Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Jan. 31, 2016 | Apr. 04, 2016 | Jul. 31, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Jan. 31, 2016 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,016 | ||
Entity Registrant Name | Triangle Petroleum Corp | ||
Entity Central Index Key | 1,281,922 | ||
Current Fiscal Year End Date | --01-31 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $ 198,604,351 | ||
Entity Common Stock, Shares Outstanding | 76,232,614 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 115,769 | $ 67,871 |
Accounts receivable | 53,302 | 171,911 |
Commodity derivatives | 12,370 | 54,775 |
Other current assets | 10,046 | 14,952 |
Total current assets | 191,487 | 309,509 |
Oil and natural gas properties, at cost, full cost method of accounting: | ||
Proved properties | 1,372,480 | 1,159,584 |
Unproved properties and properties under development, not being amortized | 78,367 | 142,896 |
Total oil and natural gas properties | 1,450,847 | 1,302,480 |
Accumulated amortization | (1,044,307) | (176,390) |
Net oil and natural gas properties | 406,540 | 1,126,090 |
Oilfield services equipment - net | 48,445 | 87,549 |
Other property and equipment, net | 42,874 | 47,367 |
Net property, plant and equipment | 497,859 | 1,261,006 |
Other Assets | ||
Equity investment | 45,600 | 64,411 |
Commodity derivatives | 9,012 | |
Deferred loan costs | 3,877 | 4,209 |
Other | 5,313 | 5,906 |
Total other assets | 63,802 | 74,526 |
Total assets | 753,148 | 1,645,041 |
CURRENT LIABILITIES | ||
Accounts payable and accrued capital expenditures | 67,339 | 176,182 |
Other accrued liabilities | 34,065 | 73,440 |
Current portion of long-term debt | 114,088 | 503 |
Interest payable | 1,700 | 2,250 |
Total current liabilities | 217,192 | 252,375 |
LONG-TERM LIABILITIES | ||
Long-term debt | 789,043 | 789,809 |
Deferred income taxes | 53,441 | |
Other | 11,495 | 4,398 |
Total liabilities | $ 1,017,730 | $ 1,100,023 |
COMMITMENT AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY (DEFICIT) | ||
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,807,111 shares issued and outstanding at January 31, 2015 and January 31, 2016, respectively | $ 1 | $ 1 |
Additional paid-in capital | 557,757 | 545,017 |
Retained earnings (accumulated deficit) | (822,340) | |
Total stockholders' equity (deficit) | (264,582) | 545,018 |
Total liabilities and stockholders’ equity (deficit) | $ 753,148 | $ 1,645,041 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Jan. 31, 2016 | Jan. 31, 2015 |
Consolidated Balance Sheets [Abstract] | ||
Common stock, par value | $ 0.00001 | $ 0.00001 |
Common stock, shares authorized | 140,000,000 | 140,000,000 |
Common stock, shares issued | 75,807,111 | 75,174,442 |
Common stock, shares outstanding | 75,807,111 | 75,174,442 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Revenues | |||
Oil, natural gas and natural gas liquids sales | $ 181,228 | $ 284,502 | $ 160,548 |
Oilfield services | 176,901 | 288,453 | 98,199 |
Total revenues | 358,129 | 572,955 | 258,747 |
Expenses | |||
Lease operating expenses | 41,504 | 25,703 | 14,454 |
Gathering, transportation and processing | 25,910 | 18,520 | 4,302 |
Production taxes | 17,491 | 29,774 | 18,006 |
Depreciation and amortization | 121,374 | 124,055 | 58,011 |
Impairment of oil and natural gas properties | 779,000 | ||
Impairment of long lived assets | 14,900 | 0 | 0 |
Accretion of asset retirement obligations | 376 | 167 | 56 |
Oilfield services | 163,452 | 216,596 | 82,327 |
General and administrative, net of amounts capitalized | 62,305 | 62,757 | 34,629 |
Total operating expenses | 1,226,312 | 477,572 | 211,785 |
INCOME (LOSS) FROM OPERATIONS | (868,183) | 95,383 | 46,962 |
OTHER INCOME (EXPENSE): | |||
Interest expense, net | (38,706) | (25,100) | (7,132) |
Amortization of deferred loan costs | (3,180) | (3,149) | (554) |
Gain on extinguishment of debt | 17,927 | 6,610 | |
Realized commodity derivative gains (losses) | 71,940 | 11,422 | (4,643) |
Unrealized commodity derivative gains (losses) | (33,393) | 52,628 | 5,725 |
Equity investment income (loss) | 1,887 | 81 | |
Impairment of investment in Caliber | (24,979) | ||
Gain (loss) on equity investment derivatives | 3,098 | 553 | 39,785 |
Other income (expense), net | (2,148) | 469 | 1,278 |
Total other income (expense) | (7,554) | 43,514 | 34,459 |
INCOME (LOSS) BEFORE INCOME TAXES | (875,737) | 138,897 | 81,421 |
INCOME TAX PROVISION (BENEFIT) | (53,397) | 45,500 | 7,941 |
NET INCOME (LOSS) | $ (822,340) | $ 93,397 | $ 73,480 |
Earnings (loss) per common share outstanding: | |||
Basic | $ (10.89) | $ 1.12 | $ 1.07 |
Diluted | $ (10.89) | $ 0.97 | $ 0.91 |
Weighted average common shares outstanding: | |||
Basic | 75,502 | 83,611 | 68,579 |
Diluted | 75,502 | 101,032 | 84,558 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ (822,340) | $ 93,397 | $ 73,480 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, amortization and accretion | 121,750 | 124,222 | 58,067 |
Impairment of oil and natural gas properties | 779,000 | ||
