
Vesting of restricted stock units (net of shares surrendered for taxes) | -2,854,000 | -2,854,000 | |||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 762,026 | ||||
Redeemed RockPile B-Units | -1,041,000 | -1,041,000 | |||
Shares repurchased and retired | -31,986,000 | -44,857,000 | -76,843,000 | ||
Shares repurchased and retired, shares | -11,431,744 | ||||
Stock-based compensation | 9,062,000 | 9,062,000 | |||
Net income (loss) for the year | 93,397,000 | 93,397,000 | |||
Balance at Jan. 31, 2015 | $75,174,442 | $545,017,000 | $545,018,000 | ||
Balance, shares at Jan. 31, 2015 | 1,000 | 75,174,442 |
Description_Of_Business
Description Of Business | 12 Months Ended |
Jan. 31, 2015 | |
Description Of Business [Abstract] | |
Description Of Business | 1. DESCRIPTION OF BUSINESS |
Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services. | |
We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana. Our core focus area is in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”). | |
In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston Basin. RockPile began operations in July 2012. | |
In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund (“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, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada. Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia. Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage. Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012. | |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Summary Of Significant Accounting Policies | 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||
Basis of Presentation. These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts. | ||||||||||
No consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented. | ||||||||||
Use of Estimates. In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of undeveloped properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. | ||||||||||
Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying 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’s 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, incorporated in the Province of Alberta, Canada, (iv) Triangle Real Estate Properties, LLC, organized in the State of Colorado, and its wholly-owned subsidiaries, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Ranger Fabrication, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries, and (vii) 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. The investment in Caliber is accounted for utilizing the equity method of accounting. | ||||||||||
Cash and Cash Equivalents. Cash and cash equivalents, including cash in banks in the United States and Canada, consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. | ||||||||||
Accounts Receivable and Credit Policies. The components of accounts receivable include the following (in thousands): | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | |||||||||
Oil and natural gas sales | $ | 21,445 | $ | 25,866 | ||||||
Joint interest billings | 72,235 | 43,660 | ||||||||
Oilfield services revenue | 59,408 | 29,109 | ||||||||
Other | 11,350 | 7,828 | ||||||||
Total accounts receivable | $ | 164,438 | $ | 106,463 | ||||||
The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues. | ||||||||||
The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year): | ||||||||||
Fiscal Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Oil & Gas Customer A | 13% | 22% | N/A | |||||||
Oil & Gas Customer B | 12% | 15% | N/A | |||||||
Oil & Gas Customer C | 12% | N/A | N/A | |||||||
Oilfield Services Customer A | 15% | N/A | N/A | |||||||
Oilfield Services Customer B | 12% | 13% | N/A | |||||||
Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available. While we believe that there are numerous operators in the Williston Basin in need of pressure pumping and related oilfield services, a severe and sustained downturn in commodities pricing could result in the loss of a significant customer. However, we do not believe that the loss of a significant customer would have a material adverse impact on the Company. | ||||||||||
Inventories. Inventories, included in other current assets, 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 utilized in evaluating net realizable value. | ||||||||||
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 natural 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. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. | ||||||||||
The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. | ||||||||||
Under the full cost method of accounting, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | ||||||||||
Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. | ||||||||||
Companies that follow the full cost method of accounting 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. | ||||||||||
At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary. However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline or if there is a negative impact on one or more of the other components of the calculation and such an impairment will likely be material. | ||||||||||
Oil and Natural Gas Reserves. Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision. The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time. | ||||||||||
Oilfield Services Equipment and Other Property and Equipment. Oilfield services equipment and other property and equipment as of January 31, 2014 and 2013 consisted of the following: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Land | $ | 7,888 | $ | 2,512 | ||||||
Building and leasehold improvements | 33,625 | 18,388 | ||||||||
Oilfield service equipment | 116,354 | 56,355 | ||||||||
Vehicles | 4,811 | 2,288 | ||||||||
Software, computers and office equipment | 5,327 | 3,016 | ||||||||
Capital leases | 853 | — | ||||||||
Total depreciable assets | 168,858 | 82,559 | ||||||||
Accumulated depreciation | -35,189 | -12,800 | ||||||||
Depreciable assets, net | 133,669 | 69,759 | ||||||||
Assets not placed in service | 1,247 | 1,333 | ||||||||
Total oilfield service equipment and other property & equipment, net | $ | 134,916 | $ | 71,092 | ||||||
Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Oilfield services equipment and other property and equipment 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 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 ranging from 3-20 years. | ||||||||||
Deferred Loan Costs. Deferred financing costs include origination, legal, engineering, and other fees incurred to issue debt. Deferred financing costs are amortized to interest expense using the effective interest method over the respective borrowing term. | ||||||||||
Equity Investment. The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations after elimination of intra-company profits and losses. The Company records losses of the unconsolidated entities only to the extent of the Company’s investment. | ||||||||||
We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. | ||||||||||
Asset Retirement Obligations. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base. | ||||||||||
Derivative Instruments. The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. | ||||||||||
The Company holds equity investment derivatives (Class A Warrants (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. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. | ||||||||||
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense. | ||||||||||
Oil, Natural Gas and Natural Gas Liquids Revenue. The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract. There were no oil or natural gas sales imbalances at January 31, 2015, 2014, or 2013. | ||||||||||
Oilfield Services Revenue. The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. | ||||||||||
Share-Based Compensation. Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. | ||||||||||
Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted 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. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive. | ||||||||||
The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands): | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Dilutive | 17,421 | 15,979 | — | |||||||
Anti-dilutive shares | 6,905 | 5,250 | 4,500 | |||||||
The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2015, 2014, and 2013: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands, except per share data) | 2015 | 2014 | 2013 | |||||||
Net income (loss) attributable to common stockholders | $ | 93,397 | $ | 73,480 | $ | -13,760 | ||||
Effect of 5% convertible note conversion | 4,135 | 3,392 | — | |||||||
Net income (loss) attributable to common stockholders after effect of debt conversion | $ | 97,532 | $ | 76,872 | $ | -13,760 | ||||
Basic weighted average common shares outstanding | 83,611 | 68,579 | 44,475 | |||||||
Effect of dilutive securities | 17,421 | 15,979 | — | |||||||
Diluted weighted average common shares outstanding | 101,032 | 84,558 | 44,475 | |||||||
Basic net income (loss) per share | $ | 1.12 | $ | 1.07 | $ | -0.31 | ||||
Diluted net income (loss) per share | $ | 0.97 | $ | 0.91 | $ | -0.31 | ||||
New Pronouncements Issued But Not Yet Adopted. In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations. | ||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position. | ||||||||||
In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements. | ||||||||||
Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements. Other than the standards discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted. | ||||||||||
Reclassifications. Certain amounts in the consolidated balance sheet as of January 31, 2014, and in our consolidated statement of operations for the years ended January 31, 2014 and 2013, have been reclassified to conform to the financial statement presentation for the period ended January 31, 2015. The balance sheet reclassifications relate to changes in the captions presented in the balance sheet. The statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported. | ||||||||||
Segment_Reporting
Segment Reporting | 12 Months Ended | |||||||||||||||
Jan. 31, 2015 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Segment Reporting | 3. SEGMENT REPORTING | |||||||||||||||
We conduct our operations within two reportable operating segments. We identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States. The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas. The Oilfield Services segment, consisting of RockPile, is responsible for a variety of oilfield and complementary services for both Triangle-operated wells and wells operated by third-parties. Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments. Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. | ||||||||||||||||
Management evaluates the performance of our segments based upon net income (loss) before income taxes. The following tables present selected financial information for our operating segments for the years ended January 31, 2015, 2014, and 2013. | ||||||||||||||||
For the Year Ended January 31, 2015 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 284,502 | $ | — | $ | — | $ | — | $ | 284,502 | ||||||
Oilfield services for third parties | — | 294,526 | — | -6,073 | 288,453 | |||||||||||
Intersegment revenues | — | 123,577 | — | -123,577 | — | |||||||||||
Total revenues | 284,502 | 418,103 | — | -129,650 | 572,955 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 55,477 | — | — | — | 55,477 | |||||||||||
Gathering, transportation and processing | 18,520 | — | — | — | 18,520 | |||||||||||
Depreciation and amortization | 116,633 | 22,008 | 921 | -15,507 | 124,055 | |||||||||||
Accretion of asset retirement obligations | 167 | — | — | — | 167 | |||||||||||
Cost of oilfield services | — | 301,142 | 308 | -84,854 | 216,596 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 6,028 | 14,620 | 11,559 | — | 32,207 | |||||||||||
Stock-based compensation | 1,155 | 509 | 6,255 | — | 7,919 | |||||||||||
Other general and administrative | 9,042 | 10,598 | 2,991 | — | 22,631 | |||||||||||
Total operating expenses | 207,022 | 348,877 | 22,034 | -100,361 | 477,572 | |||||||||||
Income (loss) from operations | 77,480 | 69,226 | -22,034 | -29,289 | 95,383 | |||||||||||
Other income (expense), net | 51,216 | -3,024 | -2,356 | -2,322 | 43,514 | |||||||||||
Net income (loss) before income taxes | $ | 128,696 | $ | 66,202 | $ | -24,390 | $ | -31,611 | $ | 138,897 | ||||||
As of January 31, 2015: | ||||||||||||||||
Net oil and natural gas properties | $ | 1,200,872 | $ | — | $ | — | $ | -74,782 | $ | 1,126,090 | ||||||
Oilfield services equipment - net | $ | — | $ | 87,549 | $ | — | $ | — | $ | 87,549 | ||||||
Other property and equipment - net | $ | 9,679 | $ | 22,246 | $ | 15,442 | $ | — | $ | 47,367 | ||||||
Total assets | $ | 1,408,768 | $ | 202,649 | $ | 131,649 | $ | -88,196 | $ | 1,654,870 | ||||||
Total liabilities | $ | 754,925 | $ | 163,987 | $ | 204,354 | $ | -13,414 | $ | 1,109,852 | ||||||
For the Year Ended January 31, 2014 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 160,548 | $ | — | $ | — | $ | — | $ | 160,548 | ||||||
Oilfield services for third parties | — | 102,606 | — | -4,407 | 98,199 | |||||||||||
Intersegment revenues | — | 91,019 | — | -91,019 | — | |||||||||||
Total revenues | 160,548 | 193,625 | — | -95,426 | 258,747 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 32,460 | — | — | — | 32,460 | |||||||||||
Gathering, transportation and processing | 4,302 | — | — | — | 4,302 | |||||||||||
Depreciation and amortization | 56,788 | 8,905 | 620 | -8,302 | 58,011 | |||||||||||
Accretion of asset retirement obligations | 56 | — | — | — | 56 | |||||||||||
Cost of oilfield services | — | 142,339 | — | -60,012 | 82,327 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 3,541 | 6,894 | 6,864 | — | 17,299 | |||||||||||
Stock-based compensation | 1,127 | 590 | 6,113 | — | 7,830 | |||||||||||
Other general and administrative | 3,939 | 4,222 | 1,339 | — | 9,500 | |||||||||||
Total operating expenses | 102,213 | 162,950 | 14,936 | -68,314 | 211,785 | |||||||||||
Income (loss) from operations | 58,335 | 30,675 | -14,936 | -27,112 | 46,962 | |||||||||||
Other income (expense), net | -172 | -991 | 38,998 | -3,376 | 34,459 | |||||||||||
Net income (loss) before income taxes | $ | 58,163 | $ | 29,684 | $ | 24,062 | $ | -30,488 | $ | 81,421 | ||||||
As of January 31, 2014: | ||||||||||||||||
Net oil and natural gas properties | $ | 725,958 | $ | — | $ | — | $ | -43,171 | $ | 682,787 | ||||||
Oilfield services equipment - net | $ | — | $ | 46,585 | $ | — | $ | — | $ | 46,585 | ||||||
Other property and equipment - net | $ | 1,594 | $ | 18,912 | $ | 4,001 | $ | — | $ | 24,507 | ||||||
Total assets | $ | 816,282 | $ | 126,114 | $ | 148,438 | $ | -63,312 | $ | 1,027,522 | ||||||
Total liabilities | $ | 318,875 | $ | 64,017 | $ | 141,609 | $ | -20,141 | $ | 504,360 | ||||||
For the Year Ended January 31, 2013 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 39,614 | $ | — | $ | — | $ | — | $ | 39,614 | ||||||
Oilfield services for third parties | — | 22,535 | — | -1,788 | 20,747 | |||||||||||
Intersegment revenues | — | 34,672 | — | -34,672 | — | |||||||||||
Total revenues | 39,614 | 57,207 | — | -36,460 | 60,361 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 8,058 | — | — | — | 8,058 | |||||||||||
Gathering, transportation and processing | 150 | — | — | — | 150 | |||||||||||
Depreciation and amortization | 13,578 | 2,857 | 378 | -1,732 | 15,081 | |||||||||||
Accretion of asset retirement obligations | 184 | — | — | — | 184 | |||||||||||
Cost of oilfield services | — | 39,534 | — | -22,928 | 16,606 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 4,367 | 8,422 | 1,959 | — | 14,748 | |||||||||||
Stock-based compensation | 2,507 | 617 | 3,342 | — | 6,466 | |||||||||||
Other general and administrative | 2,223 | 2,708 | 2,398 | — | 7,329 | |||||||||||
Total operating expenses | 31,067 | 54,138 | 8,077 | -24,660 | 68,622 | |||||||||||
Income (loss) from operations | 8,547 | 3,069 | -8,077 | -11,800 | -8,261 | |||||||||||
Other income (expense), net | -6,318 | 4 | 974 | -883 | -6,223 | |||||||||||
Net income (loss) before income taxes | $ | 2,229 | $ | 3,073 | $ | -7,103 | $ | -12,683 | $ | -14,484 | ||||||
As of January 31, 2013: | ||||||||||||||||
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 assets | $ | 362,878 | $ | 38,668 | $ | 40,220 | $ | -13,445 | $ | 428,321 | ||||||
Total liabilities | $ | 91,134 | $ | 11,845 | $ | 125,364 | $ | -1,645 | $ | 226,698 | ||||||
Certain income statement reclassifications were made as previously noted and to reflect the Exploration and Production depreciation and amortization expense gross rather than net of consolidating eliminations. | ||||||||||||||||
Eliminations and Other. For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs. | ||||||||||||||||
Under the full cost method of accounting, we deferred recognition of approximately an additional $123.6 million, $91.0 million and $34.7 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, and approximately $6.1 million, $4.4 million, and $1.8 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, associated with our non-operating partners’ share of costs charged by RockPile for well completion activities on properties we operate, by charging such oilfield services income against oilfield services revenue and crediting proved oil and natural gas properties. | ||||||||||||||||
In addition, we deferred approximately $1.3 million and $2.2 million of Caliber gross profit from our share of its income for the years ended January 31, 2015 and 2014, respectively, associated with services it provided which were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties. | ||||||||||||||||
The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced. | ||||||||||||||||
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||
Jan. 31, 2015 | |||||||
Long-Term Debt [Abstract] | |||||||
Long-term Debt | 4. LONG-TERM DEBT | ||||||
As of January 31, 2015 and 2014, respectively, the Company’s long-term debt consisted of the following: | |||||||
For the Years Ended January 31, | |||||||
2015 | 2014 | ||||||
5% convertible note | $ | 135,877 | $ | 129,290 | |||
TUSA credit facility due October 2018 | 119,272 | 183,000 | |||||
RockPile credit facility due March 2019 | 104,887 | 21,515 | |||||
TUSA 6.75% notes due July 2022 | 429,500 | — | |||||
Other notes and mortgages payable | 10,605 | 9,403 | |||||
Total debt | 800,141 | 343,208 | |||||
Less current portion of debt: | |||||||
RockPile credit facility | — | -8,450 | |||||
Other notes and mortgages payable | -503 | -401 | |||||
Total long-term debt | $ | 799,638 | $ | 334,357 | |||
Convertible Note. On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”) that became convertible after November 16, 2012 into the Company’s 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 is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after October 31, 2017, the Company has the option to make such interest payments in cash. As of January 31, 2015, $15.9 million of accrued interest has been added to the principal balance of the Convertible Note. | |||||||
TUSA Credit Facility. On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates. On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. As of November 25, 2014, the borrowing base was set by the lenders at $435.0 million. The TUSA credit facility has a maturity date of October 16, 2018. | |||||||
Borrowings under the TUSA credit facility bear interest, at TUSA’s option, at either (i) the adjusted base rate (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.50%, or (C) the one month eurodollar rate (as defined in the agreement) plus 1%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base. | |||||||
The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by the beginning of each May 1st and November 1st. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If at any time the borrowing base is less than the amount of outstanding credit exposure under the TUSA credit facility, TUSA will be required to (i) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (ii) pledge additional collateral, (iii) prepay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). TUSA will pay a per annum fee on all letters of credit issued under the TUSA credit facility, which fee will equal the applicable margin for loans accruing interest based on the eurodollar rate and a fronting fee to the issuing lender equal to the greater of 0.125% of the letter of credit amount and $500 per letter of credit. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA credit facility are guaranteed by TUSA’s domestic subsidiaries, but Triangle is not a guarantor. | |||||||
The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities and consolidated debt to consolidated EBITDAX. As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA credit facility. | |||||||
RockPile Credit Facility. On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility. On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. The RockPile credit facility has a maturity date of March 25, 2019. | |||||||
Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter. | |||||||
RockPile will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile will also pay a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. Triangle is not a guarantor under the RockPile credit facility. | |||||||
The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges. Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures. As of January 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility. | |||||||
TUSA 6.75% Notes. On July 18, 2014, TUSA entered into an Indenture (the “Indenture”) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of TUSA 6.75% Notes due 2022 (the ”TUSA 6.75% Notes”). | |||||||
The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act. The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014. The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. | |||||||
The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.5 million of offering costs which have been deferred and are being recognized on the effective interest method over the life of the notes. | |||||||
TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture. On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at a specified redemption price set forth in the Indenture plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date. | |||||||
The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market. In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million. TUSA immediately retired the repurchased notes and recognized a gain on extinguishment of debt of $6.6 million. | |||||||
The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any guarantor subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets. These covenants are subject to a number of important exceptions and qualifications. As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes. | |||||||
Second Lien Credit Facility. On June 27, 2014, TUSA entered into a Second Lien Credit Agreement, which provided for a $60.0 million second priority secured credit facility, which was funded at signing. All borrowings under the second lien credit facility were scheduled to mature on October 16, 2019 (nine months after the maturity of the TUSA credit facility). Borrowings under the second lien credit facility bore interest, at our option, at either (i) LIBOR (subject to a floor) plus a margin of 7.0% or (ii) a base rate (subject to a floor) plus a margin of 6.0%. The second lien credit facility also provided that no prepayment fees would be payable for prepayments made during the first twelve months. | |||||||
Upon issuance of the TUSA 6.75% Notes on July 18, 2014, TUSA terminated the second lien credit facility and repaid all amounts owing thereunder. | |||||||
Future Maturities of Outstanding Debt. Scheduled annual maturities of long-term debt outstanding as of January 31, 2015 were as follows: | |||||||
For the Years Ending January 31, (in thousands): | |||||||
2016 | $ | 503 | |||||
2017 | 1,450 | ||||||
2018 | 1,594 | ||||||
2019 | 119,852 | ||||||
2020 | 105,565 | ||||||
Thereafter | 571,177 | ||||||
$ | 800,141 | ||||||
Hedging_And_Commodity_Derivati
Hedging And Commodity Derivative Financial Instruments | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Commodity Derivative Instruments [Abstract] | |||||||||||||
Commodity Derivative Instruments | 5. HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS | ||||||||||||
Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price, and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. | |||||||||||||
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with three counterparties. The Company has netting arrangements with each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. | |||||||||||||
The Company’s commodity derivative instruments are measured at fair value. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on derivative activities are recorded in the commodity derivatives gains (losses) caption on the consolidated statements of operations. The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. | |||||||||||||
The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows (in thousands): | |||||||||||||
For the Years Ended January 31, | |||||||||||||
2015 | 2014 | 2013 | |||||||||||
Realized commodity derivative gains (losses) | $ | 11,422 | $ | -4,643 | $ | - | |||||||
Unrealized commodity derivative gains (losses) | 52,628 | 5,725 | -3,570 | ||||||||||
Commodity derivative gains (losses), net | $ | 64,050 | $ | 1,082 | $ | -3,570 | |||||||
The Company’s commodity derivative contracts as of January 31, 2015 are summarized below: | |||||||||||||
Contract | Quantity | Weighted Average | Weighted Average | ||||||||||
Term End Date | Type | Basis (1) | (Bbl/d) | Put Strike | Call Strike | ||||||||
Fiscal Year 2016 | Collar | NYMEX | 4,356 | $86.85 | $98.63 | ||||||||
-1 | “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange. | ||||||||||||
Subsequent to January 31, 2015, the Company entered into crude oil swaps for 1,500 Bbl/d at a weighted average price of $60.07 per barrel effective for the period from October 1, 2015 through December 31, 2016, and crude oil swaps for 500 Bbl/d at a weighted average price of $60.30 per barrel, effective for the period from January 1, 2016 through December 31, 2016. | |||||||||||||
The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and 2014 are summarized below. The net fair value of the Company’s commodity derivatives changed by $60.1 million from a net asset of $2.1 million at January 31, 2014 to a net asset of $62.2 million at January 31, 2015, primarily due to (i) changes in the futures prices for oil, which are used in the calculation of the fair value of commodity derivatives, (ii) settlement of commodity derivative positions during the current period and (iii) changes to the Company’s commodity derivative portfolio in fiscal year 2015. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company’s derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not designated any of its derivative contracts as cash-flow hedging instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented (in thousands). | |||||||||||||
For the Years Ended January 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Current Assets: | |||||||||||||
Crude oil derivative contracts | $ | 62,248 | $ | 955 | |||||||||
Other Long-Term Assets: | |||||||||||||
Crude oil derivative contracts | — | 1,192 | |||||||||||
Total derivative asset | $ | 62,248 | $ | 2,147 | |||||||||
Oil_And_Natural_Gas_Properties
Oil And Natural Gas Properties | 12 Months Ended | |||||||||||||||
Jan. 31, 2015 | ||||||||||||||||
Oil And Natural Gas Properties [Abstract] | ||||||||||||||||
Oil And Natural Gas Properties | 6. OIL AND NATURAL GAS PROPERTIES | |||||||||||||||
The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States for years ended January 31, 2015, 2014, and 2013: | ||||||||||||||||
For the Years Ended January 31, | ||||||||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||||||||
Costs incurred during the period | ||||||||||||||||
Acquisition of properties: | ||||||||||||||||
Proved | $ | 90,920 | $ | 80,201 | $ | 623 | ||||||||||
Unproved | 47,858 | 41,377 | 20,570 | |||||||||||||
Exploration | 180,174 | 96,731 | 55,583 | |||||||||||||
Development | 226,765 | 216,046 | 91,666 | |||||||||||||
Oil and natural gas expenditures | 545,717 | 434,355 | 168,442 | |||||||||||||
Asset retirement obligations, net | 1,818 | 676 | 370 | |||||||||||||
$ | 547,535 | $ | 435,031 | $ | 168,812 | |||||||||||
During fiscal years 2015, 2014, and 2013, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $545.7 million, $434.4 million, and $168.4 million, including $138.8 million, $121.6 million, and $21.2 million, respectively, for the acquisition of oil and natural gas properties. Total consideration paid includes common stock of $2.4 million and $1.2 million for fiscal years 2014 and 2013, respectively. During fiscal years 2015, 2014, and 2013, we capitalized $4.8 million, $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 properties. | ||||||||||||||||
The following table summarizes oil and natural gas property costs not being amortized at January 31, 2015, by year that the costs were incurred: | ||||||||||||||||
Fiscal Year Costs Incurred | ||||||||||||||||
2012 | ||||||||||||||||
(in thousands) | Total | 2015 | 2014 | 2013 | and prior | |||||||||||
Acquisition | $ | 113,606 | $ | 46,982 | $ | 25,785 | $ | 10,220 | $ | 30,619 | ||||||
Exploration | 22,305 | 20,830 | 1,475 | — | — | |||||||||||
Capitalized interest | 6,985 | 4,899 | 2,086 | — | — | |||||||||||
Total | $ | 142,896 | $ | 72,711 | $ | 29,346 | $ | 10,220 | $ | 30,619 | ||||||
The $142.9 million of costs not being amortized includes $17.1 million in costs for unevaluated wells in progress expected to be completed prior to January 31, 2016. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization. The majority of the unproved oil and natural gas property costs, which are not subject to amortization, relate to oil and natural gas property acquisitions and leasehold acquisition costs as well as work-in-progress on various projects. The Company expects that substantially all of its unproved property costs as of January 31, 2015 will be reclassified to proved properties over the next five years. | ||||||||||||||||
Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2015, 2014, and 2013 was $106.9 million, $51.0 million and $13.5 million, respectively. | ||||||||||||||||
Acquisitions
Acquisitions | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Acquisitions [Abstract] | ||||||||||
Acquisitions | 7. ACQUISITIONS | |||||||||
Kodiak Oil & Gas Property Acquisition. In August 2013, TUSA acquired interests in approximately 5,600 net acres of leaseholds and related producing properties along with various other related rights, permits, contracts, equipment and other assets, all located in McKenzie County, North Dakota, from Kodiak Oil & Gas Corporation (“Kodiak”). We paid approximately $83.8 million in cash. In addition, the Company and Kodiak also agreed to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’s operated units for approximately 600 net acres of leasehold interests held by Kodiak in units then operated by the Company. The effective date for the acquisition and the exchange was July 1, 2013. | ||||||||||
Marathon Oil & Gas Property Acquisition. In June 2014, we acquired from Marathon Oil Company (“Marathon”) certain oil and natural gas leaseholds and related producing properties located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,100 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $90.4 million in cash, net of certain closing adjustments of $9.6 million. Transaction costs related to the acquisition incurred during the year ended January 31, 2015 of approximately $1.3 million are recorded in general and administrative expenses. | ||||||||||
The acquisitions were accounted for using the acquisition method under ASC-805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of June 30, 2014. The following table summarizes the purchase price and the estimated values of assets acquired and liabilities assumed: | ||||||||||
Purchase price (in thousands): | ||||||||||
Cash | $ | 90,352 | ||||||||
Total consideration given | $ | 90,352 | ||||||||
Fair value allocation of purchase price: | ||||||||||
Oil and natural gas properties: | ||||||||||
Proved properties | $ | 71,044 | ||||||||
Unproved properties | 20,262 | |||||||||
Total oil and natural gas properties | 91,306 | |||||||||
Accounts payable | -469 | |||||||||
Asset retirement obligations assumed | -485 | |||||||||
Fair value of net assets acquired | $ | 90,352 | ||||||||
Pro Forma Financial Information. The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak, in August of 2013, and Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2012. | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands, except per share data) | 2015 | 2014 | 2013 | |||||||
Operating revenues | $ | 584,696 | $ | 312,081 | $ | 92,933 | ||||
Net income (loss) | $ | 96,438 | $ | 91,579 | $ | -2,407 | ||||
Earnings (loss) per common share | ||||||||||
Basic | $ | 1.15 | $ | 1.22 | $ | -0.04 | ||||
Diluted | $ | 1.00 | $ | 1.04 | $ | -0.04 | ||||
Weighted average common shares outstanding: | ||||||||||
Basic | 83,611 | 75,047 | 55,794 | |||||||
Diluted | 101,032 | 91,026 | 55,794 | |||||||
For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012. The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.4 million, $16.5 million and $12.6 million for fiscal years 2015, 2014 and 2013, respectively. The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common stock had been issued, as of the beginning of the period, nor are they necessarily indicative of future results. | ||||||||||
Acquisition of Team Well Service, Inc. In October 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 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, 2015 | |||||||
Asset Retirement Obligations [Abstract] | |||||||
Asset Retirement Obligations | 8. ASSET RETIREMENT OBLIGATIONS | ||||||
The Company’s asset retirement obligations (“ARO”) represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate producing and shut-in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. | |||||||
The following tables reflect the change in ARO for the years ended January 31, 2015 and 2014: | |||||||
For the Years Ended January 31, | |||||||
(in thousands) | 2015 | 2014 | |||||
Balance at the beginning of the period | $ | 4,629 | $ | 3,422 | |||
Liabilities incurred | 1,821 | 944 | |||||
Revision of estimates | 2,737 | 774 | |||||
Sale of assets | -29 | -83 | |||||
Liabilities settled | -747 | -484 | |||||
Accretion | 167 | 56 | |||||
Balance at the end of the period | 8,578 | 4,629 | |||||
Less current portion of obligations | -5,391 | -3,333 | |||||
Long-term ARO | $ | 3,187 | $ | 1,296 | |||
The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets. | |||||||
A significant portion of the current obligations relates to the reclamation of man-made ponds holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada of $4.8 million and $2.0 million as of January 31, 2015 and January 31, 2014, respectively. Internal engineering re-assessment of Canadian ARO resulted in revisions $2.7 million and $1.0 million to the ARO during fiscal years 2015 and 2014. Since our Canadian oil and natural gas properties were fully impaired, the ARO revisions were expensed and included in depreciation and amortization expenses in the accompanying consolidated statements of operations for the years ended January 31, 2015 and 2014, respectively. | |||||||
Equity_Investment_And_Equity_I
Equity Investment And Equity Investment Derivatives | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Equity Investment [Abstract] | ||||||||||
Equity Investment | 9. EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES | |||||||||
Equity Investment. On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly-owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly-owned subsidiary of FREIF. The joint venture entity, Caliber, was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. | ||||||||||
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 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 FREIF Caliber Holdings agreed to contribute $70.0 million to Caliber in exchange for 7,000,000 Class A Units, with the general partner of Caliber being 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 Trigger Units into 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 on June 30, 2014 did 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 converted to 1,600,000 Series 1 Warrants on June 30, 2014 with an exercise price of $14.69. | ||||||||||
Following the issuance of the additional 8,000,000 Class A Units to FREIF Caliber Holdings and the conversion by Triangle Caliber Holdings of its 4,000,000 Class A Trigger Units into 4,000,000 Class A Units, FREIF Caliber Holdings owned 15,000,000 Class A Units, representing an approximate sixty-eight percent (68%) limited partner interest in Caliber, and Triangle Caliber Holdings owned 7,000,000 Class A Units, representing an approximate thirty-two percent (32%) limited partner interest in Caliber. | ||||||||||
The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and 2014 and the strike prices for exercising warrants as of January 31, 2015: | ||||||||||
Expiration | Strike Price at | As of January 31, | ||||||||
Date | 31-Jan-15 | 2015 | 2014 | |||||||
Class A Units | — | — | 7,000,000 | 3,000,000 | ||||||
Class A Trigger Units | — | — | — | 4,000,000 | ||||||
Class A Trigger Unit Warrants | — | — | — | 1,600,000 | ||||||
Series 1 Warrants | 1-Oct-24 | $ | 12.78 | 5,600,000 | 4,000,000 | |||||
Series 2 Warrants | 1-Oct-24 | $ | 22.09 | 2,400,000 | 2,400,000 | |||||
Series 3 Warrants | 12-Sep-25 | $ | 22.09 | 3,000,000 | 3,000,000 | |||||
Series 4 Warrants | 12-Sep-25 | $ | 28.09 | 2,000,000 | 2,000,000 | |||||
The Company’s investment interest in Caliber is considered to be variable, and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk. The Company is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to its economic performance. Under the equity method, our investment will be adjusted each period for contributions made, distributions received, the change in the fair value of our holdings of equity investment derivatives of Caliber, our share of Caliber’s net income and accretion of any basis differences. Our maximum exposure to loss related to Caliber is limited to our equity investment. We evaluate our equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. | ||||||||||
The following summarizes the activities related to the Company’s equity investment in Caliber for the years ended January 31, 2015 and 2014: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Balance at beginning of year | $ | 68,536 | $ | 11,768 | ||||||
Capital contributions | — | 18,000 | ||||||||
Distributions | -6,080 | -3,150 | ||||||||
Equity investment share of net income before intra-company profit eliminations | 1,402 | 2,184 | ||||||||
Change in fair value of: | ||||||||||
Class A Trigger Units (1) | 1,745 | 38,091 | ||||||||
Class A Trigger Unit Warrants (2) | 532 | 234 | ||||||||
Series 1 Warrants | -1,241 | 926 | ||||||||
Series 2 Warrants | -254 | 254 | ||||||||
Series 3 Warrants | -207 | 207 | ||||||||
Series 4 Warrants | -22 | 22 | ||||||||
Total changes in fair value | 553 | 39,734 | ||||||||
Balance at end of year | $ | 64,411 | $ | 68,536 | ||||||
Fair value of trigger unit warrants and warrants at end of year | $ | 504 | $ | 39,734 | ||||||
-1 | The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014. | |||||||||
-2 | On June 30, 2014, the 1,600,000 Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding. | |||||||||
Equity Investment Derivatives. At January 31, 2015 and 2014, the Company held Class A (Series 1 through Series 4) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued using the following valuation techniques, which are generally less observable from objective sources. | ||||||||||
At each period end, the fair value of the Class A (Series 1 through Series 4) Warrants were estimated using a Monte Carlo Simulation (“MCS”) model. An MCS model provides a numeric approach to stochastic stock movement to forecast the future price of the underlying Class A Units, as opposed to an analytic solution provided by Black-Scholes. For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis. The resulting value represented a marketable minority value of Caliber. As the Class A Units represent a non-marketable equity interest in a private enterprise, an adjustment to our preliminary value estimates was made to account for the lack of liquidity. | ||||||||||
The MCS model assumed that the Class A Warrants would be exercised at the earlier of (a) the contractual life of 12 years, and (b) the point at which the exercise price would be reduced to $5.00 per warrant (at which point it would be advantageous for Triangle to exercise early to capture future distributions on the Class A Units). The key inputs to the MCS model are the same as the Black-Scholes model previously used including 10-year historical volatilities for publicly-traded comparable companies, risk-free interest rates over the expected warrant term and dividend yields based on expected distributions. The change in fair value during the years ended January 31, 2015 and 2014 resulted in a $0.6 million and $39.8 million increase, respectively, in our equity investment account and as a gain on equity investment derivatives. Also included in the gain on equity investment derivatives during the year ended January 31, 2015 was a gain of $1.7 million associated with the change in fair value of the 4,000,000 million Class A Trigger Units which vested on June 30, 2014. | ||||||||||
On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF. In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF, and the general partner of Caliber, owned and controlled equally between Triangle Caliber Holdings and FREIF. Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units. FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015. Triangle made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units. Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber. Triangle will recognize a gain in the first quarter of fiscal year 2016 of $4.2 million related to Caliber’s issuance of these 2,720,000 Class A Units to FREIF. | ||||||||||
Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants for the purchase of an additional 906,667 Class A Units. The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Series 1 through 4 warrants at strike prices and expiration dates noted above and 1,269,333 Series 6 warrants with a strike price of $12.50 and an expiration date of February 2, 2018. Triangle will also recognize a gain of $0.2 million in the first quarter of fiscal year 2016 related to the fair value of the warrants issued, which will be amortized over the lives of the related warrants. | ||||||||||
Capital_Stock
Capital Stock | 12 Months Ended |
Jan. 31, 2015 | |
Share-Based Compensation [Abstract] | |
Capital Stock | 10. CAPITAL STOCK |
The Company had 106.4 million shares of common stock issued or reserved for issuance at January 31, 2015. At January 31, 2015, the Company had 75.2 million shares of common stock issued and outstanding. The Company also had 3.6 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and its 2014 Equity Incentive Plan (the “2014 Plan”). The Company also had 4.6 million shares of common stock reserved that remained available for issuance under the 2014 Plan, as well as 6.0 million shares of common stock reserved for issuance under the CEO Stand-Alone Stock Option Agreement. Lastly, the Company had 17.0 million shares of common stock reserved for issuance pursuant to the Convertible Note at January 31, 2015. | |
The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. During fiscal year 2015, the Company repurchased an aggregate of 11.4 million shares of the Company’s common stock under the program at a total cost of $76.8 million. The repurchased shares of common stock were immediately retired and charged to available retained earnings with the balance charged to additional paid-in capital. As of January 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program is 4,949,393 shares. | |
ShareBased_Compensation
Share-Based Compensation | 12 Months Ended | ||||||||||
Jan. 31, 2015 | |||||||||||
Share-Based Compensation [Abstract] | |||||||||||
Share-Based Compensation | 11. SHARE-BASED COMPENSATION | ||||||||||
The Company has granted equity awards to officers, directors, and certain employees of the Company including restricted stock units and stock options. In addition, RockPile has granted Series B Units which represent interests in future RockPile profits. The Company measures its awards based on the award’s grant date fair value which is recognized ratably over the applicable vesting period. | |||||||||||
On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions. The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions. | |||||||||||
For the years ended January 31, 2015, 2014, and 2013, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows: | |||||||||||
For the Years Ended January 31, | |||||||||||
(in thousands) | 2015 | 2014 | 2013 | ||||||||
Restricted stock units | $ | 6,254 | $ | 7,496 | $ | 6,639 | |||||
Stock options | 2,299 | 1,135 | 60 | ||||||||
Stock issued pursuant to termination agreements | — | — | 99 | ||||||||
RockPile Series B Units | 509 | 590 | 617 | ||||||||
9,062 | 9,221 | 7,415 | |||||||||
Less amounts capitalized to oil and natural gas properties | -1,143 | -1,391 | -949 | ||||||||
Compensation expense | $ | 7,919 | $ | 7,830 | $ | 6,466 | |||||
Restricted Stock Units. During the year ended January 31, 2015, the Company granted 1,523,700 restricted stock units as compensation to employees, officers, and directors. Restricted stock units vest over one to five years. As of January 31, 2015, there was approximately $19.8 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 4.0 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. | |||||||||||
The following table summarizes the status of restricted stock units outstanding: | |||||||||||