Impairment of long lived assets | 14,900 | 0 | 0 |
Share-based compensation | 17,394 | 7,919 | 7,830 |
Interest expense paid-in-kind on 5% convertible note | 6,922 | 6,587 | 6,267 |
Amortization of debt issuance costs | 3,180 | 3,149 | 554 |
Gain on extinguishment of debt | (17,927) | (6,610) | |
Unrealized commodity derivative (gains) losses | 33,393 | (52,628) | (5,725) |
Equity investment (income) loss | (1,887) | (81) | |
Gain on equity investment derivatives | (3,098) | (553) | (39,785) |
Impairment of investment in Caliber | 24,979 | ||
Deferred income taxes | (53,441) | 45,500 | 7,941 |
Other | 1,067 | (1,040) | |
Changes in related current assets and current liabilities: | |||
Accounts receivable | 118,609 | (65,448) | (65,929) |
Other current assets | 4,588 | (9,926) | (3,579) |
Accounts payable and accrued liabilities | (61,181) | 57,233 | 44,840 |
Asset retirement expenditures | (1,526) | (2,206) | (484) |
Other | 652 | 262 | (1) |
Cash provided by operating activities | 165,034 | 200,817 | 82,436 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Oil and natural gas property expenditures | (231,238) | (359,102) | (279,531) |
Acquisitions of oil and natural gas properties | (810) | (138,778) | (121,578) |
Purchases of oilfield services equipment | (8,478) | (59,624) | (27,414) |
Purchases of other property and equipment | (5,112) | (26,739) | (10,928) |
Sale of oil and natural gas properties | 6,000 | 1,500 | |
Acquisition of oilfield services companies | (7,715) | ||
Proceeds from sale of equipment | 7,804 | ||
Equity investment in Caliber Midstream Partners, L.P. | (18,000) | ||
Equity investment cash distribution | 6,080 | 3,150 | |
Sale of marketable securities | 6,105 | ||
Other | (356) | 345 | |
Cash used in investing activities | (231,834) | (577,019) | (455,566) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from credit facilities | 320,789 | 504,159 | 211,820 |
Repayments of credit facilities | (189,176) | (484,515) | (32,306) |
Proceeds from notes payable | 4,032 | 451,568 | 14,430 |
Repayments of other notes and mortgages payable | (631) | (416) | (5,876) |
Early extinguishment of repurchased debt | (13,154) | (13,890) | |
Debt issuance costs | (943) | (13,980) | (2,706) |
Proceeds from issuance of common stock | 245,369 | ||
Stock offering costs | (7,072) | ||
Payments to settle tax on vested restricted stock units | (861) | (2,854) | (2,058) |
Issuance of common stock on exercise of options | 135 | 162 | |
Distributions to RockPile B unit holders | (4,329) | ||
Purchase of vested RockPile B units from unit holders | (1,029) | (1,041) | |
Common stock repurchased and retired | (76,843) | ||
Cash provided by financing activities | 114,698 | 362,323 | 421,763 |
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS | 47,898 | (13,879) | 48,633 |
CASH AND EQUIVALENTS, BEGINNING OF PERIOD | 67,871 | 81,750 | 33,117 |
CASH AND EQUIVALENTS, END OF PERIOD | $ 115,769 | $ 67,871 | $ 81,750 |
Consolidated Statements of Cas6
Consolidated Statements of Cash Flows (Parenthetical) | Jan. 31, 2016 | Jan. 31, 2015 |
Convertible Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate | 5.00% | 5.00% |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands | Common Stock [Member] | Additional Paid-In Capital [Member] | Accumulated Deficit [Member] | Total |
Balance at Jan. 31, 2013 | $ 1 | $ 323,641 | $ (122,020) | $ 201,622 |
Balance, shares at Jan. 31, 2013 | 46,733,011 | |||
Shares issued, value | 245,369 | 245,369 | ||
Shares issued, shares | 37,905,000 | |||
Stock offering costs | (7,072) | (7,072) | ||
Shares issued for the purchase of oil and natural gas properties, value | 2,438 | 2,438 | ||
Shares issued for the purchase of oil and natural gas properties, shares | 325,000 | |||
Vesting of restricted stock units (net of shares surrendered for taxes), value | (2,058) | (2,058) | ||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 664,483 | |||
Exercise of stock options, value | 162 | 162 | ||
Exercise of stock options, shares | 108,333 | |||
Share-based compensation | 9,221 | 9,221 | ||
Net income (loss) for the period | 73,480 | 73,480 | ||
Balance at Jan. 31, 2014 | $ 1 | 571,701 | (48,540) | 523,162 |
Balance, shares at Jan. 31, 2014 | 85,735,827 | |||
Vesting of restricted stock units (net of shares surrendered for taxes), value | (2,854) | (2,854) | ||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 762,026 | |||
Redeemed RockPile B-Units | (1,041) | (1,041) | ||
Shares repurchased and retired, value | (31,986) | (44,857) | (76,843) | |
Shares repurchased and retired, shares | (11,431,744) | |||
Exercise of stock options, value | 135 | 135 | ||
Exercise of stock options, shares | 108,333 | |||
Share-based compensation | 9,062 | 9,062 | ||
Net income (loss) for the period | 93,397 | 93,397 | ||
Balance at Jan. 31, 2015 | $ 1 | 545,017 | $ 545,018 | |
Balance, shares at Jan. 31, 2015 | 75,174,442 | 75,174,442 | ||
Vesting of restricted stock units (net of shares surrendered for taxes), value | (861) | $ (861) | ||