Weighted- | |||||||||||
Number of | Average Award | ||||||||||
Shares | Date Fair Value | ||||||||||
Restricted stock units outstanding - January 31, 2012 | 2,488,342 | $ | 7.02 | ||||||||
Units granted | 1,041,400 | $ | 6.37 | ||||||||
Units forfeited | -5,600 | $ | 7.59 | ||||||||
Units vested | -1,000,057 | $ | 6.90 | ||||||||
Restricted stock units outstanding - January 31, 2013 | 2,524,085 | $ | 6.68 | ||||||||
Units granted | 1,440,133 | $ | 6.95 | ||||||||
Units forfeited | -141,909 | $ | 6.58 | ||||||||
Units vested | -946,681 | $ | 6.71 | ||||||||
Restricted stock units outstanding - January 31, 2014 | 2,875,628 | $ | 6.62 | ||||||||
Units granted | 1,523,700 | $ | 9.42 | ||||||||
Units forfeited | -394,921 | $ | 7.21 | ||||||||
Units vested | -1,090,362 | $ | 7.04 | ||||||||
Restricted stock units outstanding - January 31, 2015 | 2,914,045 | $ | 7.92 | ||||||||
Stock Options. The following table summarizes the status of stock options outstanding: | |||||||||||
Weighted | |||||||||||
Number of | Average | ||||||||||
Shares | Exercise Price | ||||||||||
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 | ||||||||
Options forfeited | — | $ | — | ||||||||
Options exercised | -108,333 | $ | 1.25 | ||||||||
Options granted | 700,000 | $ | 14.00 | ||||||||
Options outstanding - January 31, 2015 (600,000 exercisable) | 6,700,000 | $ | 11.54 | ||||||||
The following table presents additional information related to the stock options outstanding at January 31, 2015: | |||||||||||
Remaining | |||||||||||
Exercise Price | Contractual Life | Number of Shares | |||||||||
per Share | (years) | Outstanding | Exercisable | ||||||||
$ | 7.50 | 8.43 | 750,000 | 75,000 | |||||||
$ | 8.50 | 8.43 | 750,000 | 75,000 | |||||||
$ | 10.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 12.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 15.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 12.00 | 6.61 | 233,333 | — | |||||||
$ | 14.00 | 6.61 | 233,333 | — | |||||||
$ | 16.00 | 9.61 | 233,334 | — | |||||||
6,700,000 | 600,000 | ||||||||||
Weighted average exercise price per share | $ | 11.54 | $ | 11.25 | |||||||
Weighted average remaining contractual life | 8.34 | 8.43 | |||||||||
Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatility is generally based on the historical volatility of Triangle’s common stock. The expected term of the options is estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rate for the expected term (from service inception to option exercise) of the options is based on the yields of U.S. Treasury instruments with lives comparable to the estimated expected option term or life. | |||||||||||
The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the options granted in fiscal year 2015: | |||||||||||
Risk free rate | 1.06 | % | |||||||||
Dividend yield | — | ||||||||||
Expected volatility | 54 | % | |||||||||
Weighted average expected stock option life (years) | 3.0 | ||||||||||
As of January 31, 2015, there was approximately $18.6 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.3 years. | |||||||||||
RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units which have an 8% preference and Series B Units, which are used for equity awards. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (Series B Units) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units. | |||||||||||
The Series B Units are intended to constitute “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93‑27 and 2001‑43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be zero. RockPile may designate a “Liquidation Value” applicable to each tranche of a Series B Unit grant so as to constitute a net profits interest. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile, be distributed with respect to the initial Series B Unit tranche if, immediately prior to the issuance of a new Series B Unit tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities) were distributed. | |||||||||||
The Series A Units are entitled to a return of contributed capital and an 8% preferred return on such capital before Series B Units participate in profits. The initial Series B tranche (Series B‑1 Units) participates pro rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B‑1 Unit until total cumulative distributions to the Series A Units total $40.0 million. As of January 31, 2015, the $40.0 million cumulative distribution threshold has been met. Therefore, future distributions will be allocated to the Series B‑1 Units until the per unit profits distributed to the Series B‑1 Units is equivalent to the per unit profits distributed to the Series A Units. Thereafter, all further distributions will be distributed on a pro rata basis. Subsequently issued Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B‑1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance. RockPile’s limited liability company agreement was amended on January 31, 2015 to permit distributions to holders of vested Series B Units as prepayment for future amounts payable to them upon a RockPile liquidity event. In the event a holder of vested Series B Units receives such a pre-liquidity event distribution, their capital account will be adjusted to reflect the prepayment. | |||||||||||
Series B Units currently have a 7 to 52 month vesting schedule. Compensation costs are determined using a Black‑Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period. | |||||||||||
A summary of the activity for RockPile’s Series B Units is as follows: | |||||||||||
Series | Series | Series | Series | ||||||||
B-1 units | B-2 units | B-3 units | B-4 units | Total | |||||||
Units outstanding - January 31, 2012 | — | — | — | — | — | ||||||
Units granted | 3,100,000 | 60,000 | — | — | 3,160,000 | ||||||
Units outstanding - January 31, 2013 | 3,100,000 | 60,000 | — | — | 3,160,000 | ||||||
Units granted | — | — | 910,000 | — | 910,000 | ||||||
Units outstanding - January 31, 2014 | 3,100,000 | 60,000 | 910,000 | — | 4,070,000 | ||||||
Units redeemed | -180,000 | — | — | — | -180,000 | ||||||
Units granted | — | — | — | 1,412,000 | 1,412,000 | ||||||
Units outstanding - January 31, 2015 | 2,920,000 | 60,000 | 910,000 | 1,412,000 | 5,302,000 | ||||||
Vested | 2,920,000 | 30,000 | 188,000 | — | 3,138,000 | ||||||
Unvested | — | 30,000 | 722,000 | 1,412,000 | 2,164,000 | ||||||
As of January 31, 2015, there was approximately $2.6 million of unrecognized compensation expense related to unvested Series B Units. We expect to recognize such expense on a pro-rata basis on the Series B Units’ vesting schedule during the next five fiscal years. | |||||||||||
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||
Fair Value Measurements | 12. FAIR VALUE MEASUREMENTS | ||||||||||||
The FASB’s ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: | |||||||||||||
· | Level 1: Quoted prices are available in active markets for identical assets or liabilities; | ||||||||||||
· | Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and | ||||||||||||
· | Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations. | ||||||||||||
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. | |||||||||||||
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2015 and January 31, 2014, by level within the fair value hierarchy: | |||||||||||||
As of January 31, 2015 | |||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Equity investment derivative assets | $ | — | $ | — | $ | 504 | $ | 504 | |||||
Commodity derivative assets | $ | — | $ | 62,248 | $ | — | $ | 62,248 | |||||
Liabilities: | |||||||||||||
RockPile earn-out liability | $ | — | $ | -1,825 | $ | — | $ | -1,825 | |||||
As of January 31, 2014 | |||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Equity investment derivative assets | $ | — | $ | — | $ | 39,734 | $ | 39,734 | |||||
Commodity derivative assets | $ | — | $ | 2,147 | $ | — | $ | 2,147 | |||||
Liabilities: | |||||||||||||
RockPile earn-out liability | $ | — | $ | -1,739 | $ | — | $ | -1,739 | |||||
Commodity Derivative Instruments. The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating. In considering counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At January 31, 2015, commodity derivative instruments utilized by the Company consist of costless collars and swaps. The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange. As such, the Company has classified these commodity derivative instruments as Level 2. | |||||||||||||
Caliber Class A (Series 1 through Series 4) Warrants. The Company determines its estimate of the fair value of Caliber Class A Warrants using a MCS model. For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis. At January 31, 2015, the Company’s Caliber Class A 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. | |||||||||||||
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. | |||||||||||||
Summary of Level 3 Financial Assets and Liabilities. The following table presents the rollforward of the fair values of the Company’s Level 3 financial assets and liabilities: | |||||||||||||
Class A | |||||||||||||
Trigger | |||||||||||||
(in thousands) | Units | Warrants | |||||||||||
Balance at January 31, 2013 | $ | — | $ | — | |||||||||
Initial recognition of equity investment derivative assets | 38,091 | 1,696 | |||||||||||
Balance at January 31, 2014 | 38,091 | 1,696 | |||||||||||
Interest paid in-kind | — | — | |||||||||||
Net unrecognized loss | — | — | |||||||||||
Net unrealized gain | 1,745 | -1,192 | |||||||||||
Conversion to Class A Units | -39,836 | — | |||||||||||
Balance at January 31, 2015 | $ | — | $ | 504 | |||||||||
Fair Value of Financial Instruments. The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing. The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair value of other notes and mortgages payable is not significantly different than their carry values. The fair value of the TUSA 6.75% Notes is derived from quoted market prices. This disclosure does not impact our financial position, results of operations or cash flows. | |||||||||||||
January 31, 2015 | January 31, 2014 | ||||||||||||
Carrying | Estimated | Carrying | Estimated | ||||||||||
(in thousands) | Value | Fair Value | Value | Fair Value | |||||||||
5% convertible note | $ | 135,877 | $ | 137,790 | $ | 129,290 | $ | 169,170 | |||||
Revolving credit facilities | 224,159 | 224,159 | 204,515 | 204,515 | |||||||||
TUSA 6.75% notes | 429,500 | 303,871 | — | — | |||||||||
Other notes and mortgages payable | 10,605 | 10,605 | 9,403 | 9,403 | |||||||||
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Income Taxes [Abstract] | ||||||||||
Income Taxes | 13. INCOME TAXES | |||||||||
The Company’s income tax provision (benefit) is composed of the following: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Current tax expense (benefit) | $ | — | $ | — | $ | — | ||||
Deferred tax expense (benefit) | ||||||||||
Federal | 42,400 | 7,324 | -2,137 | |||||||
State | 3,100 | 617 | -223 | |||||||
Foreign | — | — | -83 | |||||||
Valuation allowance - United States and Canada | — | — | 2,443 | |||||||
Total income tax provision (benefit) | $ | 45,500 | $ | 7,941 | $ | — | ||||
Income (loss) before income taxes | $ | 138,897 | $ | 81,421 | $ | -14,484 | ||||
Effective income tax rate | 33% | 10% | 0% | |||||||
A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35.0% to the Company’s income tax provision (benefit) is as follows: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Federal statutory tax expense (benefit) | $ | 48,613 | $ | 28,498 | $ | -5,069 | ||||
State income tax expense / (benefit), net of federal income tax benefit | 3,618 | 2,324 | -361 | |||||||
Permanent differences | 3,196 | 3,221 | 2,280 | |||||||
Difference in foreign tax rates | 539 | 164 | 28 | |||||||
Effect of tax rate change | -147 | -258 | -71 | |||||||
Credits | -338 | -100 | — | |||||||
State NOL adjustment | 1,061 | — | — | |||||||
Bad debt deduction for receivables from Elmworth | -14,517 | — | — | |||||||
Attribute reduction - cancellation of debt exclusion - Elmworth | 8,466 | — | — | |||||||
Changes in valuation allowance | -7,464 | -26,364 | 2,443 | |||||||
Other | 2,473 | 456 | 750 | |||||||
Provision for income taxes | $ | 45,500 | $ | 7,941 | $ | — | ||||
The difference in foreign tax rate of $0.5 million in fiscal year 2015 is a result of adjusting the U.S. blended statutory tax rate of 37.6% down to the Canadian statutory tax rate of 25.0%. | ||||||||||
The components of Triangle’s net deferred income tax assets and liabilities are as follows for fiscal years 2015 and 2014: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Current: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | $ | 1,394 | $ | 1,071 | ||||||
Accruals | 1,138 | 103 | ||||||||
Total current assets | 2,532 | 1,174 | ||||||||
Valuation allowance | -1,193 | -492 | ||||||||
Total current assets after valuation allowance | 1,339 | 682 | ||||||||
Liabilities: | ||||||||||
Hedging liabilities | -20,806 | -361 | ||||||||
Total current liabilities | -20,806 | -361 | ||||||||
Net current deferred income tax asset (liability) | $ | -19,467 | $ | 321 | ||||||
Non-Current: | ||||||||||
Assets: | ||||||||||
Canadian oil and natural gas properties | $ | — | $ | 6,080 | ||||||
United States net losses carried forward | 48,443 | 33,129 | ||||||||
Canadian net losses carried forward | — | 1,905 | ||||||||
Asset retirement obligations | 1,198 | 416 | ||||||||
Stock-based compensation | 3,182 | 3,105 | ||||||||
Property and equipment | — | 157 | ||||||||
Other | 2,395 | 1,864 | ||||||||
Total non-current assets | 55,218 | 46,656 | ||||||||
Valuation allowance | — | -8,165 | ||||||||
Total non-current assets after valuation allowance | 55,218 | 38,491 | ||||||||
Liabilities: | ||||||||||
United States oil and natural gas properties | -56,531 | -29,536 | ||||||||
Investment in Caliber | -32,661 | -16,766 | ||||||||
Hedging liabilities | — | -451 | ||||||||
Total deferred non-current income tax liability | -89,192 | -46,753 | ||||||||
Net non-current deferred income tax liability | $ | -33,974 | $ | -8,262 | ||||||
Total net deferred income tax liability | $ | -53,441 | $ | -7,941 | ||||||
As of fiscal year 2013 the Company placed a full valuation allowance against deferred income taxes. During the year ended January 31, 2014, Triangle had determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized. Therefore, all deferred tax benefits were recognized in fiscal year 2014 and the full valuation allowance removed as part of the effective tax rate. | ||||||||||
Triangle has also determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized. Therefore, all remaining Canadian deferred tax assets will have a full valuation allowance placed against them. As a result of the cancellation of indebtedness related to the Elmworth intercompany, certain deferred tax assets and the related valuation allowance were reduced. The key negative evidence relating to the Canadian deferred tax assets considered in this determination includes the following: (i) a history of both book and tax losses; (ii) cumulative losses in recent years; (iii) an expectation of tax losses during the next four to five years. Therefore, the combination of historical/cumulative losses as well as an expectation of book and taxable losses 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 net operating loss carryovers as of January 31, 2015 of $136.9 million for federal income tax purposes and $131.1 million for financial reporting purposes. The difference of $5.8 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The United States NOL carryforwards begin expiring in 2024. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years. | ||||||||||
At January 31, 2015 and 2014, 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 2012 to 2015 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 2012 to 2015, except for Colorado which is open for the fiscal years 2011 to 2015. We also file with various Canadian taxing authorities which remain open for fiscal years 2011 to 2015. | ||||||||||
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Jan. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 14. RELATED PARTY TRANSACTIONS |
TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line. TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the 2014 in-service dates for the Caliber facilities. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $359.2 million was outstanding at January 31, 2015. | |
TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement, that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date anticipated to be in the first half of fiscal year 2016. The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water. | |
For the years ended January 31, 2015 and 2014, Caliber had $43.0 million and $15.6 million of revenue, respectively, of which $36.6 million and $15.0 million, respectively, were from TUSA. Also, TUSA sold one salt water disposal well to an affiliate of Caliber for $1.5 million in fiscal year 2015. | |
For the year ended January 31, 2015, Triangle received $0.9 million from Caliber for certain administrative services supplemental to those provided by Caliber employees. The administrative services were provided pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber. | |
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended | |||
Jan. 31, 2015 | ||||
Commitments And Contingencies [Abstract] | ||||
Commitments And Contingencies | 15. COMMITMENTS AND CONTINGENCIES | |||
Triangle has entered into non-cancelable operating leases for office facilities and Rockpile has entered into various non-cancelable operating leases relating to (i) equipment for transportation, transloading and storage bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance. Rent expense incurred under the non-cancelable operating leases was $1.8 million, $0.8 million, and $0.5 million for the fiscal years ended January 31, 2015, 2014, and 2013, respectively. | ||||
As of January 31, 2015, the future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are: | ||||
Fiscal Years Ending January 31, | Annual Rental Amount (in thousands) | |||
2016 | $ | 2,807 | ||
2017 | $ | 2,749 | ||
2018 | $ | 2,357 | ||
2019 | $ | 2,108 | ||
2020 and thereafter | $ | 2,686 | ||
As of January 31, 2015 the Company was subject to commitments on four drilling rig contracts. Two of the drilling rig contracts expire in first quarter of fiscal year 2016, and the remaining contracts expire in the second and fourth quarters of fiscal year 2016. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $10.2 million as of January 31, 2015 as required under the terms of the contracts. | ||||
CEO Transaction Bonus Program Pursuant to the Third Amended and Restated Employment Agreement, dated July 4, 2014 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its initial investment in the relevant entity (“Transaction Bonus”). The amount of this Transaction Bonus would be equivalent to 5% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the Transaction Bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. | ||||
On January 31, 2015, Triangle and Mr. Samuels entered into a First Amendment to Third Amended and Restated Employment Agreement (the “First Amendment”) that modified the Employment Agreement to permit Triangle’s Board to authorize distributions to Mr. Samuels pursuant to his Transaction Bonus program in advance of defined liquidity events. Any Board authorized distribution to Mr. Samuels related to the Transaction Bonus program would reduce any future award payable to Mr. Samuels following a liquidity event. There are no clawback provisions in the First Amendment that would require Mr. Samuels to repay Triangle for any excess distributions or payments received. | ||||
In connection with the First Amendment, the Board authorized the payment of a Transaction Bonus to Mr. Samuels of $1.9 million which has been recorded as a liability as of January 31, 2015. The payment of the Board authorized distribution will occur on the earlier of December 31, 2015 or when the WTI (NYMEX) price of oil exceeds $65 for 5 days over a consecutive 30 day period, subject to Mr. Samuel’s continuous employment with the Company through the applicable distribution date. 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, 2015, and, therefore, no amounts have been recorded in the accompanying consolidated balance sheets other than the Board authorized distribution. | ||||
Supplemental_Disclosures_Of_Ca
Supplemental Disclosures Of Cash Flow Information | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Supplemental Disclosures of Cash Flow Information [Abstract] | ||||||||||
Supplemental Disclosures of Cash Flow Information | 16. SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION | |||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Cash paid during the period for: | ||||||||||
Interest expense | $ | 19,713 | $ | 1,419 | $ | 75 | ||||
Income taxes | $ | 600 | $ | — | $ | — | ||||
Non-cash investing activities: | ||||||||||
Additions (reductions) to oil and natural gas properties through: | ||||||||||
Increased accounts payable and accrued liabilities | $ | 47,838 | $ | 30,785 | $ | 36,654 | ||||
Issuance of common stock | $ | — | $ | 2,438 | $ | 1,204 | ||||
Capitalized stock based compensation | $ | 1,143 | $ | 1,391 | $ | 949 | ||||
Change in asset retirement obligations | $ | 1,818 | $ | 673 | $ | 1,869 | ||||
Capitalized interest | $ | 4,899 | $ | 809 | $ | — | ||||
Acquisition of oilfield services equipment through notes payable and liabilities | $ | — | $ | 1,990 | $ | — | ||||
Purchase of minority interest in RockPile | $ | — | $ | — | $ | 12,349 | ||||
Non-cash financing activities: | ||||||||||
Notes payable issued for redemption of RockPile B Units | $ | 1,041 | $ | — | $ | — | ||||
Quarterly_Financial_Informatio
Quarterly Financial Information (Unaudited) | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Quarterly Financial Information [Abstract] | |||||||||||||
Quarterly Financial Information | 17. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | ||||||||||||
The Company’s quarterly financial information for fiscal years 2015 and 2014 is as follows: | |||||||||||||
For the Year Ended January 31, 2015 (1) | |||||||||||||
First | Second | Third | Fourth | ||||||||||
(in thousands) | Quarter | Quarter | Quarter | Quarter | |||||||||
Total revenue | $ | 99,782 | $ | 141,989 | $ | 174,196 | $ | 156,988 | |||||
Income from operations (2) | $ | 22,347 | $ | 38,489 | $ | 33,345 | $ | 1,202 | |||||
Net income | $ | 14,542 | $ | 14,552 | $ | 25,398 | $ | 38,905 | |||||
Net income attributable to common stockholders | $ | 14,542 | $ | 14,552 | $ | 25,398 | $ | 38,905 | |||||
Net income per common share - basic | $ | 0.17 | $ | 0.17 | $ | 0.30 | $ | 0.50 | |||||
Net income per common share - diluted | $ | 0.15 | $ | 0.15 | $ | 0.26 | $ | 0.42 | |||||
For the Year Ended January 31, 2014 (1) | |||||||||||||
First | Second | Third | Fourth | ||||||||||
(in thousands) | Quarter | Quarter | Quarter | Quarter | |||||||||
Total revenue | $ | 34,294 | $ | 50,394 | $ | 88,549 | $ | 85,510 | |||||
Income from operations (2) | $ | 4,328 | $ | 12,973 | $ | 17,160 | $ | 12,501 | |||||
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 | |||||
-1 | Amounts reported for the quarter period. | ||||||||||||
-2 | There were immaterial reclassifications for the periods presented between operating expenses and other income (expense). | ||||||||||||
Supplemental_Information_On_Oi
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ||||||||||
Unaudited Supplemental Oil And Natural Gas Disclosures | 18. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) | |||||||||
Oil and Natural Gas Reserve Information. The following information concerning the Company’s oil and natural gas operations is provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures. | ||||||||||
At January 31, 2015, the Company’s oil and natural gas producing activities were conducted in the Williston Basin in the continental United States. All of our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams, Stark, or Dunn, or in the Montana counties of Roosevelt, Sheridan, Madison or Richland. The Company has ceased all Canadian exploration and production activities and its oil and natural gas properties were fully impaired as of January 31, 2012. | ||||||||||
Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Such prices are also adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices utilized in the calculation of a standardized measure of discounted future net cash flows related to proved oil and natural gas reserves (“Standardized Measure”) | ||||||||||
The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended January 31, 2015. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2015, January 31, 2014, and January 31, 2013 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. | ||||||||||
The reserve estimates presented in the following tables are expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”), thousands of barrels of natural gas liquids (“Mbbls”) and thousands of barrels of oil equivalent (“Mboe”). | ||||||||||
Crude Oil | Natural Gas | NGL | ||||||||
(Mbbls) | (MMcf) | (Mbbls) | ||||||||
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 | |||||||
Revisions of previous estimates | 2,087 | 1,475 | -776 | |||||||
Purchase of reserves | 3,655 | 2,928 | 7 | |||||||
Extensions, discoveries and other additions | 13,946 | 11,710 | 1,129 | |||||||
Sale of reserves | -2 | -3 | — | |||||||
Production | -3,511 | -2,429 | -260 | |||||||
Total proved reserves at January 31, 2015 | 48,091 | 40,185 | 4,081 | |||||||
Proved Developed Reserves included above: | ||||||||||
31-Jan-12 | 538 | 202 | — | |||||||
31-Jan-13 | 4,985 | 5,906 | — | |||||||
31-Jan-14 | 13,734 | 10,930 | 1,440 | |||||||
31-Jan-15 | 29,605 | 24,136 | 2,350 | |||||||
Proved Undeveloped Reserves included above: | ||||||||||
31-Jan-12 | 827 | 472 | — | |||||||
31-Jan-13 | 7,554 | 6,679 | — | |||||||
31-Jan-14 | 18,182 | 15,574 | 2,541 | |||||||
31-Jan-15 | 18,486 | 16,049 | 1,731 | |||||||
The following average prices are reflected in the calculation of the Standardized Measure: | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Oil price per barrel | $ | 79.71 | $ | 93.09 | $ | 84.76 | ||||
Natural gas price per Mcf | $ | 6.09 | $ | 3.99 | $ | 5.23 | ||||
Natural gas liquids price per barrel | $ | 34.61 | $ | 44.10 | $ | — | ||||
Extensions and Discoveries in Fiscal Year 2015. The 13.9 million barrels of oil, 11.7 billion cubic feet of natural gas, and 1.1 million barrels of natural gas liquids of proved reserves added by extensions and discoveries in North Dakota in fiscal year 2015 are primarily due to our increased completion of wells, particularly operated wells, and other parties completing wells offsetting our properties. In fiscal year 2015, we participated in 145 gross (38.6 net) productive wells completed, and we added 37 gross (14.0 net) new proved undeveloped well locations discussed later in this Note. | ||||||||||
Revisions in Fiscal Year 2015. The 2.1 million barrels upward revision in crude oil proved reserves in fiscal year 2015 was primarily due to longer production histories that favorably supported the increase in proved oil reserves. The 1.5 billion cubic feet upward revision in natural gas reserves and the 0.8 million barrels decrease in NGL reserves reflect agreements and arrangements at the end of fiscal year 2015 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 Fiscal Year 2015. The Company purchased certain proved properties which added reserves of 3.7 million barrels of oil and 2.9 billion cubic feet of natural gas proved reserves in fiscal year 2015. | ||||||||||
Proved Undeveloped Reserves. At January 31, 2015, we had proved undeveloped oil and natural gas reserves of 22,892 Mboe, down 427 Mboe from 23,319 Mboe at January 31, 2014. Changes in our proved undeveloped reserves are summarized in the following table: | ||||||||||
(Mboe) | Gross Wells | Net Wells | ||||||||
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 | |||||||
Revisions | 66 | -1 | -0.1 | |||||||
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 | |||||||
Revisions | 84 | — | — | |||||||
Acquisitions | 5,466 | 13 | 11.8 | |||||||
Extensions and discoveries of proved reserves | 13,155 | 68 | 29.6 | |||||||
Proved Undeveloped Reserves at January 31, 2014 | 23,319 | 104 | 52.5 | |||||||
Became developed reserves in fiscal year 2015 | -8,461 | -30 | -18.5 | |||||||
Revisions | 1,676 | -14 | 4.7 | |||||||
Acquisitions | 528 | 6 | 1.3 | |||||||
Extensions and discoveries of proved reserves | 5,830 | 37 | 14.0 | |||||||
Proved Undeveloped Reserves at January 31, 2015 | 22,892 | 103 | 54.0 | |||||||
During fiscal year 2015, we invested approximately $151.6 million (averaging $8.2 million per net well) related to the drilling and completion of the 30 gross (18.5 net) wells that converted 8,461 Mboe of proved undeveloped reserves to proved developed reserves. | ||||||||||
For proved undeveloped (“PUD”) locations at January 31, 2015, the following table provides further information on the timing and status of operated and non-operated locations: | ||||||||||
PUD | Development Wells | |||||||||
Locations | Gross | Net | ||||||||
Proved undeveloped locations: | ||||||||||
For which Triangle operated wells are to be drilled and completed by January 31, 2020 | 79 | 79 | 49.9 | |||||||
For which non-operated wells were in-progress at January 31, 2015 and are expected to be completed in fiscal year 2016 | — | — | — | |||||||
That are non-operated wells with drilling permits | 6 | 6 | 0.7 | |||||||
That are non-operated wells to be drilled by July 31, 2017 | 18 | 18 | 3.4 | |||||||
103 | 103 | 54.0 | ||||||||
Standardized Measure of Discounted Future Net Cash Flows | ||||||||||
Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2015 and 2014 (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 2015 and 2014. Under that accounting guidance: | ||||||||||
· | Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the fiscal year-end estimated future proved reserve quantities. | |||||||||
· | Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. | |||||||||
· | Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using fiscal year-end cost rates and assuming continuation of existing economic conditions. | |||||||||
· | Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and natural gas properties and (ii) net operating loss carryforwards relating to our oil and natural gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure. | |||||||||
These assumptions do not necessarily reflect the Company’s expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations. | ||||||||||
The following summary sets forth the Company’s Standardized Measure for January 31, 2015, 2014, and 2013: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Future cash inflows | $ | 4,219,155 | $ | 3,252,079 | $ | 1,128,676 | ||||
Future costs: | ||||||||||
Production | -1,586,288 | -1,118,508 | -333,185 | |||||||
Development | -439,749 | -505,432 | -199,173 | |||||||
Future income tax expense | -394,538 | -364,340 | -87,313 | |||||||
Future net cash flows | 1,798,580 | 1,263,799 | 509,005 | |||||||
10% discount factor | -977,088 | -690,564 | -297,653 | |||||||
Standardized measure of discounted future net cash flows relating to proved reserves | $ | 821,492 | $ | 573,235 | $ | 211,352 | ||||
Because the estimated salvage value of equipment exceeds the related abandonment costs for well plugging and site restoration costs, future development costs at January 31, 2015 of $439.7 million does not include any net abandonment costs. | ||||||||||
The principle sources of change in the Standardized Measure are shown in the following table: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Standardized measure, beginning of period | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
Extensions and discoveries, net of future production and development costs | 312,185 | 333,140 | 193,107 | |||||||
Sales, net of production costs | -210,505 | -123,786 | -31,502 | |||||||
Previously estimated development costs incurred during the period | 121,282 | 66,724 | 10,368 | |||||||
Revision of quantity estimates | 24,115 | 73,598 | 15,910 | |||||||
Net change in prices, net of production costs | -141,200 | 19,173 | 2,779 | |||||||
Acquisition of reserves | 91,327 | 99,683 | 2,119 | |||||||
Divestiture of reserves | -72 | -7,341 | -3,273 | |||||||
Accretion of discount | 67,790 | 22,486 | 2,943 | |||||||
Changes in future development costs | 57,259 | 7,699 | 801 | |||||||
Change in income taxes | -56,652 | -91,161 | -13,509 | |||||||
Change in production timing and other | -17,272 | -38,332 | 2,181 | |||||||
Standardized measure, end of period | $ | 821,492 | $ | 573,235 | $ | 211,352 | ||||
We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and natural gas disclosures and use the “short-cut” method for the ceiling test calculation. Companies that follow the full cost accounting method are required to make quarterly “ceiling test” calculations. This test limits total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) to no more than the sum of (i) the present value discounted at 10% of estimated future net cash flows from proved reserves, (ii) the cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized and (iv) all related tax effects. | ||||||||||
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Use of Estimates | Use of Estimates. In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of undeveloped properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. | |||||||||
Principles of Consolidation | Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying 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’s 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, incorporated in the Province of Alberta, Canada, (iv) Triangle Real Estate Properties, LLC, organized in the State of Colorado, and its wholly-owned subsidiaries, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Ranger Fabrication, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries, and (vii) 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. The investment in Caliber is accounted for utilizing the equity method of accounting. | ||||||||||
Cash And Cash Equivalents | ||||||||||
Cash and Cash Equivalents. Cash and cash equivalents, including cash in banks in the United States and Canada, consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. | ||||||||||
Accounts Receivable And Credit Policies | ||||||||||
Accounts Receivable and Credit Policies. The components of accounts receivable include the following (in thousands): | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | |||||||||
Oil and natural gas sales | $ | 21,445 | $ | 25,866 | ||||||
Joint interest billings | 72,235 | 43,660 | ||||||||
Oilfield services revenue | 59,408 | 29,109 | ||||||||
Other | 11,350 | 7,828 | ||||||||
Total accounts receivable | $ | 164,438 | $ | 106,463 | ||||||
The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues. | ||||||||||
The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year): | ||||||||||
Fiscal Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Oil & Gas Customer A | 13% | 22% | N/A | |||||||
Oil & Gas Customer B | 12% | 15% | N/A | |||||||
Oil & Gas Customer C | 12% | N/A | N/A | |||||||
Oilfield Services Customer A | 15% | N/A | N/A | |||||||
Oilfield Services Customer B | 12% | 13% | N/A | |||||||
Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available. While we believe that there are numerous operators in the Williston Basin in need of pressure pumping and related oilfield services, a severe and sustained downturn in commodities pricing could result in the loss of a significant customer. However, we do not believe that the loss of a significant customer would have a material adverse impact on the Company. | ||||||||||
Inventories | Inventories. Inventories, included in other current assets, 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 utilized in evaluating net realizable value. | |||||||||
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 natural 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. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. | |||||||||
The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. | ||||||||||
Under the full cost method of accounting, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. | ||||||||||
Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. | ||||||||||
Companies that follow the full cost method of accounting 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. | ||||||||||
At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary. However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline or if there is a negative impact on one or more of the other components of the calculation and such an impairment will likely be material. | ||||||||||
Oil And Natural Gas Reserves | Oil and Natural Gas Reserves. Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision. The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time. | |||||||||
Oilfield Services Equipment and Other Property And Equipment | Oilfield Services Equipment and Other Property and Equipment. Oilfield services equipment and other property and equipment as of January 31, 2014 and 2013 consisted of the following: | |||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Land | $ | 7,888 | $ | 2,512 | ||||||
Building and leasehold improvements | 33,625 | 18,388 | ||||||||
Oilfield service equipment | 116,354 | 56,355 | ||||||||
Vehicles | 4,811 | 2,288 | ||||||||
Software, computers and office equipment | 5,327 | 3,016 | ||||||||
Capital leases | 853 | — | ||||||||
Total depreciable assets | 168,858 | 82,559 | ||||||||
Accumulated depreciation | -35,189 | -12,800 | ||||||||
Depreciable assets, net | 133,669 | 69,759 | ||||||||
Assets not placed in service | 1,247 | 1,333 | ||||||||
Total oilfield service equipment and other property & equipment, net | $ | 134,916 | $ | 71,092 | ||||||
Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Oilfield services equipment and other property and equipment 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 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 ranging from 3-20 years. | ||||||||||
Deferred Financing Costs | Deferred Loan Costs. Deferred financing costs include origination, legal, engineering, and other fees incurred to issue debt. Deferred financing costs are amortized to interest expense using the effective interest method over the respective borrowing term. | |||||||||
Investment In Unconsolidated Entities | Equity Investment. The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations after elimination of intra-company profits and losses. The Company records losses of the unconsolidated entities only to the extent of the Company’s investment. | |||||||||
We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. | ||||||||||
Asset Retirement Obligations | 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. | |||||||||
Derivatives Instruments | Derivative Instruments. The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. | |||||||||
The Company holds equity investment derivatives (Class A Warrants (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. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. | |||||||||
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense. | ||||||||||
Revenue Recognition | Oil, Natural Gas and Natural Gas Liquids Revenue. The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract. There were no oil or natural gas sales imbalances at January 31, 2015, 2014, or 2013. | |||||||||
Oilfield Services Revenue. The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. | ||||||||||
Share-Based Compensation | Share-Based Compensation. Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. | |||||||||
Earnings Per Share | Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted 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. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive. | |||||||||
The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands): | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Dilutive | 17,421 | 15,979 | — | |||||||
Anti-dilutive shares | 6,905 | 5,250 | 4,500 | |||||||
The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2015, 2014, and 2013: | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands, except per share data) | 2015 | 2014 | 2013 | |||||||
Net income (loss) attributable to common stockholders | $ | 93,397 | $ | 73,480 | $ | -13,760 | ||||
Effect of 5% convertible note conversion | 4,135 | 3,392 | — | |||||||
Net income (loss) attributable to common stockholders after effect of debt conversion | $ | 97,532 | $ | 76,872 | $ | -13,760 | ||||
Basic weighted average common shares outstanding | 83,611 | 68,579 | 44,475 | |||||||
Effect of dilutive securities | 17,421 | 15,979 | — | |||||||
Diluted weighted average common shares outstanding | 101,032 | 84,558 | 44,475 | |||||||
Basic net income (loss) per share | $ | 1.12 | $ | 1.07 | $ | -0.31 | ||||
Diluted net income (loss) per share | $ | 0.97 | $ | 0.91 | $ | -0.31 | ||||
Recent Accounting Developments | New Pronouncements Issued But Not Yet Adopted. In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations. | |||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position. | ||||||||||
In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements. | ||||||||||
Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements. Other than the standards discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted. | ||||||||||
Reclassifications | Reclassifications. Certain amounts in the consolidated balance sheet as of January 31, 2014, and in our consolidated statement of operations for the years ended January 31, 2014 and 2013, have been reclassified to conform to the financial statement presentation for the period ended January 31, 2015. The balance sheet reclassifications relate to changes in the captions presented in the balance sheet. The statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported. | |||||||||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Schedule of accounts receivable | The components of accounts receivable include the following (in thousands): | |||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | |||||||||
Oil and natural gas sales | $ | 21,445 | $ | 25,866 | ||||||
Joint interest billings | 72,235 | 43,660 | ||||||||
Oilfield services revenue | 59,408 | 29,109 | ||||||||
Other | 11,350 | 7,828 | ||||||||
Total accounts receivable | $ | 164,438 | $ | 106,463 | ||||||
Schedules of Concentration of Risk, by Risk Factor [Table Text Block] | ||||||||||
Fiscal Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Oil & Gas Customer A | 13% | 22% | N/A | |||||||
Oil & Gas Customer B | 12% | 15% | N/A | |||||||
Oil & Gas Customer C | 12% | N/A | N/A | |||||||
Oilfield Services Customer A | 15% | N/A | N/A | |||||||
Oilfield Services Customer B | 12% | 13% | N/A | |||||||
Schedule of Oilfield services equipment and other property and equipment | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Land | $ | 7,888 | $ | 2,512 | ||||||
Building and leasehold improvements | 33,625 | 18,388 | ||||||||
Oilfield service equipment | 116,354 | 56,355 | ||||||||
Vehicles | 4,811 | 2,288 | ||||||||
Software, computers and office equipment | 5,327 | 3,016 | ||||||||
Capital leases | 853 | — | ||||||||
Total depreciable assets | 168,858 | 82,559 | ||||||||
Accumulated depreciation | -35,189 | -12,800 | ||||||||
Depreciable assets, net | 133,669 | 69,759 | ||||||||
Assets not placed in service | 1,247 | 1,333 | ||||||||
Total oilfield service equipment and other property & equipment, net | $ | 134,916 | $ | 71,092 | ||||||
Schedule of weighted average dilutive and anti-dilutive securities | ||||||||||
The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands): | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Dilutive | 17,421 | 15,979 | — | |||||||
Anti-dilutive shares | 6,905 | 5,250 | 4,500 | |||||||
Schedule of computations of net income(loss) per common share (basic and diluted) | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands, except per share data) | 2015 | 2014 | 2013 | |||||||
Net income (loss) attributable to common stockholders | $ | 93,397 | $ | 73,480 | $ | -13,760 | ||||
Effect of 5% convertible note conversion | 4,135 | 3,392 | — | |||||||
Net income (loss) attributable to common stockholders after effect of debt conversion | $ | 97,532 | $ | 76,872 | $ | -13,760 | ||||
Basic weighted average common shares outstanding | 83,611 | 68,579 | 44,475 | |||||||
Effect of dilutive securities | 17,421 | 15,979 | — | |||||||
Diluted weighted average common shares outstanding | 101,032 | 84,558 | 44,475 | |||||||
Basic net income (loss) per share | $ | 1.12 | $ | 1.07 | $ | -0.31 | ||||
Diluted net income (loss) per share | $ | 0.97 | $ | 0.91 | $ | -0.31 | ||||
Segment_Reporting_Tables
Segment Reporting (Tables) | 12 Months Ended | |||||||||||||||
Jan. 31, 2015 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Schedule Of Segment Reporting | ||||||||||||||||
For the Year Ended January 31, 2015 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 284,502 | $ | — | $ | — | $ | — | $ | 284,502 | ||||||
Oilfield services for third parties | — | 294,526 | — | -6,073 | 288,453 | |||||||||||
Intersegment revenues | — | 123,577 | — | -123,577 | — | |||||||||||
Total revenues | 284,502 | 418,103 | — | -129,650 | 572,955 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 55,477 | — | — | — | 55,477 | |||||||||||
Gathering, transportation and processing | 18,520 | — | — | — | 18,520 | |||||||||||
Depreciation and amortization | 116,633 | 22,008 | 921 | -15,507 | 124,055 | |||||||||||
Accretion of asset retirement obligations | 167 | — | — | — | 167 | |||||||||||
Cost of oilfield services | — | 301,142 | 308 | -84,854 | 216,596 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 6,028 | 14,620 | 11,559 | — | 32,207 | |||||||||||
Stock-based compensation | 1,155 | 509 | 6,255 | — | 7,919 | |||||||||||
Other general and administrative | 9,042 | 10,598 | 2,991 | — | 22,631 | |||||||||||
Total operating expenses | 207,022 | 348,877 | 22,034 | -100,361 | 477,572 | |||||||||||
Income (loss) from operations | 77,480 | 69,226 | -22,034 | -29,289 | 95,383 | |||||||||||
Other income (expense), net | 51,216 | -3,024 | -2,356 | -2,322 | 43,514 | |||||||||||
Net income (loss) before income taxes | $ | 128,696 | $ | 66,202 | $ | -24,390 | $ | -31,611 | $ | 138,897 | ||||||
As of January 31, 2015: | ||||||||||||||||
Net oil and natural gas properties | $ | 1,200,872 | $ | — | $ | — | $ | -74,782 | $ | 1,126,090 | ||||||
Oilfield services equipment - net | $ | — | $ | 87,549 | $ | — | $ | — | $ | 87,549 | ||||||
Other property and equipment - net | $ | 9,679 | $ | 22,246 | $ | 15,442 | $ | — | $ | 47,367 | ||||||
Total assets | $ | 1,408,768 | $ | 202,649 | $ | 131,649 | $ | -88,196 | $ | 1,654,870 | ||||||
Total liabilities | $ | 754,925 | $ | 163,987 | $ | 204,354 | $ | -13,414 | $ | 1,109,852 | ||||||
For the Year Ended January 31, 2014 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 160,548 | $ | — | $ | — | $ | — | $ | 160,548 | ||||||
Oilfield services for third parties | — | 102,606 | — | -4,407 | 98,199 | |||||||||||
Intersegment revenues | — | 91,019 | — | -91,019 | — | |||||||||||
Total revenues | 160,548 | 193,625 | — | -95,426 | 258,747 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 32,460 | — | — | — | 32,460 | |||||||||||
Gathering, transportation and processing | 4,302 | — | — | — | 4,302 | |||||||||||
Depreciation and amortization | 56,788 | 8,905 | 620 | -8,302 | 58,011 | |||||||||||
Accretion of asset retirement obligations | 56 | — | — | — | 56 | |||||||||||
Cost of oilfield services | — | 142,339 | — | -60,012 | 82,327 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 3,541 | 6,894 | 6,864 | — | 17,299 | |||||||||||
Stock-based compensation | 1,127 | 590 | 6,113 | — | 7,830 | |||||||||||
Other general and administrative | 3,939 | 4,222 | 1,339 | — | 9,500 | |||||||||||
Total operating expenses | 102,213 | 162,950 | 14,936 | -68,314 | 211,785 | |||||||||||
Income (loss) from operations | 58,335 | 30,675 | -14,936 | -27,112 | 46,962 | |||||||||||
Other income (expense), net | -172 | -991 | 38,998 | -3,376 | 34,459 | |||||||||||
Net income (loss) before income taxes | $ | 58,163 | $ | 29,684 | $ | 24,062 | $ | -30,488 | $ | 81,421 | ||||||
As of January 31, 2014: | ||||||||||||||||
Net oil and natural gas properties | $ | 725,958 | $ | — | $ | — | $ | -43,171 | $ | 682,787 | ||||||
Oilfield services equipment - net | $ | — | $ | 46,585 | $ | — | $ | — | $ | 46,585 | ||||||
Other property and equipment - net | $ | 1,594 | $ | 18,912 | $ | 4,001 | $ | — | $ | 24,507 | ||||||
Total assets | $ | 816,282 | $ | 126,114 | $ | 148,438 | $ | -63,312 | $ | 1,027,522 | ||||||
Total liabilities | $ | 318,875 | $ | 64,017 | $ | 141,609 | $ | -20,141 | $ | 504,360 | ||||||
For the Year Ended January 31, 2013 | ||||||||||||||||
Exploration | Corporate | |||||||||||||||
and | Oilfield | and | Consolidated | |||||||||||||
(in thousands) | Production | Services | Other | Eliminations | Total | |||||||||||
Revenues: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 39,614 | $ | — | $ | — | $ | — | $ | 39,614 | ||||||
Oilfield services for third parties | — | 22,535 | — | -1,788 | 20,747 | |||||||||||
Intersegment revenues | — | 34,672 | — | -34,672 | — | |||||||||||
Total revenues | 39,614 | 57,207 | — | -36,460 | 60,361 | |||||||||||
Expenses: | ||||||||||||||||
Lease operating and production taxes | 8,058 | — | — | — | 8,058 | |||||||||||
Gathering, transportation and processing | 150 | — | — | — | 150 | |||||||||||
Depreciation and amortization | 13,578 | 2,857 | 378 | -1,732 | 15,081 | |||||||||||
Accretion of asset retirement obligations | 184 | — | — | — | 184 | |||||||||||
Cost of oilfield services | — | 39,534 | — | -22,928 | 16,606 | |||||||||||
General and administrative, net of amounts capitalized: | ||||||||||||||||
Salaries and benefits | 4,367 | 8,422 | 1,959 | — | 14,748 | |||||||||||
Stock-based compensation | 2,507 | 617 | 3,342 | — | 6,466 | |||||||||||
Other general and administrative | 2,223 | 2,708 | 2,398 | — | 7,329 | |||||||||||
Total operating expenses | 31,067 | 54,138 | 8,077 | -24,660 | 68,622 | |||||||||||
Income (loss) from operations | 8,547 | 3,069 | -8,077 | -11,800 | -8,261 | |||||||||||
Other income (expense), net | -6,318 | 4 | 974 | -883 | -6,223 | |||||||||||
Net income (loss) before income taxes | $ | 2,229 | $ | 3,073 | $ | -7,103 | $ | -12,683 | $ | -14,484 | ||||||
As of January 31, 2013: | ||||||||||||||||
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 assets | $ | 362,878 | $ | 38,668 | $ | 40,220 | $ | -13,445 | $ | 428,321 | ||||||
Total liabilities | $ | 91,134 | $ | 11,845 | $ | 125,364 | $ | -1,645 | $ | 226,698 | ||||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||
Jan. 31, 2015 | |||||||
Long-Term Debt [Abstract] | |||||||
Schedule Of Debt | |||||||
For the Years Ended January 31, | |||||||
2015 | 2014 | ||||||
5% convertible note | $ | 135,877 | $ | 129,290 | |||
TUSA credit facility due October 2018 | 119,272 | 183,000 | |||||
RockPile credit facility due March 2019 | 104,887 | 21,515 | |||||
TUSA 6.75% notes due July 2022 | 429,500 | — | |||||
Other notes and mortgages payable | 10,605 | 9,403 | |||||
Total debt | 800,141 | 343,208 | |||||
Less current portion of debt: | |||||||
RockPile credit facility | — | -8,450 | |||||
Other notes and mortgages payable | -503 | -401 | |||||
Total long-term debt | $ | 799,638 | $ | 334,357 | |||
Scheduled annual maturities of long-term debt outstanding | |||||||
For the Years Ending January 31, (in thousands): | |||||||
2016 | $ | 503 | |||||
2017 | 1,450 | ||||||
2018 | 1,594 | ||||||
2019 | 119,852 | ||||||
2020 | 105,565 | ||||||
Thereafter | 571,177 | ||||||
$ | 800,141 | ||||||
Hedging_And_Commodity_Derivati1
Hedging And Commodity Derivative Financial Instruments (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Commodity Derivative Instruments [Abstract] | |||||||||||||
Schedule of components of commodity derivative gains(losses) | |||||||||||||
The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows (in thousands): | |||||||||||||
For the Years Ended January 31, | |||||||||||||
2015 | 2014 | 2013 | |||||||||||
Realized commodity derivative gains (losses) | $ | 11,422 | $ | -4,643 | $ | - | |||||||
Unrealized commodity derivative gains (losses) | 52,628 | 5,725 | -3,570 | ||||||||||
Commodity derivative gains (losses), net | $ | 64,050 | $ | 1,082 | $ | -3,570 | |||||||
Summary Of Derivative Instruments | The Company’s commodity derivative contracts as of January 31, 2015 are summarized below: | ||||||||||||
Contract | Quantity | Weighted Average | Weighted Average | ||||||||||
Term End Date | Type | Basis (1) | (Bbl/d) | Put Strike | Call Strike | ||||||||
Fiscal Year 2016 | Collar | NYMEX | 4,356 | $86.85 | $98.63 | ||||||||
-1 | “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange. | ||||||||||||
Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value | The main headings represent the balance sheet captions for the contracts presented (in thousands). | ||||||||||||
For the Years Ended January 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Current Assets: | |||||||||||||
Crude oil derivative contracts | $ | 62,248 | $ | 955 | |||||||||
Other Long-Term Assets: | |||||||||||||
Crude oil derivative contracts | — | 1,192 | |||||||||||
Total derivative asset | $ | 62,248 | $ | 2,147 | |||||||||
Oil_And_Natural_Gas_Properties1
Oil And Natural Gas Properties (Tables) | 12 Months Ended | |||||||||||||||
Jan. 31, 2015 | ||||||||||||||||
Oil And Natural Gas Properties [Abstract] | ||||||||||||||||
Schedule Of Capitalized Costs Incurred | ||||||||||||||||
For the Years Ended January 31, | ||||||||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||||||||
Costs incurred during the period | ||||||||||||||||
Acquisition of properties: | ||||||||||||||||
Proved | $ | 90,920 | $ | 80,201 | $ | 623 | ||||||||||
Unproved | 47,858 | 41,377 | 20,570 | |||||||||||||
Exploration | 180,174 | 96,731 | 55,583 | |||||||||||||
Development | 226,765 | 216,046 | 91,666 | |||||||||||||
Oil and natural gas expenditures | 545,717 | 434,355 | 168,442 | |||||||||||||
Asset retirement obligations, net | 1,818 | 676 | 370 | |||||||||||||
$ | 547,535 | $ | 435,031 | $ | 168,812 | |||||||||||
Costs Not Being Amortized | ||||||||||||||||
Fiscal Year Costs Incurred | ||||||||||||||||
2012 | ||||||||||||||||
(in thousands) | Total | 2015 | 2014 | 2013 | and prior | |||||||||||
Acquisition | $ | 113,606 | $ | 46,982 | $ | 25,785 | $ | 10,220 | $ | 30,619 | ||||||
Exploration | 22,305 | 20,830 | 1,475 | — | — | |||||||||||
Capitalized interest | 6,985 | 4,899 | 2,086 | — | — | |||||||||||
Total | $ | 142,896 | $ | 72,711 | $ | 29,346 | $ | 10,220 | $ | 30,619 | ||||||
Acquisitions_Tables
Acquisitions (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Acquisitions [Abstract] | ||||||||||
Summary Of Purchase Price And Preliminary Estimated Values Of Assets Acquired And Liabilities Assumed | ||||||||||
Purchase price (in thousands): | ||||||||||
Cash | $ | 90,352 | ||||||||
Total consideration given | $ | 90,352 | ||||||||
Fair value allocation of purchase price: | ||||||||||
Oil and natural gas properties: | ||||||||||
Proved properties | $ | 71,044 | ||||||||
Unproved properties | 20,262 | |||||||||
Total oil and natural gas properties | 91,306 | |||||||||
Accounts payable | -469 | |||||||||
Asset retirement obligations assumed | -485 | |||||||||
Fair value of net assets acquired | $ | 90,352 | ||||||||
Proforma Schedule For Oil And Natural Gas Acquisition | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands, except per share data) | 2015 | 2014 | 2013 | |||||||
Operating revenues | $ | 584,696 | $ | 312,081 | $ | 92,933 | ||||
Net income (loss) | $ | 96,438 | $ | 91,579 | $ | -2,407 | ||||
Earnings (loss) per common share | ||||||||||
Basic | $ | 1.15 | $ | 1.22 | $ | -0.04 | ||||
Diluted | $ | 1.00 | $ | 1.04 | $ | -0.04 | ||||
Weighted average common shares outstanding: | ||||||||||
Basic | 83,611 | 75,047 | 55,794 | |||||||
Diluted | 101,032 | 91,026 | 55,794 | |||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||
Jan. 31, 2015 | |||||||
Asset Retirement Obligations [Abstract] | |||||||
Asset Retirement Obligations | |||||||
For the Years Ended January 31, | |||||||
(in thousands) | 2015 | 2014 | |||||
Balance at the beginning of the period | $ | 4,629 | $ | 3,422 | |||
Liabilities incurred | 1,821 | 944 | |||||
Revision of estimates | 2,737 | 774 | |||||
Sale of assets | -29 | -83 | |||||
Liabilities settled | -747 | -484 | |||||
Accretion | 167 | 56 | |||||
Balance at the end of the period | 8,578 | 4,629 | |||||
Less current portion of obligations | -5,391 | -3,333 | |||||
Long-term ARO | $ | 3,187 | $ | 1,296 | |||
The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets. | |||||||
Equity_Investment_And_Equity_I1
Equity Investment And Equity Investment Derivatives (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Equity Investment [Abstract] | ||||||||||
Schedule Of Equity Investment In Caliber | ||||||||||
Expiration | Strike Price at | As of January 31, | ||||||||
Date | 31-Jan-15 | 2015 | 2014 | |||||||
Class A Units | — | — | 7,000,000 | 3,000,000 | ||||||
Class A Trigger Units | — | — | — | 4,000,000 | ||||||
Class A Trigger Unit Warrants | — | — | — | 1,600,000 | ||||||
Series 1 Warrants | 1-Oct-24 | $ | 12.78 | 5,600,000 | 4,000,000 | |||||
Series 2 Warrants | 1-Oct-24 | $ | 22.09 | 2,400,000 | 2,400,000 | |||||
Series 3 Warrants | 12-Sep-25 | $ | 22.09 | 3,000,000 | 3,000,000 | |||||
Series 4 Warrants | 12-Sep-25 | $ | 28.09 | 2,000,000 | 2,000,000 | |||||
Summary of activities related to company's equity investment | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Balance at beginning of year | $ | 68,536 | $ | 11,768 | ||||||
Capital contributions | — | 18,000 | ||||||||
Distributions | -6,080 | -3,150 | ||||||||
Equity investment share of net income before intra-company profit eliminations | 1,402 | 2,184 | ||||||||
Change in fair value of: | ||||||||||
Class A Trigger Units (1) | 1,745 | 38,091 | ||||||||
Class A Trigger Unit Warrants (2) | 532 | 234 | ||||||||
Series 1 Warrants | -1,241 | 926 | ||||||||
Series 2 Warrants | -254 | 254 | ||||||||
Series 3 Warrants | -207 | 207 | ||||||||
Series 4 Warrants | -22 | 22 | ||||||||
Total changes in fair value | 553 | 39,734 | ||||||||
Balance at end of year | $ | 64,411 | $ | 68,536 | ||||||
Fair value of trigger unit warrants and warrants at end of year | $ | 504 | $ | 39,734 | ||||||
-1 | The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014. | |||||||||
-2 | On June 30, 2014, the 1,600,000 Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding. | |||||||||
ShareBased_Compensation_Tables
Share-Based Compensation (Tables) | 12 Months Ended | ||||||||||
Jan. 31, 2015 | |||||||||||
Share-Based Compensation [Abstract] | |||||||||||
Non-Cash Stock-Based Compensation Cost | |||||||||||
For the Years Ended January 31, | |||||||||||
(in thousands) | 2015 | 2014 | 2013 | ||||||||
Restricted stock units | $ | 6,254 | $ | 7,496 | $ | 6,639 | |||||
Stock options | 2,299 | 1,135 | 60 | ||||||||
Stock issued pursuant to termination agreements | — | — | 99 | ||||||||
RockPile Series B Units | 509 | 590 | 617 | ||||||||
9,062 | 9,221 | 7,415 | |||||||||
Less amounts capitalized to oil and natural gas properties | -1,143 | -1,391 | -949 | ||||||||
Compensation expense | $ | 7,919 | $ | 7,830 | $ | 6,466 | |||||
Restricted Stock Units Outstanding | |||||||||||
Weighted- | |||||||||||
Number of | Average Award | ||||||||||
Shares | Date Fair Value | ||||||||||
Restricted stock units outstanding - January 31, 2012 | 2,488,342 | $ | 7.02 | ||||||||
Units granted | 1,041,400 | $ | 6.37 | ||||||||
Units forfeited | -5,600 | $ | 7.59 | ||||||||
Units vested | -1,000,057 | $ | 6.90 | ||||||||
Restricted stock units outstanding - January 31, 2013 | 2,524,085 | $ | 6.68 | ||||||||
Units granted | 1,440,133 | $ | 6.95 | ||||||||
Units forfeited | -141,909 | $ | 6.58 | ||||||||
Units vested | -946,681 | $ | 6.71 | ||||||||
Restricted stock units outstanding - January 31, 2014 | 2,875,628 | $ | 6.62 | ||||||||
Units granted | 1,523,700 | $ | 9.42 | ||||||||
Units forfeited | -394,921 | $ | 7.21 | ||||||||
Units vested | -1,090,362 | $ | 7.04 | ||||||||
Restricted stock units outstanding - January 31, 2015 | 2,914,045 | $ | 7.92 | ||||||||
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block] | |||||||||||
Weighted | |||||||||||
Number of | Average | ||||||||||
Shares | Exercise Price | ||||||||||
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 | ||||||||
Options forfeited | — | $ | — | ||||||||
Options exercised | -108,333 | $ | 1.25 | ||||||||
Options granted | 700,000 | $ | 14.00 | ||||||||
Options outstanding - January 31, 2015 (600,000 exercisable) | 6,700,000 | $ | 11.54 | ||||||||
Option Grant Plan Fair Value Assumptions | |||||||||||
The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the options granted in fiscal year 2015: | |||||||||||
Risk free rate | 1.06 | % | |||||||||
Dividend yield | — | ||||||||||
Expected volatility | 54 | % | |||||||||
Weighted average expected stock option life (years) | 3.0 | ||||||||||
Stock Options Outstanding By Exercise Price | The following table presents additional information related to the stock options outstanding at January 31, 2015: | ||||||||||
Remaining | |||||||||||
Exercise Price | Contractual Life | Number of Shares | |||||||||
per Share | (years) | Outstanding | Exercisable | ||||||||
$ | 7.50 | 8.43 | 750,000 | 75,000 | |||||||
$ | 8.50 | 8.43 | 750,000 | 75,000 | |||||||
$ | 10.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 12.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 15.00 | 8.43 | 1,500,000 | 150,000 | |||||||
$ | 12.00 | 6.61 | 233,333 | — | |||||||
$ | 14.00 | 6.61 | 233,333 | — | |||||||
$ | 16.00 | 9.61 | 233,334 | — | |||||||
6,700,000 | 600,000 | ||||||||||
Weighted average exercise price per share | $ | 11.54 | $ | 11.25 | |||||||
Weighted average remaining contractual life | 8.34 | 8.43 | |||||||||
Summary Of Series B Unit Activity | |||||||||||
Series | Series | Series | Series | ||||||||
B-1 units | B-2 units | B-3 units | B-4 units | Total | |||||||
Units outstanding - January 31, 2012 | — | — | — | — | — | ||||||
Units granted | 3,100,000 | 60,000 | — | — | 3,160,000 | ||||||
Units outstanding - January 31, 2013 | 3,100,000 | 60,000 | — | — | 3,160,000 | ||||||
Units granted | — | — | 910,000 | — | 910,000 | ||||||
Units outstanding - January 31, 2014 | 3,100,000 | 60,000 | 910,000 | — | 4,070,000 | ||||||
Units redeemed | -180,000 | — | — | — | -180,000 | ||||||
Units granted | — | — | — | 1,412,000 | 1,412,000 | ||||||
Units outstanding - January 31, 2015 | 2,920,000 | 60,000 | 910,000 | 1,412,000 | 5,302,000 | ||||||
Vested | 2,920,000 | 30,000 | 188,000 | — | 3,138,000 | ||||||
Unvested | — | 30,000 | 722,000 | 1,412,000 | 2,164,000 | ||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||
Schedule Of Fair Value, Assets And Liabilities Measured On Recurring Basis | |||||||||||||
As of January 31, 2015 | |||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Equity investment derivative assets | $ | — | $ | — | $ | 504 | $ | 504 | |||||
Commodity derivative assets | $ | — | $ | 62,248 | $ | — | $ | 62,248 | |||||
Liabilities: | |||||||||||||
RockPile earn-out liability | $ | — | $ | -1,825 | $ | — | $ | -1,825 | |||||
As of January 31, 2014 | |||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | |||||||||
Assets: | |||||||||||||
Equity investment derivative assets | $ | — | $ | — | $ | 39,734 | $ | 39,734 | |||||
Commodity derivative assets | $ | — | $ | 2,147 | $ | — | $ | 2,147 | |||||
Liabilities: | |||||||||||||
RockPile earn-out liability | $ | — | $ | -1,739 | $ | — | $ | -1,739 | |||||
Rollforward Of Level 3 Financial Liabilities | |||||||||||||
Class A | |||||||||||||
Trigger | |||||||||||||
(in thousands) | Units | Warrants | |||||||||||
Balance at January 31, 2013 | $ | — | $ | — | |||||||||
Initial recognition of equity investment derivative assets | 38,091 | 1,696 | |||||||||||
Balance at January 31, 2014 | 38,091 | 1,696 | |||||||||||
Interest paid in-kind | — | — | |||||||||||
Net unrecognized loss | — | — | |||||||||||
Net unrealized gain | 1,745 | -1,192 | |||||||||||
Conversion to Class A Units | -39,836 | — | |||||||||||
Balance at January 31, 2015 | $ | — | $ | 504 | |||||||||
Summary Of Fair Value Of Financial Instruments | |||||||||||||
January 31, 2015 | January 31, 2014 | ||||||||||||
Carrying | Estimated | Carrying | Estimated | ||||||||||
(in thousands) | Value | Fair Value | Value | Fair Value | |||||||||
5% convertible note | $ | 135,877 | $ | 137,790 | $ | 129,290 | $ | 169,170 | |||||
Revolving credit facilities | 224,159 | 224,159 | 204,515 | 204,515 | |||||||||
TUSA 6.75% notes | 429,500 | 303,871 | — | — | |||||||||
Other notes and mortgages payable | 10,605 | 10,605 | 9,403 | 9,403 | |||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Income Taxes [Abstract] | ||||||||||
Schedule Of Income Tax Expense (Benefit) | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Current tax expense (benefit) | $ | — | $ | — | $ | — | ||||
Deferred tax expense (benefit) | ||||||||||
Federal | 42,400 | 7,324 | -2,137 | |||||||
State | 3,100 | 617 | -223 | |||||||
Foreign | — | — | -83 | |||||||
Valuation allowance - United States and Canada | — | — | 2,443 | |||||||
Total income tax provision (benefit) | $ | 45,500 | $ | 7,941 | $ | — | ||||
Income (loss) before income taxes | $ | 138,897 | $ | 81,421 | $ | -14,484 | ||||
Effective income tax rate | 33% | 10% | 0% | |||||||
Reconciliation Of Income Tax Expense (Benefit) | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Federal statutory tax expense (benefit) | $ | 48,613 | $ | 28,498 | $ | -5,069 | ||||
State income tax expense / (benefit), net of federal income tax benefit | 3,618 | 2,324 | -361 | |||||||
Permanent differences | 3,196 | 3,221 | 2,280 | |||||||
Difference in foreign tax rates | 539 | 164 | 28 | |||||||
Effect of tax rate change | -147 | -258 | -71 | |||||||
Credits | -338 | -100 | — | |||||||
State NOL adjustment | 1,061 | — | — | |||||||
Bad debt deduction for receivables from Elmworth | -14,517 | — | — | |||||||
Attribute reduction - cancellation of debt exclusion - Elmworth | 8,466 | — | — | |||||||
Changes in valuation allowance | -7,464 | -26,364 | 2,443 | |||||||
Other | 2,473 | 456 | 750 | |||||||
Provision for income taxes | $ | 45,500 | $ | 7,941 | $ | — | ||||
Components Of Deferred Tax Assets And Liabilities | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Current: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | $ | 1,394 | $ | 1,071 | ||||||
Accruals | 1,138 | 103 | ||||||||
Total current assets | 2,532 | 1,174 | ||||||||
Valuation allowance | -1,193 | -492 | ||||||||
Total current assets after valuation allowance | 1,339 | 682 | ||||||||
Liabilities: | ||||||||||
Hedging liabilities | -20,806 | -361 | ||||||||
Total current liabilities | -20,806 | -361 | ||||||||
Net current deferred income tax asset (liability) | $ | -19,467 | $ | 321 | ||||||
Non-Current: | ||||||||||
Assets: | ||||||||||
Canadian oil and natural gas properties | $ | — | $ | 6,080 | ||||||
United States net losses carried forward | 48,443 | 33,129 | ||||||||
Canadian net losses carried forward | — | 1,905 | ||||||||
Asset retirement obligations | 1,198 | 416 | ||||||||
Stock-based compensation | 3,182 | 3,105 | ||||||||
Property and equipment | — | 157 | ||||||||
Other | 2,395 | 1,864 | ||||||||
Total non-current assets | 55,218 | 46,656 | ||||||||
Valuation allowance | — | -8,165 | ||||||||
Total non-current assets after valuation allowance | 55,218 | 38,491 | ||||||||
Liabilities: | ||||||||||
United States oil and natural gas properties | -56,531 | -29,536 | ||||||||
Investment in Caliber | -32,661 | -16,766 | ||||||||
Hedging liabilities | — | -451 | ||||||||
Total deferred non-current income tax liability | -89,192 | -46,753 | ||||||||
Net non-current deferred income tax liability | $ | -33,974 | $ | -8,262 | ||||||
Total net deferred income tax liability | $ | -53,441 | $ | -7,941 | ||||||
Commitments_And_Contingencies_
Commitments And Contingencies (Tables) | 12 Months Ended | |||
Jan. 31, 2015 | ||||
Commitments And Contingencies [Abstract] | ||||
Schedule Of Annual Rentals per Year | ||||
Fiscal Years Ending January 31, | Annual Rental Amount (in thousands) | |||
2016 | $ | 2,807 | ||
2017 | $ | 2,749 | ||
2018 | $ | 2,357 | ||
2019 | $ | 2,108 | ||
2020 and thereafter | $ | 2,686 | ||
Recovered_Sheet1
Supplemental Disclosures of Cash Flow Information (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Supplemental Disclosures of Cash Flow Information [Abstract] | ||||||||||
Schedule of Supplemetal Cash Flow Disclosures | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Cash paid during the period for: | ||||||||||
Interest expense | $ | 19,713 | $ | 1,419 | $ | 75 | ||||
Income taxes | $ | 600 | $ | — | $ | — | ||||
Non-cash investing activities: | ||||||||||
Additions (reductions) to oil and natural gas properties through: | ||||||||||
Increased accounts payable and accrued liabilities | $ | 47,838 | $ | 30,785 | $ | 36,654 | ||||
Issuance of common stock | $ | — | $ | 2,438 | $ | 1,204 | ||||
Capitalized stock based compensation | $ | 1,143 | $ | 1,391 | $ | 949 | ||||
Change in asset retirement obligations | $ | 1,818 | $ | 673 | $ | 1,869 | ||||
Capitalized interest | $ | 4,899 | $ | 809 | $ | — | ||||
Acquisition of oilfield services equipment through notes payable and liabilities | $ | — | $ | 1,990 | $ | — | ||||
Purchase of minority interest in RockPile | $ | — | $ | — | $ | 12,349 | ||||
Non-cash financing activities: | ||||||||||
Notes payable issued for redemption of RockPile B Units | $ | 1,041 | $ | — | $ | — | ||||
Quarterly_Financial_Informatio1
Quarterly Financial Information (Tables) | 12 Months Ended | ||||||||||||
Jan. 31, 2015 | |||||||||||||
Quarterly Financial Information [Abstract] | |||||||||||||
Schedule Of Quarterly Financial Information | |||||||||||||
For the Year Ended January 31, 2015 (1) | |||||||||||||
First | Second | Third | Fourth | ||||||||||
(in thousands) | Quarter | Quarter | Quarter | Quarter | |||||||||
Total revenue | $ | 99,782 | $ | 141,989 | $ | 174,196 | $ | 156,988 | |||||
Income from operations (2) | $ | 22,347 | $ | 38,489 | $ | 33,345 | $ | 1,202 | |||||
Net income | $ | 14,542 | $ | 14,552 | $ | 25,398 | $ | 38,905 | |||||
Net income attributable to common stockholders | $ | 14,542 | $ | 14,552 | $ | 25,398 | $ | 38,905 | |||||
Net income per common share - basic | $ | 0.17 | $ | 0.17 | $ | 0.30 | $ | 0.50 | |||||
Net income per common share - diluted | $ | 0.15 | $ | 0.15 | $ | 0.26 | $ | 0.42 | |||||
For the Year Ended January 31, 2014 (1) | |||||||||||||
First | Second | Third | Fourth | ||||||||||
(in thousands) | Quarter | Quarter | Quarter | Quarter | |||||||||
Total revenue | $ | 34,294 | $ | 50,394 | $ | 88,549 | $ | 85,510 | |||||
Income from operations (2) | $ | 4,328 | $ | 12,973 | $ | 17,160 | $ | 12,501 | |||||
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 | |||||
Supplemental_Information_On_Oi1
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Tables) | 12 Months Ended | |||||||||
Jan. 31, 2015 | ||||||||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ||||||||||
Summary Of Changes In Estimated Proved Reserves | ||||||||||
Crude Oil | Natural Gas | NGL | ||||||||
(Mbbls) | (MMcf) | (Mbbls) | ||||||||
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 | |||||||
Revisions of previous estimates | 2,087 | 1,475 | -776 | |||||||
Purchase of reserves | 3,655 | 2,928 | 7 | |||||||
Extensions, discoveries and other additions | 13,946 | 11,710 | 1,129 | |||||||
Sale of reserves | -2 | -3 | — | |||||||
Production | -3,511 | -2,429 | -260 | |||||||
Total proved reserves at January 31, 2015 | 48,091 | 40,185 | 4,081 | |||||||
Proved Developed Reserves included above: | ||||||||||
31-Jan-12 | 538 | 202 | — | |||||||
31-Jan-13 | 4,985 | 5,906 | — | |||||||
31-Jan-14 | 13,734 | 10,930 | 1,440 | |||||||
31-Jan-15 | 29,605 | 24,136 | 2,350 | |||||||
Proved Undeveloped Reserves included above: | ||||||||||
31-Jan-12 | 827 | 472 | — | |||||||
31-Jan-13 | 7,554 | 6,679 | — | |||||||
31-Jan-14 | 18,182 | 15,574 | 2,541 | |||||||
31-Jan-15 | 18,486 | 16,049 | 1,731 | |||||||
Summary Of Status Of Proved Undeveloped Reserves | ||||||||||
(Mboe) | Gross Wells | Net Wells | ||||||||
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 | |||||||
Revisions | 66 | -1 | -0.1 | |||||||
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 | |||||||
Revisions | 84 | — | — | |||||||
Acquisitions | 5,466 | 13 | 11.8 | |||||||
Extensions and discoveries of proved reserves | 13,155 | 68 | 29.6 | |||||||
Proved Undeveloped Reserves at January 31, 2014 | 23,319 | 104 | 52.5 | |||||||
Became developed reserves in fiscal year 2015 | -8,461 | -30 | -18.5 | |||||||
Revisions | 1,676 | -14 | 4.7 | |||||||
Acquisitions | 528 | 6 | 1.3 | |||||||
Extensions and discoveries of proved reserves | 5,830 | 37 | 14.0 | |||||||
Proved Undeveloped Reserves at January 31, 2015 | 22,892 | 103 | 54.0 | |||||||
Schedule Of Proved Undeveloped Drilling Locations | ||||||||||
PUD | Development Wells | |||||||||
Locations | Gross | Net | ||||||||
Proved undeveloped locations: | ||||||||||
For which Triangle operated wells are to be drilled and completed by January 31, 2020 | 79 | 79 | 49.9 | |||||||
For which non-operated wells were in-progress at January 31, 2015 and are expected to be completed in fiscal year 2016 | — | — | — | |||||||
That are non-operated wells with drilling permits | 6 | 6 | 0.7 | |||||||
That are non-operated wells to be drilled by July 31, 2017 | 18 | 18 | 3.4 | |||||||
103 | 103 | 54.0 | ||||||||
Schedule Of Prices Used In Calculation Of Standardized Measure | ||||||||||
For the Years Ended January 31, | ||||||||||
2015 | 2014 | 2013 | ||||||||
Oil price per barrel | $ | 79.71 | $ | 93.09 | $ | 84.76 | ||||
Natural gas price per Mcf | $ | 6.09 | $ | 3.99 | $ | 5.23 | ||||
Natural gas liquids price per barrel | $ | 34.61 | $ | 44.10 | $ | — | ||||
Summary Of Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Future cash inflows | $ | 4,219,155 | $ | 3,252,079 | $ | 1,128,676 | ||||
Future costs: | ||||||||||
Production | -1,586,288 | -1,118,508 | -333,185 | |||||||
Development | -439,749 | -505,432 | -199,173 | |||||||
Future income tax expense | -394,538 | -364,340 | -87,313 | |||||||
Future net cash flows | 1,798,580 | 1,263,799 | 509,005 | |||||||
10% discount factor | -977,088 | -690,564 | -297,653 | |||||||
Standardized measure of discounted future net cash flows relating to proved reserves | $ | 821,492 | $ | 573,235 | $ | 211,352 | ||||
Schedule Of Principle Sources Of Change In Standardized Measure | ||||||||||
For the Years Ended January 31, | ||||||||||
(in thousands) | 2015 | 2014 | 2013 | |||||||
Standardized measure, beginning of period | $ | 573,235 | $ | 211,352 | $ | 29,428 | ||||
Extensions and discoveries, net of future production and development costs | 312,185 | 333,140 | 193,107 | |||||||
Sales, net of production costs | -210,505 | -123,786 | -31,502 | |||||||
Previously estimated development costs incurred during the period | 121,282 | 66,724 | 10,368 | |||||||
Revision of quantity estimates | 24,115 | 73,598 | 15,910 | |||||||
Net change in prices, net of production costs | -141,200 | 19,173 | 2,779 | |||||||
Acquisition of reserves | 91,327 | 99,683 | 2,119 | |||||||
Divestiture of reserves | -72 | -7,341 | -3,273 | |||||||
Accretion of discount | 67,790 | 22,486 | 2,943 | |||||||
Changes in future development costs | 57,259 | 7,699 | 801 | |||||||
Change in income taxes | -56,652 | -91,161 | -13,509 | |||||||
Change in production timing and other | -17,272 | -38,332 | 2,181 | |||||||
Standardized measure, end of period | $ | 821,492 | $ | 573,235 | $ | 211,352 | ||||
Description_Of_Business_Detail
Description Of Business (Details) | 12 Months Ended |
Jan. 31, 2015 | |
item | |
Description Of Business [Abstract] | |
Number of major focus lines of business | 3 |
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 |
Accounting Policies [Line Items] | ||
Accounts receivable | 164,438 | 106,463 |
Gain (loss) recognized on disposition | 0 | |
Oil and gas imbalance | 0 | |
Oil & Gas Customer A [Member] | ||
Accounting Policies [Line Items] | ||
Customer concentration risk percentage | 13.00% | 22.00% |
Oil & Gas Customer B [Member] | ||
Accounting Policies [Line Items] | ||
Customer concentration risk percentage | 12.00% | 15.00% |
Oil & Gas Customer C [Member] | ||
Accounting Policies [Line Items] | ||
Customer concentration risk percentage | 12.00% | |
Oilfield Services Customer A [Member] | ||
Accounting Policies [Line Items] | ||
Customer concentration risk percentage | 15.00% | |
Oilfield Services Customer B [Member] | ||
Accounting Policies [Line Items] | ||
Customer concentration risk percentage | 12.00% | 13.00% |
Oil And Gas Property [Member] | ||
Accounting Policies [Line Items] | ||
Accounts receivable | 21,445 | 25,866 |
Joint interest billings [Member] | ||
Accounting Policies [Line Items] | ||
Accounts receivable | 72,235 | 43,660 |
Oilfield Services [Member] | ||
Accounting Policies [Line Items] | ||
Accounts receivable | 59,408 | 29,109 |
Other [Member] | ||
Accounting Policies [Line Items] | ||
Accounts receivable | 11,350 | 7,828 |
Maximum [Member] | ||
Accounting Policies [Line Items] | ||
Equity method ownership percentage | 50.00% | |
Minimum [Member] | ||
Accounting Policies [Line Items] | ||
Equity method ownership percentage | 20.00% |
Summary_Of_Significant_Account4
Summary Of Significant Accounting Policies (Details 2) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | $168,858 | $82,559 |
Accumulated depreciation | -35,189 | -12,800 |
Depreciable assets, net | 133,669 | 69,759 |
Assets not placed in service | 1,247 | 1,333 |
Total oilfield service equipment and other property and equipment, net | 134,916 | 71,092 |
Land [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | 7,888 | 2,512 |
Building And Leasehold Improvements [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | 33,625 | 18,388 |
Oilfield Service Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | 116,354 | 56,355 |
Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | 4,811 | 2,288 |
Software, Computers And Office Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | 5,327 | 3,016 |
Capital Leases [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Total Depreciable Assets | $853 |
Summary_Of_Significant_Account5
Summary Of Significant Accounting Policies (Details 3) | 12 Months Ended |
Jan. 31, 2015 | |
Minimum [Member] | |
Estimated useful life | 3 years |
Maximum [Member] | |
Estimated useful life | 20 years |
Summary_Of_Significant_Account6
Summary Of Significant Accounting Policies (Details 4) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Earnings Per Share [Abstract] | |||||||||||
Net income | $38,905 | $25,398 | $14,552 | $14,542 | $14,249 | $47,221 | $6,799 | $5,211 | $93,397 | $73,480 | ($13,760) |
Effect of 5% Convertible Note conversion | 4,135 | 3,392 | |||||||||
Net income (loss) attributable to common shareholders after effect of debt conversion | $97,532 | $76,872 | ($13,760) | ||||||||
Basic weighted average common shares outstanding | 83,611 | 68,579 | 44,475 | ||||||||
Effect of dilutive securities | 17,421 | 15,979 | |||||||||
Diluted weighted average common shares outstanding | 101,032 | 84,558 | 44,475 | ||||||||
Basic net income (loss) per share | $0.50 | $0.30 | $0.17 | $0.17 | $0.17 | $0.60 | $0.12 | $0.10 | $1.12 | $1.07 | ($0.31) |
Diluted net income (loss) per share | $0.42 | $0.26 | $0.15 | $0.15 | $0.15 | $0.50 | $0.12 | $0.10 | $0.97 | $0.91 | ($0.31) |
Anitdilutive securities excluded from calculation of diluted net income | 6,905 | 5,250 | 4,500 |
Segment_Reporting_Details
Segment Reporting (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
segment | |||
Segment Reporting [Abstract] | |||
Number of reportable segments | 2 | ||
Deferred Revenue | $123.60 | $91 | $34.70 |
Deferred gross profit | $1.30 | $2.20 |
Segment_Reporting_Details_2
Segment Reporting (Details 2) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
REVENUES | |||||||||||
Oil and natural gas liquids sales | $284,502 | $160,548 | $39,614 | ||||||||
Oilfield services for third parties | 288,453 | 98,199 | 20,747 | ||||||||
Total revenues | 156,988 | 174,196 | 141,989 | 99,782 | 85,510 | 88,549 | 50,394 | 34,294 | 572,955 | 258,747 | 60,361 |
EXPENSES: | |||||||||||
Production taxes and other lease operating | 55,477 | 32,460 | 8,058 | ||||||||
Gathering, transportation and processing | 18,520 | 4,302 | 150 | ||||||||
Depreciation and amortization | 124,055 | 58,011 | 15,081 | ||||||||
Accretion of asset retirement obligations | 167 | 56 | 184 | ||||||||
Cost of oilfield services | 216,596 | 82,327 | 16,606 | ||||||||
Salaries and benefits | 32,207 | 17,299 | 14,748 | ||||||||
Stock-based compensation | 7,919 | 7,830 | 6,466 | ||||||||
Other general and administrative | 22,631 | 9,500 | 7,329 | ||||||||
Total operating expenses | 477,572 | 211,785 | 68,622 | ||||||||
INCOME FROM OPERATIONS | 1,202 | 33,345 | 38,489 | 22,347 | 12,501 | 17,160 | 12,973 | 4,328 | 95,383 | 46,962 | -8,261 |
Other income (expense), net | 43,514 | 34,459 | -6,223 | ||||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | 138,897 | 81,421 | -14,484 | ||||||||
Net oil and natural gas properties | 1,126,090 | 682,787 | 1,126,090 | 682,787 | 298,757 | ||||||
Oilfield services equipment, net | 87,549 | 46,585 | 87,549 | 46,585 | 18,878 | ||||||
Other property and equipment, net | 47,367 | 24,507 | 47,367 | 24,507 | 15,779 | ||||||
Total assets | 1,654,870 | 1,027,522 | 1,654,870 | 1,027,522 | 428,321 | ||||||
Total liabilities | 1,109,852 | 504,360 | 1,109,852 | 504,360 | 226,698 | ||||||
Eliminations And Other [Member] | |||||||||||
REVENUES | |||||||||||
Oilfield services for third parties | -6,073 | -4,407 | -1,788 | ||||||||
Total revenues | -129,650 | -95,426 | -36,460 | ||||||||
EXPENSES: | |||||||||||
Depreciation and amortization | -15,507 | -8,302 | -1,732 | ||||||||
Cost of oilfield services | -84,854 | -60,012 | -22,928 | ||||||||
Total operating expenses | -100,361 | -68,314 | -24,660 | ||||||||
INCOME FROM OPERATIONS | -29,289 | -27,112 | -11,800 | ||||||||
Other income (expense), net | -2,322 | -3,376 | -883 | ||||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | -31,611 | -30,488 | -12,683 | ||||||||
Net oil and natural gas properties | -74,782 | -43,171 | -74,782 | -43,171 | -11,800 | ||||||
Total assets | -88,196 | -63,312 | -88,196 | -63,312 | -13,445 | ||||||
Total liabilities | -13,414 | -20,141 | -13,414 | -20,141 | -1,645 | ||||||
Intersegment Revenues [Member] | Eliminations And Other [Member] | |||||||||||
REVENUES | |||||||||||
Total revenues | -123,577 | -91,019 | -34,672 | ||||||||
Exploration and Production [Member] | |||||||||||
REVENUES | |||||||||||
Oil and natural gas liquids sales | 284,502 | 160,548 | 39,614 | ||||||||
Total revenues | 284,502 | 160,548 | 39,614 | ||||||||
EXPENSES: | |||||||||||
Production taxes and other lease operating | 55,477 | 32,460 | 8,058 | ||||||||
Gathering, transportation and processing | 18,520 | 4,302 | 150 | ||||||||
Depreciation and amortization | 116,633 | 56,788 | 13,578 | ||||||||
Accretion of asset retirement obligations | 167 | 56 | 184 | ||||||||
Salaries and benefits | 6,028 | 3,541 | 4,367 | ||||||||
Stock-based compensation | 1,155 | 1,127 | 2,507 | ||||||||
Other general and administrative | 9,042 | 3,939 | 2,223 | ||||||||
Total operating expenses | 207,022 | 102,213 | 31,067 | ||||||||
INCOME FROM OPERATIONS | 77,480 | 58,335 | 8,547 | ||||||||
Other income (expense), net | 51,216 | -172 | -6,318 | ||||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | 128,696 | 58,163 | 2,229 | ||||||||
Net oil and natural gas properties | 1,200,872 | 725,958 | 1,200,872 | 725,958 | 310,557 | ||||||
Other property and equipment, net | 9,679 | 1,594 | 9,679 | 1,594 | 1,597 | ||||||
Total assets | 1,408,768 | 816,282 | 1,408,768 | 816,282 | 362,878 | ||||||
Total liabilities | 754,925 | 318,875 | 754,925 | 318,875 | 91,134 | ||||||
Oilfield Services [Member] | |||||||||||
REVENUES | |||||||||||
Oilfield services for third parties | 294,526 | 102,606 | 22,535 | ||||||||
Total revenues | 418,103 | 193,625 | 57,207 | ||||||||
EXPENSES: | |||||||||||
Depreciation and amortization | 22,008 | 8,905 | 2,857 | ||||||||
Cost of oilfield services | 301,142 | 142,339 | 39,534 | ||||||||
Salaries and benefits | 14,620 | 6,894 | 8,422 | ||||||||
Stock-based compensation | 509 | 590 | 617 | ||||||||
Other general and administrative | 10,598 | 4,222 | 2,708 | ||||||||
Total operating expenses | 348,877 | 162,950 | 54,138 | ||||||||
INCOME FROM OPERATIONS | 69,226 | 30,675 | 3,069 | ||||||||
Other income (expense), net | -3,024 | -991 | 4 | ||||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | 66,202 | 29,684 | 3,073 | ||||||||
Oilfield services equipment, net | 87,549 | 46,585 | 87,549 | 46,585 | 18,878 | ||||||
Other property and equipment, net | 22,246 | 18,912 | 22,246 | 18,912 | 12,443 | ||||||
Total assets | 202,649 | 126,114 | 202,649 | 126,114 | 38,668 | ||||||
Total liabilities | 163,987 | 64,017 | 163,987 | 64,017 | 11,845 | ||||||
Oilfield Services [Member] | Intersegment Revenues [Member] | |||||||||||
REVENUES | |||||||||||
Total revenues | 123,577 | 91,019 | 34,672 | ||||||||
Corporate And Other [Member] | |||||||||||
EXPENSES: | |||||||||||
Depreciation and amortization | 921 | 620 | 378 | ||||||||
Cost of oilfield services | 308 | ||||||||||
Salaries and benefits | 11,559 | 6,864 | 1,959 | ||||||||
Stock-based compensation | 6,255 | 6,113 | 3,342 | ||||||||
Other general and administrative | 2,991 | 1,339 | 2,398 | ||||||||
Total operating expenses | 22,034 | 14,936 | 8,077 | ||||||||
INCOME FROM OPERATIONS | -22,034 | -14,936 | -8,077 | ||||||||
Other income (expense), net | -2,356 | 38,998 | 974 | ||||||||
NET INCOME (LOSS) BEFORE INCOME TAXES | -24,390 | 24,062 | -7,103 | ||||||||
Other property and equipment, net | 15,442 | 4,001 | 15,442 | 4,001 | 1,739 | ||||||
Total assets | 131,649 | 148,438 | 131,649 | 148,438 | 40,220 | ||||||
Total liabilities | $204,354 | $141,609 | $204,354 | $141,609 | $125,364 |
LongTerm_Debt_Details
Long-Term Debt (Details) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 | Jul. 18, 2014 |
In Thousands, unless otherwise specified | |||
Debt Instrument [Line Items] | |||
5% Convertible Note | $135,877 | $129,290 | |
Credit facility | 224,159 | 204,515 | |
Other notes and mortgages payable | 10,605 | 9,403 | |
TUSA 6.75% notes | 429,500 | ||
Total debt | 800,141 | 343,208 | |
Less current portion of credit facility | -8,450 | ||
Other notes and mortgages payable | -503 | -401 | |
Total long-term debt | 799,638 | 334,357 | |
TUSA Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate | 6.75% | 6.75% | |
Convertible Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate | 5.00% | 5.00% | |
TUSA [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | 119,272 | 183,000 | |
Rockpile [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | $104,887 | $21,515 |
LongTerm_Debt_Details_2
Long-Term Debt (Details 2) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 |
Debt Instrument [Line Items] | ||
Accrued interest | $2,250,000 | $268,000 |
Convertible Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate | 5.00% | 5.00% |
Debt instrument, face amount | 120,000,000 | |
Convertible note, conversion price | $8 | |
Accrued interest | $15,900,000 |
Longterm_Debt_Details_3
Long-term Debt (Details 3) (USD $) | 0 Months Ended | 12 Months Ended | |
Nov. 25, 2014 | Jan. 31, 2015 | Jul. 18, 2014 | |
TUSA Senior Notes [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt instrument, interest rate | 6.75% | 6.75% | |
TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, maximum borrowing capacity | $1,000,000,000 | ||
Letter of credit sublimit | 15,000,000 | ||
Credit agreement borrowing base | 435,000,000 | ||
Percentage of Oil and Gas Interests Used For Collateral | 80.00% | ||
TUSA [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, fronting fee percentage | 0.13% | ||
Credit facility, fronting fee amount | $500 | ||
Minimum [Member] | TUSA [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, commitment fee percentage | 0.38% | ||
Maximum [Member] | TUSA [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, commitment fee percentage | 0.50% | ||
Federal Funds Rate [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, basis spread on interest rate | 0.50% | ||
Eurodollar Rate Plus 1% [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, margin on dollar amount based on usage | 1.00% | ||
Eurodollar Rate Plus 1% [Member] | Minimum [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, margin on dollar amount based on usage | 0.50% | ||
Eurodollar Rate Plus 1% [Member] | Maximum [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, margin on dollar amount based on usage | 1.50% | ||
Eurodollar [Member] | Minimum [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, margin on dollar amount based on usage | 1.50% | ||
Eurodollar [Member] | Maximum [Member] | TUSA [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, margin on dollar amount based on usage | 2.50% |
Longterm_Debt_Details_4
Long-term Debt (Details 4) (USD $) | 12 Months Ended | ||||
Jan. 31, 2015 | Jan. 31, 2014 | Mar. 25, 2014 | Nov. 13, 2014 | Nov. 12, 2014 | |
Debt Instrument [Line Items] | |||||
Credit facility | 224,159,000 | $204,515,000 | |||
Rockpile [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, maximum borrowing capacity | 100,000,000 | ||||
Credit facility | 104,887,000 | 21,515,000 | |||
Rockpile [Member] | Federal Funds Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, basis spread on interest rate | 0.50% | ||||
Rockpile [Member] | Eurodollar Rate Plus 1% [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, basis spread on interest rate | 1.00% | ||||
Rockpile [Member] | Letter of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, fronting fee percentage | 0.13% | ||||
Rockpile [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, maximum borrowing capacity | $150,000,000 | $100,000,000 | |||
Maximum [Member] | Rockpile [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.50% | ||||
Maximum [Member] | Rockpile [Member] | Eurodollar Rate Plus 1% [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, margin on dollar amount based on usage | 2.25% | ||||
Maximum [Member] | Rockpile [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, margin on dollar amount based on usage | 3.25% | ||||
Minimum [Member] | Rockpile [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.38% | ||||
Minimum [Member] | Rockpile [Member] | Eurodollar Rate Plus 1% [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, margin on dollar amount based on usage | 1.50% | ||||
Minimum [Member] | Rockpile [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit facility, margin on dollar amount based on usage | 2.50% |
Longterm_Debt_Details_5
Long-term Debt (Details 5) (USD $) | 12 Months Ended | |
Jan. 31, 2015 | Jul. 18, 2014 | |
Debt Instrument [Line Items] | ||
Gain (loss) on extinguishment of debt | $6,610,000 | |
TUSA Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | 450,000,000 | |
Debt instrument, interest rate | 6.75% | 6.75% |
Offering costs | 10,500,000 | |
Face value of notes repurchased | 20,500,000 | |
Repurchased amount | 13,900,000 | |
Gain (loss) on extinguishment of debt | $6,600,000 | |
TUSA Senior Notes [Member] | Redemption prior to July 15, 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, percentage | 100.00% | |
Redemption price, percentage of principal amount redeemed | 35.00% | |
TUSA Senior Notes [Member] | Redemption Due to Change in Control Events [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, percentage | 101.00% |
Longterm_Debt_Details_6
Long-term Debt (Details 6) (USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jun. 27, 2014 | |
Long-term Debt, Fiscal Year Maturity [Abstract] | |||
2016 | 503,000 | ||
2017 | 1,450,000 | ||
2018 | 1,594,000 | ||
2019 | 119,852,000 | ||
2020 | 105,565,000 | ||
Thereafter | 571,177,000 | ||
Total debt | 800,141,000 | 343,208,000 | |
Second Lien Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, maximum borrowing capacity | $60,000,000 | ||
LIBOR [Member] | Second Lien Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, basis spread on interest rate | 7.00% | ||
Base Rate [Member] | Second Lien Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit facility, basis spread on interest rate | 6.00% |
Hedging_And_Commodity_Derivati2
Hedging And Commodity Derivative Financial Instruments (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Realized commodity derivative gains (losses) | $11,422 | ($4,643) | |
Commodity derivatives gains (losses) | 64,050 | 1,082 | -3,570 |
Crude Oil Derivative Contract [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Number of counterparties | 3 | ||
Crude Oil Derivative Contract [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Realized commodity derivative gains (losses) | 11,422 | -4,643 | |
Unrealized commodity derivative gains (losses) | 52,628 | 5,725 | -3,570 |
Commodity derivatives gains (losses) | $64,050 | $1,082 | ($3,570) |
Hedging_And_Commodity_Derivati3
Hedging And Commodity Derivative Financial Instruments (Details 2) | 12 Months Ended | |
Jan. 31, 2015 | Feb. 28, 2015 | |
Fiscal 2016 Collar [Member] | ||
Derivative [Line Items] | ||
End date | Fiscal Year 2016 | |
Contract type | Collar | |
Basis | NYMEX | |
Quantity, (bbls) | 4,356 | |
Put strike price | 86.85 | |
Call strike price | 98.63 | |
Notional Disclosures [Abstract] | ||
Notional amount per day (in Bbl) | 4,356 | |
October 2015 Through December 2016 Member | Crude Oil Derivative Contract [Member] | Subsequent Event [Member] | ||
Notional Disclosures [Abstract] | ||
Derivative, Swap Type, Average Fixed Price | 60.07 | |
January 2016 Through December 2016 Member | Crude Oil Derivative Contract [Member] | Subsequent Event [Member] | ||
Notional Disclosures [Abstract] | ||
Derivative, Swap Type, Average Fixed Price | 60.3 |
Hedging_And_Commodity_Derivati4
Hedging And Commodity Derivative Financial Instruments (Details 3) (Crude Oil Derivative Contract [Member], USD $) | 12 Months Ended | |
Jan. 31, 2015 | Jan. 31, 2014 | |
Derivatives, Fair Value [Line Items] | ||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | $60,100,000 | |
Derivative Assets | 62,248,000 | 2,147,000 |
Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Assets | 62,248,000 | 955,000 |
Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Assets | $1,192,000 |
Oil_And_Natural_Gas_Properties2
Oil And Natural Gas Properties (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Property And Equipment [Abstract] | |||
Proved | $90,920 | $80,201 | $623 |
Unproved | 47,858 | 41,377 | 20,570 |
Exploration | 180,174 | 96,731 | 55,583 |
Development | 226,765 | 216,046 | 91,666 |
Oil and natural gas expenditures | 545,717 | 434,355 | 168,442 |
Asset retirement obligation, net | 1,818 | 676 | 370 |
Total costs incurred | $547,535 | $435,031 | $168,812 |
Oil_And_Natural_Gas_Properties3
Oil And Natural Gas Properties (Details 2) (USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Issuance of common stock for oil and gas properties | $2,400,000 | $1,200,000 | |
Capitalized internal land and geology department costs | 4,800,000 | 3,700,000 | 2,000,000 |
Costs not being amortized | 142,896,000 | ||
Duration for Unproved property costs to be reclassified to proved property costs | 5 years | ||
Depreciation and amortization expense for oil and gas properties | 106,900,000 | 51,000,000 | 13,500,000 |
Oil and Gas Properties [Member] | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Total consideration to purchase oil and gas properties | 545,700,000 | 434,400,000 | 168,400,000 |
Unproved Leaseholds [Member] | Oil and Gas Properties [Member] | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Total consideration to purchase oil and gas properties | 138,800,000 | 121,600,000 | 21,200,000 |
Unevaluated Wells In Progress [Member] | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Costs not being amortized | $17,100,000 |
Oil_And_Natural_Gas_Properties4
Oil And Natural Gas Properties (Details 3) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | $113,606 | |||
Exploration | 22,305 | |||
Capitalized Interest | 6,985 | |||
Total | 142,896 | |||
2015 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 46,982 | |||
Exploration | 20,830 | |||
Capitalized Interest | 4,899 | |||
Total | 72,711 | |||
2014 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 25,785 | |||
Exploration | 1,475 | |||
Capitalized Interest | 2,086 | |||
Total | 29,346 | |||
2013 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 10,220 | |||
Total | 10,220 | |||
2012 and prior | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 30,619 | |||
Total | $30,619 |
Acquisitions_Details
Acquisitions (Details) (USD $) | 0 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | |||
Aug. 28, 2013 | Aug. 31, 2013 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | Jun. 30, 2014 | Oct. 31, 2013 | |
acre | acre | ||||||
Kodiak Oil And Natural Gas Property [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Date of acquisition | 28-Aug-13 | ||||||
Number of acres purchased | 5,600 | ||||||
Cash paid for acquisition | $83,800,000 | ||||||
Number of leasehold interest acres that could be exchanged | 600 | ||||||
Pro forma depreciation, amortization and accretion expense | 3,400,000 | 16,500,000 | 12,600,000 | ||||
Marathon Oil And Gas [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Date of acquisition | 1-Jun-14 | ||||||
Number of acres purchased | 41,100 | ||||||
Cash paid for acquisition | 90,352,000 | ||||||
Acquisition transaction costs | 1,300,000 | ||||||
Total consideration for acquisition | 90,352,000 | ||||||
Net downward adjustment included in the purchase price consideration | 9,600,000 | ||||||
Team Well Service, Inc. [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Date of acquisition | 1-Oct-13 | ||||||
Team Well Service, Inc. [Member] | Rockpile [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Cash paid for acquisition | 6,800,000 | ||||||
Unsecured note payable | 800,000 | ||||||
Earn-out payments | 1,500,000 | ||||||
Identifiable intangible assets | 3,900,000 | ||||||
Goodwill | $1,700,000 |
Acquisitions_Details_2
Acquisitions (Details 2) (USD $) | 0 Months Ended | 1 Months Ended |
In Thousands, unless otherwise specified | Aug. 28, 2013 | Jun. 30, 2014 |
Kodiak Oil And Natural Gas Property [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Cash | $83,800 | |
Marathon Oil And Gas [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Cash | 90,352 | |
Total consideration given | 90,352 | |
Proved properties | 71,044 | |
Unproved properties | 20,262 | |
Total oil and natural gas properties | 91,306 | |
Accounts payable | -469 | |
Asset retirement obligation assumed | -485 | |
Fair value of net assets acquired | $90,352 |
Acquisitions_Details_3
Acquisitions (Details 3) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Acquisitions [Abstract] | |||
Operating revenue | $584,696 | $312,081 | $92,933 |
Net income (loss) | $96,438 | $91,579 | ($2,407) |
Earnings (loss) per common share, basic | $1.15 | $1.22 | ($0.04) |
Earnings (loss) per common share, diluted | $1 | $1.04 | ($0.04) |
Weighted average common shares outstanding, basic | 83,611 | 75,047 | 55,794 |
Weighted average common shares outstanding, diluted | 101,032 | 91,026 | 55,794 |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 |
Asset Retirement Obligations [Abstract] | ||
Balance, beginning of period | $4,629 | $3,422 |
Liabilities incurred | 1,821 | 944 |
Revision of estimates | 2,737 | 774 |
Sales of assets | -29 | -83 |
Liabilities settled | -747 | -484 |
Accretion | 167 | 56 |
Balance, end of period | 8,578 | 4,629 |
Less current portion of obligations | -5,391 | -3,333 |
Long-term asset retirement obligations | $3,187 | $1,296 |
Asset_Retirement_Obligations_D1
Asset Retirement Obligations (Details 2) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Asset Retirement Obligations [Line Items] | |||
Accretion of asset retirement obligations | $167 | $56 | $184 |
Asset retirement obligations, current | 5,391 | 3,333 | |
Reclamation Of Man Made Ponds And Plugging And Abandonment Of Well Bores and Plug And Abandon Vertical Wells [Member] | |||
Asset Retirement Obligations [Line Items] | |||
Asset retirement obligations, current | 4,800 | 2,000 | |
Canada [Member] | Internal Engineering Re-assessment [Member] | |||
Asset Retirement Obligations [Line Items] | |||
Accretion of asset retirement obligations | $2,700 | $1,000 |
Equity_Investment_And_Equity_I2
Equity Investment And Equity Investment Derivatives (Details) (Caliber Midstream Partners, L.P. [Member], USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2015 | Oct. 31, 2012 | Sep. 12, 2013 | Sep. 30, 2013 | Feb. 02, 2015 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Increase in equity method investment | $553,000 | $39,734,000 | |||||
FREIF Caliber Holdings [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contribution to joint venture | 70,000,000 | ||||||
Equity method investments, Class A Units received | 2,720,000 | 7,000,000 | |||||
Equity method investment, Class A units held | 17,720,000 | ||||||
Equity method investments, warrants received | 906,667 | ||||||
FREIF Caliber Holdings [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contribution to joint venture | 80,000,000 | ||||||
Equity method investments, Class A Units received | 8,000,000 | ||||||
Equity method investment, Class A units held | 15,000,000 | 15,000,000 | |||||
Equity method ownership percentage | 68.00% | 68.00% | |||||
Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contribution to joint venture | $30,000,000 | ||||||
Equity method investments, Class A Units received | 3,000,000 | ||||||
Equity method investments, Class A Trigger Units received | 4,000,000 | ||||||
Equity method investment, Class A units held | 7,000,000 | ||||||
Equity method investments, warrants received | 3,626,667 | ||||||
Triangle Caliber Holdings LLC [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, Class A Units received | 4,000,000 | ||||||
Equity method investments, Class A Trigger Units received | 4,000,000 | ||||||
Equity method investment, Class A units held | 7,000,000 | 7,000,000 | |||||
Equity method ownership percentage | 32.00% | 32.00% | |||||
Class A Units [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investment, Class A units held | 7,000,000 | 3,000,000 | 7,000,000 | ||||
Series 1 Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 4,000,000 | ||||||
Equity method investments, warrant excercise price | $14.69 | ||||||
Series 1 Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 1,600,000 | ||||||
Equity method investments, warrant excercise price | $14.69 | ||||||
Series 2 Warrant $24.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 2,400,000 | ||||||
Equity method investments, warrant excercise price | $24 | ||||||
Class A Trigger Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 1,600,000 | ||||||
Equity method investments, warrant excercise price | $14.69 | ||||||
Class A Trigger Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments Class A trigger units converted | 1,600,000 | ||||||
Series 5 Warrant $32.00 Strike Price [Member] | FREIF Caliber Holdings [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 5,000,000 | ||||||
Equity method investments, warrant excercise price | $32 | ||||||
Series 3 Warrant $24.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 3,000,000 | ||||||
Equity method investments, warrant excercise price | $24 | ||||||
Series 4 Warrant $30.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 2,000,000 | ||||||
Equity method investments, warrant excercise price | $30 |
Equity_Investment_And_Equity_I3
Equity Investment And Equity Investment Derivatives (Details 2) (Caliber Midstream Partners, L.P. [Member], USD $) | 12 Months Ended | |
Jan. 31, 2015 | Jan. 31, 2014 | |
Class A Units [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Class AUnits Held | 7,000,000 | 3,000,000 |
Class A Triggering Units [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Class AUnits Held | 4,000,000 | |
Class A Trigger Unit Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Class AUnits Held | 1,600,000 | |
Series 1 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Warrant expiration date | 1-Oct-24 | |
Equity method investments, warrant excercise price | $12.78 | |
Equity Method Investment, Class AUnits Held | 5,600,000 | 4,000,000 |
Series 2 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Warrant expiration date | 1-Oct-24 | |
Equity method investments, warrant excercise price | $22.09 | |
Equity Method Investment, Class AUnits Held | 2,400,000 | 2,400,000 |
Series 3 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Warrant expiration date | 12-Sep-25 | |
Equity method investments, warrant excercise price | $22.09 | |
Equity Method Investment, Class AUnits Held | 3,000,000 | 3,000,000 |
Series 4 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Warrant expiration date | 12-Sep-25 | |
Equity method investments, warrant excercise price | $28.09 | |
Equity Method Investment, Class AUnits Held | 2,000,000 | 2,000,000 |
Equity_Investment_And_Equity_I4
Equity Investment And Equity Investment Derivatives (Details 3) (USD $) | 12 Months Ended | 0 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jun. 30, 2014 | Jan. 31, 2015 |
Schedule of Equity Method Investments [Line Items] | ||||
Equity investment, Beginning balance | $68,536 | |||
Distributions | -6,080 | -3,150 | ||
Equity investment, Ending balance | 64,411 | 68,536 | 64,411 | |
Class A Triggering Units [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Number of units converted | 1,600,000 | |||
Caliber Midstream Partners, L.P. [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity investment, Beginning balance | 68,536 | 11,768 | ||
Capital contributions | 18,000 | |||
Distributions | -6,080 | -3,150 | ||
Equity investment share of net income for the year | 1,402 | 2,184 | ||
Increase in equity method investment | 553 | 39,734 | ||
Equity investment, Ending balance | 64,411 | 68,536 | 64,411 | |
Fair value of trigger unit warrants and warrants at end of year | 504 | 39,734 | 504 | |
Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Capital contributions | 0 | |||
Equity method investments, warrants received | 3,626,667 | |||
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | 1,745 | 38,091 | ||
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | 532 | 234 | ||
Caliber Midstream Partners, L.P. [Member] | Series 1 Warrants [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | -1,241 | 926 | ||
Equity method investments, warrants received | 5,600,000 | |||
Caliber Midstream Partners, L.P. [Member] | Series 2 Warrants [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | -254 | 254 | ||
Caliber Midstream Partners, L.P. [Member] | Series 3 Warrants [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | -207 | 207 | ||
Caliber Midstream Partners, L.P. [Member] | Series 4 Warrants [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Increase in equity method investment | ($22) | $22 |
Equity_Investment_And_Equity_I5
Equity Investment And Equity Investment Derivatives (Details 4) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jun. 30, 2014 |
Schedule of Equity Method Investments [Line Items] | |||
Gain (loss) on equity investment derivative | $553 | $39,785 | |
Class A Triggering Units [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Gain (loss) on equity investment derivative | 1,700 | ||
Equity investment, number of units vested | 4,000,000 | ||
Class A Trigger Unit Warrants [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Expected term of warrants | 12 years | ||
Equity Method Investments, warrant floor price | $5 | ||
Input assumption, historical volatility period | 10 years | ||
Caliber Midstream Partners, L.P. [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Increase in equity method investment | 553 | 39,734 | |
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Increase in equity method investment | 1,745 | 38,091 | |
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Increase in equity method investment | $532 | $234 |
Equity_Investment_And_Equity_I6
Equity Investment And Equity Investment Derivatives (Details 5) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Feb. 02, 2015 | Jan. 31, 2015 | Oct. 31, 2012 | Apr. 30, 2015 | Sep. 12, 2013 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Gain (loss) on equity investment derivative | $553,000 | $39,785,000 | |||||
Class A Triggering Units [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Gain (loss) on equity investment derivative | 1,700,000 | ||||||
Series 1, Series 2, Series 3 and Series 4 Warrants [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 2,357,334 | ||||||
Caliber Midstream Partners, L.P. [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contributed capital | 18,000,000 | ||||||
Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contributed capital | 0 | ||||||
Equity method investments, Class A Units received | 3,000,000 | ||||||
Equity method investment, Class A units held | 7,000,000 | ||||||
Equity method investments, warrants received | 3,626,667 | ||||||
Caliber Midstream Partners, L.P. [Member] | FREIF Caliber Holdings [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Contributed capital | 34,000,000 | ||||||
Equity method investments, Class A Units received | 2,720,000 | 7,000,000 | |||||
Equity method investment, Class A units held | 17,720,000 | ||||||
Equity method investments, warrants received | 906,667 | ||||||
Caliber Midstream Partners, L.P. [Member] | Forecast [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Gain (loss) on equity investment derivative | 4,200,000 | ||||||
Gain (loss) on equity investment derivative, related to warrants | $200,000 | ||||||
Caliber Midstream Partners, L.P. [Member] | Forecast [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, Class A Units received | 4,000,000 | ||||||
Equity method investment, Class A units held | 7,000,000 | 7,000,000 | |||||
Equity method ownership percentage | 32.00% | 32.00% | |||||
Caliber Midstream Partners, L.P. [Member] | Forecast [Member] | FREIF Caliber Holdings [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, Class A Units received | 8,000,000 | ||||||
Equity method investment, Class A units held | 15,000,000 | 15,000,000 | |||||
Equity method ownership percentage | 68.00% | 68.00% | |||||
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investment, Class A units held | 4,000,000 | ||||||
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method ownership percentage | 28.30% | ||||||
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | FREIF Caliber Holdings [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method ownership percentage | 71.70% | ||||||
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investment, Class A units held | 1,600,000 | ||||||
Caliber Midstream Partners, L.P. [Member] | Series 6 Warrants [Member] | Triangle Caliber Holdings LLC [Member] | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investments, warrants received | 1,269,333 | ||||||
Equity method investments, warrant excercise price | 12.5 |
Capital_Stock_Details
Capital Stock (Details) (USD $) | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 |
Capital Stock [Line Items] | ||
Shares reserved for issuance | 106,400,000 | |
Common stock, shares issued | 75,174,442 | 85,735,827 |
Common stock, shares outstanding | 75,174,442 | 85,735,827 |
Stock Repurchase authorised (Tranche 1) | $25 | |
Common stock repurchased (in shares) | 11,400,000 | |
Common stock repurchased | $76.80 | |
Authorized shares remaining repurchase | 4,949,393 | |
2011 Omnibus Incentive Plan | ||
Capital Stock [Line Items] | ||
Shares reserved for issuance | 3,600,000 | |
2014 Plan | ||
Capital Stock [Line Items] | ||
Shares reserved for issuance | 4,600,000 | |
CEO Stand-Alone Stock Option Agreement | ||
Capital Stock [Line Items] | ||
Shares reserved for issuance | 6,000,000 | |
Convertible Notes Payable [Member] | ||
Capital Stock [Line Items] | ||
Shares reserved for issuance | 17,000,000 |
ShareBased_Compensation_Detail
Share-Based Compensation (Details) (USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation, net | $7,919,000 | $7,830,000 | $6,466,000 |
Proceeds from issuance of common stock | 245,369,000 | ||
Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation | 19,800,000 | ||
Unrecognized compensation, recognition period | 4 years | ||
Number of shares per vesting unit | 1 | ||
Units granted, number of units | 1,523,700 | 1,440,133 | 1,041,400 |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation, recognition period | 3 years 3 months 18 days | ||
Unrecognized compensation cost related to awards | 18,600,000 | ||
Rockpile Series A Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Preferred return on investment | 8.00% | ||
Series B Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares reserved under Plan | 6,000,000 | ||
Share-based awards vesting period | 5 years | ||
Unrecognized compensation | 2,600,000 | ||
Maxiumum amount of distributions | $40,000,000 | ||
2014 Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares reserved under Plan | 6,000,000 | ||
Minimum [Member] | Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 1 year | ||
Minimum [Member] | Series B Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 7 months | ||
Maximum [Member] | Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 5 years | ||
Maximum [Member] | Series B Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 52 months |
ShareBased_Compensation_Detail1
Share-Based Compensation (Details 2) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Compensation expense before capitalized amount | $9,062 | $9,221 | $7,415 |
Less amounts capitalized to oil and natural gas properties | -1,143 | -1,391 | -949 |
Stock-based compensation, net | 7,919 | 7,830 | 6,466 |
Restricted Stock Units (RSUs) [Member] | |||
Compensation expense before capitalized amount | 6,254 | 7,496 | 6,639 |
Employee Stock Option [Member] | |||
Compensation expense before capitalized amount | 2,299 | 1,135 | 60 |
Stock Issued Pursuant to Termination Agreements [Member] | |||
Compensation expense before capitalized amount | 99 | ||
RockPile Stock Based Compensation Related to Series [Member] | |||
Compensation expense before capitalized amount | $509 | $590 | $617 |
ShareBased_Compensation_Detail2
Share-Based Compensation (Details 3) (Restricted Stock Units (RSUs) [Member], USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Unvested Beginning Balance | 2,875,628 | 2,524,085 | 2,488,342 |
Outstanding, Weighted-Average Award Date Fair Value, Beginning Balance | $6.62 | $6.68 | $7.02 |
Units granted, number of units | 1,523,700 | 1,440,133 | 1,041,400 |
Units granted, Weighted Average Award Date Fair Value | $9.42 | $6.95 | $6.37 |
Units forfeited, Number of Shares | -394,921 | -141,909 | -5,600 |
Units forfeited, Weighted Average Award Date Fair Value | $7.21 | $6.58 | $7.59 |
Units that vested, Number of Shares | -1,090,362 | -946,681 | -1,000,057 |
Units that vested, Weighted Average Award Date Fair Value | $7.04 | $6.71 | $6.90 |
Outstanding, Unvested Ending Balance | 2,914,045 | 2,875,628 | 2,524,085 |
Outstanding, Weighted-Average Grant Date Fair Value, Ending Balance | $7.92 | $6.62 | $6.68 |
ShareBased_Compensation_Detail3
Share-Based Compensation (Details 4) (Employee Stock Option [Member], USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options outstanding, beginning balance | 6,108,333 | 231,666 | 235,833 |
Options forfeited | -15,000 | ||
Options exercised | -108,333 | -108,333 | -4,167 |
Options granted | 700,000 | 6,000,000 | |
Options outstanding, ending balance | 6,700,000 | 6,108,333 | 231,666 |
Weighted average exercise price, options outstanding beginning balance | $11.07 | $1.48 | $1.50 |
Weighted average exercise price, options forfeited | $3 | ||
Weighted average exercise price, options exercised | $1.25 | $1.25 | $3 |
Weighted average exercise price, options granted | $14 | $11.25 | |
Weighted average exercise price, options outstanding ending balance | $11.54 | $11.07 | $1.48 |
Options exercisable, beginning | 108,333 | 231,666 | 142,500 |
Options exercisable, ending | 600,000 | 108,333 | 231,666 |
ShareBased_Compensation_Detail4
Share-Based Compensation (Details 5) (Employee Stock Option [Member], USD $) | 12 Months Ended | |||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ||||
Outstanding options | 6,700,000 | 6,108,333 | 231,666 | 235,833 |
Number of shares exercise | 600,000 | |||
Weighted average exercise price per share | $11.54 | $11.07 | $1.48 | $1.50 |
Weighted average remaining contractual life (years) | 8 years 4 months 2 days | |||
Weighted average exercise price per share (exercisable) | $11.25 | |||
Weighted average remaining contractual life (years) (exercisable) | 8 years 5 months 5 days | |||
$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 | 8 years 5 months 5 days | |||
Outstanding options | 750,000 | |||
Number of shares exercise | 75,000 | |||
$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 | 8 years 5 months 5 days | |||
Outstanding options | 750,000 | |||
Number of shares exercise | 75,000 | |||
$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 | 8 years 5 months 5 days | |||
Outstanding options | 1,500,000 | |||
Number of shares exercise | 150,000 | |||
$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 | 8 years 5 months 5 days | |||
Outstanding options | 1,500,000 | |||
Number of shares exercise | 150,000 | |||
$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 | 8 years 5 months 5 days | |||
Outstanding options | 1,500,000 | |||
Number of shares exercise | 150,000 | |||
$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 | 6 years 7 months 10 days | |||
Outstanding options | 233,333 | |||
$14.00 [Member] | ||||
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ||||
Exercise price per share | $14 | |||
Remaining contractual life | 6 years 7 months 10 days | |||
Outstanding options | 233,333 | |||
$16.00 [Member] | ||||
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ||||
Exercise price per share | $16 | |||
Remaining contractual life | 9 years 7 months 10 days | |||
Outstanding options | 233,334 |
ShareBased_Compensation_Detail5
Share-Based Compensation (Details 6) | 12 Months Ended |
Jan. 31, 2015 | |
Share-Based Compensation [Abstract] | |
Risk free rate | 1.06% |
Expected volatility | 54.00% |
Weighted average expected stock option life (years) | 3 years |
ShareBased_Compensation_Detail6
Share-Based Compensation (Details 7) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 4,070,000 | 3,160,000 | |
Grants, Number of Units | 1,412,000 | 910,000 | 3,160,000 |
Units redeemed | -180,000 | ||
Outstanding, Number of Units, Ending Balance | 5,302,000 | 4,070,000 | 3,160,000 |
Grants, Number of Vested Units | 3,138,000 | ||
Grants, Number of Unvested Units | 2,164,000 | ||
Series B Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining vesting period | 5 years | ||
Series B-1 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 3,100,000 | ||
Grants, Number of Units | 3,100,000 | ||
Units redeemed | -180,000 | ||
Outstanding, Number of Units, Ending Balance | 2,920,000 | 3,100,000 | |
Grants, Number of Vested Units | 2,920,000 | ||
Series B-2 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 60,000 | ||
Grants, Number of Units | 60,000 | ||
Outstanding, Number of Units, Ending Balance | 60,000 | 60,000 | |
Grants, Number of Vested Units | 30,000 | ||
Grants, Number of Unvested Units | 30,000 | ||
Series B-3 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 910,000 | ||
Grants, Number of Units | 910,000 | ||
Outstanding, Number of Units, Ending Balance | 910,000 | 910,000 | |
Grants, Number of Vested Units | 188,000 | ||
Grants, Number of Unvested Units | 722,000 | ||
Series B-4 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grants, Number of Units | 1,412,000 | ||
Outstanding, Number of Units, Ending Balance | 1,412,000 | ||
Grants, Number of Unvested Units | 1,412,000 |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 |
Crude Oil Derivative Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | $62,248 | $2,147 |
Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Earn-out liability | -1,825 | -1,739 |
Fair Value, Measurements, Recurring [Member] | Equity Investment Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 504 | 39,734 |
Fair Value, Measurements, Recurring [Member] | Crude Oil Derivative Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 62,248 | 2,147 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Earn-out liability | -1,825 | -1,739 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Derivative Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 62,248 | 2,147 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Investment Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | $504 | $39,734 |
Fair_Value_Measurements_Detail1
Fair Value Measurements (Details 2) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 |
Class A Triggering Units [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Beginning balance | $38,091 | |
Initial recognition of equity investment derivative assets | 38,091 | |
Net unrealized gain | 1,745 | |
Conversion to Class A units | -39,836 | |
Ending balance | 38,091 | |
Warrants [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Beginning balance | 1,696 | |
Initial recognition of equity investment derivative assets | 1,696 | |
Net unrealized gain | -1,192 | |
Ending balance | $504 | $1,696 |
Fair_Value_Measurements_Detail2
Fair Value Measurements (Details 3) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 | Jul. 18, 2014 |
In Thousands, unless otherwise specified | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
5% convertible note, carrying value | $135,877 | $129,290 | |
Convertible note | 137,790 | 169,170 | |
Long-term portion of credit facilities | 224,159 | 196,065 | |
Revolving credit facilities, carrying value | 224,159 | 204,515 | |
Revolving credit facilities, fair value | 224,159 | 204,515 | |
Other notes and mortgages payable, carrying value | 10,605 | 9,403 | |
Other notes and mortgages payable, fair value | 10,605 | 9,403 | |
TUSA 6.75% notes, carrying value | 429,500 | ||
TUSA 6.75% notes, fair value | $303,871 | ||
Convertible Notes [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt instrument, interest rate | 5.00% | 5.00% | |
TUSA Senior Notes [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt instrument, interest rate | 6.75% | 6.75% |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Federal statutory rate | 35.00% | ||
Difference in foreign tax rates | $539,000 | $164,000 | $28,000 |
US effective tax rate | 37.60% | ||
Canadian effective tax rate | 25.00% | ||
Unrecognized Tax Benefits | 0 | 0 | |
Provision for uncertain tax positions | 0 | 0 | |
Domestic Tax Authority [Member] | |||
Net operating loss carryforward | 136,900,000 | ||
Operating loss carryovers for financial reporting purposes | 131,100,000 | ||
Net operating loss carryforwards that do not benefit financial statements | $5,800,000 | ||
Minimum [Member] | Foreign Tax Authority [Member] | |||
Duration of expected taxable income (loss) for deferred tax asset | 4 years | ||
Maximum [Member] | Foreign Tax Authority [Member] | |||
Duration of expected taxable income (loss) for deferred tax asset | 5 years |
Income_Taxes_Details_2
Income Taxes (Details 2) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Income Taxes [Abstract] | |||
Deferred income tax expense (benefit), Federal | $42,400 | $7,324 | ($2,137) |
Deferred income tax expense (benefit), State | 3,100 | 617 | -223 |
Deferred income tax expense (benefit), Foreign | -83 | ||
Valuation allowance - United States and Canada | -7,464 | -26,364 | 2,443 |
Income tax expense (benefit) | 45,500 | 7,941 | |
Income (loss) before income taxes | $138,897 | $81,421 | ($14,484) |
Effective income tax rate | 33.00% | 10.00% | 0.00% |
Income_Taxes_Details_3
Income Taxes (Details 3) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Income Taxes [Abstract] | |||
Federal statutory tax expense (benefit) | $48,613 | $28,498 | ($5,069) |
State income tax expense / (benefit), net of federal income tax benefit | 3,618 | 2,324 | -361 |
Permanent differences | 3,196 | 3,221 | 2,280 |
Difference in foreign tax rates | 539 | 164 | 28 |
Effect of tax rate change | -147 | -258 | -71 |
Credits | -338 | -100 | |
State NOL adjustment | 1,061 | ||
Bad debt deduction for receivables from Elmworth | -14,517 | ||
Attribute reduction - cancellation of debt exclusion - Elmworth | 8,466 | ||
Changes in valuation allowance | -7,464 | -26,364 | 2,443 |
Other | 2,473 | 456 | 750 |
Income tax expense (benefit) | $45,500 | $7,941 |
Income_Taxes_Details_4
Income Taxes (Details 4) (USD $) | Jan. 31, 2015 | Jan. 31, 2014 |
In Thousands, unless otherwise specified | ||
Income Taxes [Abstract] | ||
Asset retirement obligations | $1,394 | $1,071 |
Accurals | 1,138 | 103 |
Total current assets | 2,532 | 1,174 |
Valuation allowance | -1,193 | -492 |
Total current assets after valuation allowance | 1,339 | 682 |
Hedging liabilities | -20,806 | -361 |
Total current liabilities | -20,806 | -361 |
Net current deferred income tax asset | -19,467 | 321 |
Canadian oil and natural gas properties | 6,080 | |
United States net losses carried forward | 48,443 | 33,129 |
Canadian net losses carried forward | 1,905 | |
Asset retirement obligations | 1,198 | 416 |
Stock-based compensation | 3,182 | 3,105 |
Property and equipment | 157 | |
Other | 2,395 | 1,864 |
Total non-current assets | 55,218 | 46,656 |
Valuation allowance | -8,165 | |
Total non-current assets after valuation allowance | 55,218 | 38,491 |
United States oil and natural gas properties | -56,531 | -29,536 |
Investment in Caliber | -32,661 | -16,766 |
Hedging liabilities | -451 | |
Total deferred non-current income tax liability | -89,192 | -46,753 |
Deferred income tax liability | -33,974 | -8,262 |
Total net deferred income tax liability | ($53,441) | ($7,941) |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
item | item | ||||||||||
Related Party Transaction [Line Items] | |||||||||||
Revenues | $156,988,000 | $174,196,000 | $141,989,000 | $99,782,000 | $85,510,000 | $88,549,000 | $50,394,000 | $34,294,000 | $572,955,000 | $258,747,000 | $60,361,000 |
Number of salt water disposal wells | 1 | 1 | |||||||||
Proceeds from sale of salt water disposal wells | 1,500,000 | 3,265,000 | |||||||||
TUSA [Member] | |||||||||||
Related Party Transaction [Line Items] | |||||||||||
Revenues | 36,600,000 | 15,000,000 | |||||||||
Caliber North Dakota LLC [Member] | |||||||||||
Related Party Transaction [Line Items] | |||||||||||
Term of midstream agreements with Caliber | 15 years | ||||||||||
Minmum commitment over term of agreements | 405,000,000 | 405,000,000 | |||||||||
Remaining commitment | 359,200,000 | 359,200,000 | |||||||||
Revenues | 43,000,000 | 15,600,000 | |||||||||
Proceeds from sale of salt water disposal wells | 1,500,000 | ||||||||||
Reimbursed administrative services from Caliber | $900,000 |
Recovered_Sheet2
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Long-term Purchase Commitment [Line Items] | |||
Lease operating expense | $1.80 | $0.80 | $0.50 |
Early contract termination fee | 10.2 | ||
Chief Executive Officer [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Contingent liability for bonus payout to CEO | $1.90 | ||
Threshold WTI price of oil for payment of a Transaction Bonus | 65 | ||
Number of days over specified period during which oil price should exceed specified value | 5 | ||
Period during which oil price should exceed specified value over specified number of days | 30 days | ||
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 (Details 2) (USD $) | Jan. 31, 2015 |
In Thousands, unless otherwise specified | |
Commitments And Contingencies [Abstract] | |
2016 | $2,807 |
2017 | 2,749 |
2018 | 2,357 |
2019 | 2,108 |
2020 and thereafter | $2,686 |
Supplemental_Disclosures_Of_Ca1
Supplemental Disclosures Of Cash Flow Information (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Supplemental Disclosures of Cash Flow Information [Abstract] | |||
Interest expense | $19,713 | $1,419 | $75 |
Income taxes | 600 | ||
Increased accounts payable and accrued liabilities | 47,838 | 30,785 | 36,654 |
Issuance of common stock | 2,438 | 1,204 | |
Capitalized stock-based compensation | 1,143 | 1,391 | 949 |
Change in asset retirement obligations | 1,818 | 673 | 1,869 |
Capitalized interest | 4,899 | 809 | |
Acquisition of oilfield services equipment through notes payable and liabilities | 1,990 | ||
Purchase minority interest in Rockpile | 12,349 | ||
Notes payable issued for redemption of RockPile B units | $1,041 |
Quarterly_Financial_Informatio2
Quarterly Financial Information (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2014 | Oct. 31, 2013 | Jul. 31, 2013 | Apr. 30, 2013 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Quarterly Financial Information [Abstract] | |||||||||||
Total revenue | $156,988 | $174,196 | $141,989 | $99,782 | $85,510 | $88,549 | $50,394 | $34,294 | $572,955 | $258,747 | $60,361 |
Income (loss) from operations | 1,202 | 33,345 | 38,489 | 22,347 | 12,501 | 17,160 | 12,973 | 4,328 | 95,383 | 46,962 | -8,261 |
Net income (loss) | 38,905 | 25,398 | 14,552 | 14,542 | 14,249 | 47,221 | 6,799 | 5,211 | 93,397 | 73,480 | -14,484 |
Net income (loss) attributable to common stockholders | $38,905 | $25,398 | $14,552 | $14,542 | $14,249 | $47,221 | $6,799 | $5,211 | $93,397 | $73,480 | ($13,760) |
Net income (loss) per common share - basic | $0.50 | $0.30 | $0.17 | $0.17 | $0.17 | $0.60 | $0.12 | $0.10 | $1.12 | $1.07 | ($0.31) |
Net income (loss) per common share - diluted | $0.42 | $0.26 | $0.15 | $0.15 | $0.15 | $0.50 | $0.12 | $0.10 | $0.97 | $0.91 | ($0.31) |
Supplemental_Information_On_Oi2
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details) (USD $) | 12 Months Ended | |||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
MBoe | MBoe | MBoe | MBoe | |
item | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Productive wells, gross | 145 | |||
Productive wells, net | 38.6 | |||
New proved undeveloped, gross | 37 | |||
New proved undeveloped, net | 14 | |||
Proved Undeveloped Reserve BOE 1 | 22,892 | 23,319 | 8,668 | 905 |
Net increase and decrease on proved undeveloped reserve BOE 1 | 427 | |||
Proved undeveloped reserves, conversion to proved developed reserves | 8,461 | 3,701 | 363 | |
Investment in drilling and completion of wells | $151,600,000 | |||
Investment in drilling and completion per well | 8,200,000 | |||
Estimated future development costs | -439,749,000 | -505,432,000 | -199,173,000 | |
Estimated future net costs | $1,798,580,000 | $1,263,799,000 | $509,005,000 | |
Gross Wells [Member] | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Proved undeveloped wells, became developed during period | 30 | 32 | 9 | |
Net Wells [Member] | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Proved undeveloped wells, became developed during period | 18.5 | 7.9 | 1.2 | |
Crude Oil Reserves [Member] | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Proved reserves added by extensions and discoveries | 13,946 | 12,059 | 10,960 | |
Revisions of previous estimates | 2,087 | 2,727 | 665 | |
Natural Gas Reserves [Member] | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Proved reserves added by extensions and discoveries | 11,710 | 11,064 | 10,251 | |
Revisions of previous estimates | 1,475 | -859 | 1,832 | |
Natural Gas Liquids Reserves [Member] | ||||
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items] | ||||
Proved reserves added by extensions and discoveries | 1,129 | 1,599 | ||
Revisions of previous estimates | -776 | 1,762 |
Supplemental_Information_On_Oi3
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 2) | 12 Months Ended | |||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
MBbls | MBbls | MBbls | MBbls | |
Crude Oil Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | 31,916 | 12,539 | 1,365 | |
Revisions of previous estimates | 2,087 | 2,727 | 665 | |
Purchase of reserves | 3,655 | 6,836 | 230 | |
Extensions, discoveries and other additions | 13,946 | 12,059 | 10,960 | |
Sale of reserves | -2 | -491 | -229 | |
Production | -3,511 | -1,754 | -452 | |
Total proved reserves, ending balance | 48,091 | 31,916 | 12,539 | |
Proved Developed, Volume | 29,605 | 13,734 | 4,985 | 538 |
Proved Undeveloped, Volume | 18,486 | 18,182 | 7,554 | 827 |
Natural Gas Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | 26,504 | 12,585 | 674 | |
Revisions of previous estimates | 1,475 | -859 | 1,832 | |
Purchase of reserves | 2,928 | 4,714 | 181 | |
Extensions, discoveries and other additions | 11,710 | 11,064 | 10,251 | |
Sale of reserves | -3 | -374 | -165 | |
Production | -2,429 | -626 | -188 | |
Total proved reserves, ending balance | 40,185 | 26,504 | 12,585 | |
Proved Developed, Volume | 24,136 | 10,930 | 5,906 | 202 |
Proved Undeveloped, Volume | 16,049 | 15,574 | 6,679 | 472 |
Natural Gas Liquids Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | 3,981 | |||
Revisions of previous estimates | -776 | 1,762 | ||
Purchase of reserves | 7 | 690 | ||
Extensions, discoveries and other additions | 1,129 | 1,599 | ||
Production | -260 | -70 | ||
Total proved reserves, ending balance | 4,081 | 3,981 | ||
Proved Developed, Volume | 2,350 | 1,440 | ||
Proved Undeveloped, Volume | 1,731 | 2,541 |
Supplemental_Information_On_Oi4
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 3) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |||
Oil price per barrel | 79.71 | 93.09 | 84.76 |
Natural gas price per Mcf | 6.09 | 3.99 | 5.23 |
Natural gas liquids price per barrel | 34.61 | 44.1 |
Supplemental_Information_On_Oi5
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 4) | 12 Months Ended | ||
Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
MBoe | MBoe | MBoe | |
Reserve Quantities [Line Items] | |||
Proved undeveloped reserve (BOE) beginning balance | 23,319 | 8,668 | 905 |
Became developed reserves during fiscal year | -8,461 | -3,701 | -363 |
Traded for net acres in drill spacing units | -353 | -256 | |
Net revisions | 1,676 | 84 | 66 |
Acquisition of additional interests in PUD location | 528 | 5,466 | 172 |
Additional proved undeveloped locations | 8,144 | ||
Extensions and discoveries of proved reserves | 5,830 | 13,155 | |
Proved undeveloped reserve (BOE) ending balance | 22,892 | 23,319 | 8,668 |
Gross Wells [Member] | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped wells, beginning balance | 104 | 59 | 17 |
Proved undeveloped wells, became developed during period | -30 | -32 | -9 |
Proved undeveloped wells, traded for net acres in other drill spacing units | -4 | -5 | |
Proved undeveloped wells, net revisions | -14 | -1 | |
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 6 | 13 | |
Proved undeveloped wells, additional proved undeveloped locations | 57 | ||
Proved undeveloped wells, extensions and discoveries | 37 | 68 | |
Proved undeveloped wells, ending balance | 103 | 104 | 59 |
Net Wells [Member] | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped wells, beginning balance | 52.5 | 19.8 | 2.6 |
Proved undeveloped wells, became developed during period | -18.5 | -7.9 | -1.2 |
Proved undeveloped wells, traded for net acres in other drill spacing units | -0.8 | -0.7 | |
Proved undeveloped wells, net revisions | 4.7 | -0.1 | |
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 1.3 | 11.8 | 0.3 |
Proved undeveloped wells, additional proved undeveloped locations | 18.9 | ||
Proved undeveloped wells, extensions and discoveries | 14 | 29.6 | |
Proved undeveloped wells, ending balance | 54 | 52.5 | 19.8 |
Supplemental_Information_On_Oi6
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 5) | 12 Months Ended |
Jan. 31, 2015 | |
item | |
PUD Locations [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020 | 79 |
Proved undeveloped locations non-operated wells with drilling permits | 6 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017 | 18 |
Proved undeveloped locations additions to proved undeveloped reserves | 103 |
Development Wells Gross [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020 | 79 |
Proved undeveloped locations non-operated wells with drilling permits | 6 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017 | 18 |
Proved undeveloped locations additions to proved undeveloped reserves | 103 |
Development Wells Net [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020 | 49.9 |
Proved undeveloped locations non-operated wells with drilling permits | 0.7 |
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017 | 3.4 |
Proved undeveloped locations additions to proved undeveloped reserves | 54 |
Supplemental_Information_On_Oi7
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 6) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |||
Future cash inflows | $4,219,155 | $3,252,079 | $1,128,676 |
Future costs: | |||
Production | -1,586,288 | -1,118,508 | -333,185 |
Development | -439,749 | -505,432 | -199,173 |
Future income tax expense | -394,538 | -364,340 | -87,313 |
Future net cash flows | 1,798,580 | 1,263,799 | 509,005 |
10% discount factor | -977,088 | -690,564 | -297,653 |
Standardized measure of discounted future net cash flows relating to proved reserves | $821,492 | $573,235 | $211,352 |
Supplemental_Information_On_Oi8
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 7) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |||
Standardized measure, beginning of period | $573,235 | $211,352 | $29,428 |
Extensions and discoveries, net of future production and development costs | 312,185 | 333,140 | 193,107 |
Sales, net of production costs | -210,505 | -123,786 | -31,502 |
Previously estimated development costs incurred during the period | 121,282 | 66,724 | 10,368 |
Revision of quantity estimates | 24,115 | 73,598 | 15,910 |
Net change in prices, net of production costs | -141,200 | 19,173 | 2,779 |
Acquisition of reserves | 91,327 | 99,683 | 2,119 |
Divestitures of reserves | -72 | -7,341 | -3,273 |
Accretion of discount | 67,790 | 22,486 | 2,943 |
Changes in future development costs | 57,259 | 7,699 | 801 |
Change in income taxes | -56,652 | -91,161 | -13,509 |
Change in production timing and other | -17,272 | -38,332 | 2,181 |
Standardized measure, end of period | $821,492 | $573,235 | $211,352 |