Vesting of restricted stock units (net of shares surrendered for taxes), shares | 632,669 | |||
Share-based compensation | 18,959 | 18,959 | ||
Distributions to RockPile B-Unit holders | (4,329) | (4,329) | ||
Purchase of vested RockPile B units from unit holders | (1,029) | (1,029) | ||
Net income (loss) for the period | (822,340) | (822,340) | ||
Balance at Jan. 31, 2016 | $ 1 | $ 557,757 | $ (822,340) | $ (264,582) |
Balance, shares at Jan. 31, 2016 | 75,807,111 | 75,807,111 |
Description Of Business
Description Of Business | 12 Months Ended |
Jan. 31, 2016 | |
Basis Of Presentation [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 predominantly located in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”). In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston Basin. RockPile began operations in July 2012. In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund. Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin. The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada. Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia. Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage. Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Jan. 31, 2016 | |
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 condensed consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented. Liquidity and Ability to Continue as a Going Concern . The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, its liquidity outlook has changed since the third quarter of fiscal year 2016. Continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. These factors and the RockPile debt compliance issues raise substantial doubt about the Company’s ability to continue as a going concern. RockPile Liquidity and Covenants . On April 13, 2016, RockPile entered into Amendment No. 2 to the Credit Agreement (“Amendment No. 2”), which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility. Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing as discussed further in Note 4. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but the success of these discussions and negotiations is uncertain. In addition, i f RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile. As a result, substantial doubt exists regarding the ability of RockPile, our oilfield services subsidiary, to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default. TUSA Liquidity and Covenants . As of January 31, 2016, TUSA had $243.8 million drawn, plus an additional $2.5 million outstanding in letters of credit, resulting in remaining available borrowing capacity of $103.7 million under the TUSA credit facility. On March 31, 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base of $350.0 million. As a result, no further extensions of credit currently are available under the TUSA credit agreement. As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of consolidated debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recover or it is unable to obtain cure financing or a waiver or amendment from its lenders, with whom it is engaged in ongoing discussions . Also, the current ratio covenant could be adversely impacted if a redetermination significantly lowers the borrowing base. If TUSA were to breach a covenant in a future period, TUSA has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due ( 45 days after quarter ends and 90 days after its fiscal year end) to cure such a breach, also known as an equity cure. Although there are many risks and uncertainties in this environment, TUSA believes that it will be able to reach an agreement with its banks, find acceptable alternative financing or obtain equity cure contributions to prevent or cure an event of default under its credit facility. However, there can be no assurances that these plans can be achieved. If TUSA were to breach any financial covenants under its credit facility and such breach became an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes (as defined below) that could enable holders of the TUSA 6.75% Notes to declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable. While we believe our existing capital resources, including our cash flow from TUSA’s operations and cash on hand at TUSA and Triangle, are sufficient to conduct our operations of TUSA and Triangle through fiscal year 2017 and into fiscal year 2018, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted if oil and natural gas prices remain depressed for an extended period of time. Further, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations. If we are not able to meet our debt covenants in future periods, or if our borrowing base is significantly reduced, we may be required but unable to refinance or restructure all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the TUSA credit facility. Further, failing to comply with the financial and other restrictive covenants in the TUSA credit facility and the TUSA 6.75% Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations. Triangle Liquidity . Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful. Use of Estimates. In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of unproved properties, investment in equity method investees and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these consolidated financial statements. Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. The investment in Caliber is accounted for utilizing the equity method of accounting. Cash and Cash Equivalents. Cash and cash equivalents, including cash in banks in the United States and Canada, consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. Accounts Receivable and Credit Policies . The components of accounts receivable include the following (in thousands): For the Years Ended January 31, 2015 2016 Oil and natural gas sales $ $ Joint interest billings Oilfield services revenue Other Total accounts receivable $ $ 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): For the Years Ended January 31, 2014 2015 2016 Oil & Gas Customer A N/A Oil & Gas Customer B Oil & Gas Customer C N/A N/A Oilfield Services Customer A N/A N/A Oilfield Services Customer B N/A Oilfield services Customer C N/A N/A Oilfield services Customer D N/A 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. The loss of any significant oilfield services customer is detrimental to RockPile during this low price competitive pressure pumping and oilfield services environment but would not be expected to have a material adverse effect on the Company. Inventories. Inventories, included in other current assets, consist of well equipment, sand, chemicals and ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors utilized in evaluating net realizable value. Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2014, 2015 and 2016 was $52.0 million, $106.9 million and $90.4 million, respectively. At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation. January 31, 2014 January 31, 2015 January 31, 2016 Oil (per Bbl) $ $ $ Natural gas (per MMbtu) $ $ $ Natural gas liquids (per Bbl) $ $ $ We recognized impairments to our proved oil and natural gas properties of $779.0 million for the year ended January 31, 2016, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the years ended January 31, 2014 and 2015. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids (“NGL”) prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date. The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Oil and Natural Gas Reserves. Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision. The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time. Oilfield Services Equipment and Other Property and Equipment . Oilfield services equipment and other property and equipment consisted of the following as of: (in thousands) January 31, 2015 January 31, 2016 Oilfield services equipment $ $ Accumulated depreciation Depreciable assets, net Assets not placed in service Total oilfield services equipment, net $ $ Land $ $ Building and leasehold improvements Vehicles Software, computers and office equipment Capital leases Accumulated depreciation Depreciable assets, net Assets not placed in service Total other property and equipment, net $ $ Impairment of Long-Lived Assets. Long ‑lived assets such as property and equipment and identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long ‑lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long ‑lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined using various valuation techniques including discounted cash flow models, quoted market values, and third ‑party independent appraisals, as considered necessary. No impairment losses were recognized in fiscal years 2014 and 2015 and an impairment loss of $14.9 million, primarily related to oilfield services equipment, was recorded in fiscal year 2016. Debt Issuance Costs. Debt issuance costs related to the TUSA 6.75% Notes and the Convertible Note, each as defined below, are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets, and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets, and are amortized to interest expense on a straight-line basis over the term of the agreement . Equity Investment. The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the consolidated statements of operations after elimination of intra-company profits and losses. The Company records losses of the unconsolidated entities only to the extent of the Company’s investment. We evaluate our equity method investment for impairment when there are indicators of impairment. If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. Asset Retirement Obligations. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base. Derivative Instruments. The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. The Company holds equity investment derivatives (Class A Warrants) in Caliber. Our equity investment derivatives are measured at fair value and are included in equity investment on the consolidated balance sheet. Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations. Income Taxes. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in interest expense. Oil, Natural Gas and Natural Gas Liquids Revenue. The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract. There were no oil or natural gas sales imbalances at January 31, 2015 and 2016. Oilfield Services Revenue . The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. Share- Based Compensation . Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the vesting period. The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted earnings per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive. The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented : For the Years Ended January 31, (in thousands) 2014 2015 2016 Dilutive — Anti-dilutive shares The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented: For the Years Ended January 31, (in thousands, except per share data) 2014 2015 2016 Net income (loss) attributable to common stockholders $ $ $ Effect of 5% convertible note conversion — Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion $ $ $ Basic weighted average common shares outstanding Effect of dilutive securities — Diluted weighted average common shares outstanding Basic net income (loss) per share $ $ $ Diluted net inco |
Segment Reporting
Segment Reporting | 12 Months Ended |
Jan. 31, 2016 | |
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 and its subsidiaries, is responsible for a variety of oilfield and well completion services for both TUSA-operated wells and wells operated by third-parties. Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments. Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. Management evaluates the performance of our segments based upon net income (loss) before income taxes. The following tables present selected financial information for our operating segments for the years ended January 31, 2016 , 2015 and 2014 : For the Year Ended January 31, 2016 Exploration Corporate and Oilfield and Consolidated (in thousands) Production Services Other Eliminations Total Revenues: Oil, natural gas and natural gas liquids sales $ $ — $ — $ — $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Impairments — Accretion of asset retirement obligations — — — Oilfield services — — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ As of January 31, 2016: Cash and cash equivalents $ $ $ $ — $ Net oil and natural gas properties $ $ — $ — $ $ Oilfield services equipment, net $ — $ $ — $ — $ Other property and equipment, net $ $ $ $ — $ Total assets $ $ $ $ $ Total liabilities $ $ $ $ $ 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 $ $ — $ — $ $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Accretion of asset retirement obligations — — — Oilfield services — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ As of January 31, 2015: Cash and cash equivalents $ $ $ $ — $ Net oil and natural gas properties $ $ — $ — $ $ Oilfield services equipment, net $ — $ $ — $ — $ Other property and equipment, net $ $ $ $ — $ Total assets $ $ $ $ $ Total liabilities $ $ $ $ $ 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 $ $ — $ — $ $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Accretion of asset retirement obligations — — — Oilfield services — — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ Eliminations and Other. For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs. Under the full cost method of accounting, we defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties. The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced. For the years ended January 31, 2014, 2015 and 2016, $4.8 million, $9.6 million and $0.2 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment. These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements . |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Jan. 31, 2016 | |
Long-Term Debt [Abstract] | |
Long-term Debt | 4. LONG-TERM DEBT T he Company’s long-term debt consisted of the following as of January 31, 2015 and 2016 : (in thousands) January 31, 2015 January 31, 2016 TUSA credit facility due October 2018 $ $ RockPile credit facility due March 2019 TUSA 6.75% notes due July 2022 5% convertible note Other notes and mortgages payable Total principal Debt issuance costs Total debt Less current portion of debt: RockPile credit facility — Other notes and mortgages payable Total current portion of long-term debt Total long-term debt $ $ TUSA Credit Facility. On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates. On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. The TUSA credit facility has a maturity date of October 16, 2018. On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (“Amendment No. 1”) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants. The May 2015 semi-annual redetermination of the borrowing base was conducted concurrently with the execution of Amendment No. 1, and the borrowing base was adjusted from $435.0 million to $350.0 million. The November 2015 semi-annual redetermination of the borrowing base was reaffirmed at $350.0 million. As of January 31, 2016, TUSA had $243.8 million drawn, plus an additional $2.5 million outstanding in letters of credit, resulting in remaining available borrowing capacity of $103.7 million under the TUSA credit facility. On March 31 , 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base of $350 .0 million. As a result, no further extensions of credit currently are available under the TUSA credit agreement. Borrowings under the TUSA credit facility bear interest, at TUSA’s option, at either (i) the adjusted base rate (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.50% , or (C) the one month Eurodollar rate (as defined in the agreement) plus 1.0%) , plus an applicable margin that ranges between 0.50% and 1.50% , depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the Eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50% , depending on TUSA’s utilization percentage of the then effective borrowing base. The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If the new borrowing base resulting from any regularly scheduled, semi-annual redetermination is less than the amount of outstanding credit exposure under the credit facility, TUSA will be required to (i) pledge additional collateral, (ii) repay the principal amount of the loans in an amount sufficient to eliminate the excess, (iii) repay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). In contrast, if a borrowing base deficiency results from an unscheduled redetermination, TUSA must immediately repay the excess and may not remedy such deficiency by pledging additional collateral or repaying the excess in installments. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA credit facility are guaranteed by TUSA’s subsidiaries, but Triangle is not a guarantor. Continued low commodity prices, reductions in TUSA’s capital budget and the resulting reserve write-downs are expected to impact the upcoming May 2016 redetermination. To the extent a reduction in the borrowing base results in existing indebtedness exceeding the reduced borrowing base, mandatory repayment of the borrowing base deficiency would be required as described above . Although the outcome of the May redetermination is uncertain, TUSA believes that it has sufficient cash on hand to be able to make any such mandatory repayment. Any such non-payment could result in an event of default. The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities, consolidated senior secured debt to consolidated EBITDAX, and interest to consolidated EBITDAX. As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of secured debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recover. For any such breach of a financial covenant in fiscal year 2017, the Company intends to provide an equity contribution to TUSA to cure such breach, subject to approval by the Company’s Board of Directors. RockPile Credit Facility . On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility. On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. The RockPile credit facility has a maturity date of March 25, 2019. Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5% , or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0% ), plus an applicable margin that ranges between 1.5% and 2.25% , depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25% , depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter. RockPile pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor. The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges. Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures. RockPile has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due ( 45 days after quarter ends and 120 days after its fiscal year end) to cure such a breach (an equity cure) . The cure amount is defined as the amount which, if added to EBITDA for the test period in which a default of the financial covenant occurred, would cause the financial covenant for such test period to be satisfied. RockPile may exercise this cure right in no more than two of any four consecutive fiscal quarters and no more than five times during the term of the credit facility. To date, RockPile has not exercised an equity cure right. On April 13, 2016, RockPile entered into Amendment No. 2, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility. Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but there are no guarantees these discussions or negotiations will be successful. If RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the RockPile equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default. TUSA 6.75% Notes . On July 18, 2014, TUSA entered into an Indenture (the “Indenture”) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (the “TUSA 6.75% Notes”). The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act. The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014. The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.5 million of offering costs which have been deferred and are being recognized using the effective interest method over the life of the notes. TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture. On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at a price equal to 105.063% of the principal amount of the notes redeemed ( 103.375% after July 15, 2018, 101.688% after July 15, 2019 and 100% on and after July 15, 2020), plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at 106.75% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings and cash contributions to capital stock. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the repurchase date. The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market. In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $6.6 million. During fiscal year 2016, TUSA repurchased additional TUSA 6.75% Notes with a face value of $31.1 million for $13.2 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $17.9 million. The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any restricted subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets. These covenants are subject to a number of important exceptions and qualifications. As of January 31, 2016 , TUSA was in compliance with all covenants under the TUSA 6.75% Notes. Convertible Note. On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”) that became convertible after November 16, 2012, in whole or in part, into the Company’s common stock at a conversion rate of one share per $8.00 of outstanding balance. The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after September 30, 2017, the Company has the option to make such interest payments in cash. As of January 31, 2016 , $22.8 million of accrued interest has been added to the principal balance of the Convertible Note. The Convertible Note does not have a stated maturity. Following July 31, 2017, if the trading price of the Company’s common stock exceeds $11.00 per share for 20 consecutive trading days and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following July 31, 2020, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal plus accrued and unpaid interest, payable in cash. Further, following July 31, 2022, a change of control of the Company, or certain other fundamental changes (as defined in the indenture), the holder of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to July 31, 2017. Future Maturities of Outstanding Debt. Scheduled annual maturities (including the impact of the reclassification of the RockPile debt) of long-term debt outstanding as of January 31, 2016 were as follows: For the Years Ending January 31, (in thousands): 2017 $ 2018 2019 2020 2021 Thereafter $ |
Hedging And Commodity Derivativ
Hedging And Commodity Derivative Financial Instruments | 12 Months Ended |
Jan. 31, 2016 | |
Hedging And Commodity Derivative Financial 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 or reduce existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with six counterparties. The Company has netting arrangements with each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company’s commodity derivative instruments are measured at fair value. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows: For the Years Ended January 31, (in thousands) 2014 2015 2016 Realized commodity derivative gains (losses) $ $ $ Unrealized commodity derivative gains (losses) Commodity derivative gains (losses), net $ $ $ The Company’s commodity derivative contracts as of January 31, 2016 are summarized below: Weighted Weighted Weighted Contract Quantity Average Average Average Type Basis (1) (Bbl/d) Put Strike Call Strike Price February 1, 2016 to January 31, 2017 Swap NYMEX n/a n/a $ February 1, 2017 to January 31, 2018 Swap NYMEX n/a n/a $ (1) “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange. In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million. The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016. The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and 2016 are summarized below. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value. (in thousands) January 31, 2015 January 31, 2016 Current Assets: Crude oil derivative contracts $ $ Other Long-Term Assets: Crude oil derivative contracts — Total derivative asset $ $ Long-Term Liabilities: Crude oil derivative contracts $ — $ — Total derivative liability $ — $ — |
Oil And Natural Gas Properties
Oil And Natural Gas Properties | 12 Months Ended |
Jan. 31, 2016 | |
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, 2014, 2015 and 2016: For the Years Ended January 31, (in thousands) 2014 2015 2016 Costs incurred during the period Acquisition of properties: Proved $ $ $ Unproved Exploration Development Oil and natural gas expenditures Asset retirement obligations, net $ $ $ During fiscal years 2014, 2015 and 2016, we acquired oil and natural gas properties, and participated in the drilling and completion of wells, for total consideration of approximately $434.4 million, $545.7 million, and $153.3 million, including $121.6 million, $138.8 million, and $0.8 million, respectively, for the acquisition of oil and natural gas properties. Total consideration paid includes common stock of $2.4 million in fiscal year 2014. During fiscal years 2014, 2015 and 2016, we capitalized $3.7 million, $4.8 million, and $4.3 million, respectively, of internal land, geology, and operations department costs directly associated with property acquisition, exploration (including lease record maintenance), and development. The following table summarizes oil and natural gas property costs not being amortized at January 31, 2016, by year that the costs were incurred: Fiscal Year Costs Incurred 2013 (in thousands) and prior 2014 2015 2016 Acquisition $ $ $ $ Exploration — Capitalized interest — Total $ $ $ $ Unproved properties includes $78.4 million of costs not being amortized as of January 31, 2016. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization. The majority of the unproved oil and natural gas property costs, which are not subject to amortization, relate to oil and natural gas property acquisitions and leasehold acquisition costs. The Company transferred $14.5 million, $67.2 million and $35.1 million of unproved costs into the amortization base in fiscal years 2014, 2015 and 2016, respectively, due to impairment, development of acreage or placement of assets into service. In fiscal year 2016, the Company impaired unproved leasehold costs for substantially all acreage not held by production. Due to the long estimated economic lives of its wells and the majority of the unproved costs related to leasehold costs for acreage held by production, the Company expects that only a minor portion of its unproved property costs as of January 31, 2016 will be reclassified to proved properties within the next five years unless there is a dramatic increase in commodity pric es. |
Acquisitions
Acquisitions | 12 Months Ended |
Jan. 31, 2016 | |
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): As of June 30, 2014 Cash $ Total consideration given $ Fair value allocation of purchase price: Oil and natural gas properties: Proved properties $ Unproved properties Total oil and natural gas properties Accounts payable Asset retirement obligations assumed Fair value of net assets acquired $ Pro Forma Financial Information. The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak, in August of 2013, and Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2013. For the Years Ended January 31, (in thousands, except per share data) 2014 2015 Operating revenues $ $ Net income (loss) $ $ Earnings (loss) per common share Basic $ $ Diluted $ $ Weighted average common shares outstanding: Basic Diluted For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012. The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.4 million and $16.5 million for fiscal years 2015 and 2014, respectively. The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common stock had been issued, as of the beginning of the period, nor are they necessarily indicative of future results. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Jan. 31, 2016 | |
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 2016: For the Years Ended January 31, (in thousands) 2015 2016 Balance at the beginning of the period $ $ Liabilities incurred Revision of estimates Sale of assets Liabilities settled Accretion Balance at the end of the period Less current portion of obligations Long-term ARO $ $ The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets. A significant portion of the current obligations relates to the reclamation of man-made ponds holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada of $4.8 million and $4.9 million as of January 31, 2015 and January 31, 2016, respectively. Internal engineering re-assessment of Canadian ARO resulted in revisions of $2.7 million and $1.3 million to the ARO during fiscal years 2015 and 2016. Since our Canadian oil and natural gas properties were fully impaired, the ARO revisions were expensed and included in depreciation and amortization expenses in the accompanying consolidated statements of operations. |
Equity Investment And Equity In
Equity Investment And Equity Investment Derivatives | 12 Months Ended |
Jan. 31, 2016 | |
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”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund. The joint venture entity, Caliber, was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF. In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF and the general partner of Caliber, which is owned and controlled equally between Triangle Caliber Holdings and FREIF. Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units. FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015. Triangle Caliber Holdings made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units. Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber. Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants (Series 5) for the purchase of an additional 906,667 Class A Units. The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Class A (Series 1 through 4) Warrants at strike prices and expiration dates noted below and 1,269,333 Class A (Series 6) Warrants with a strike price of $12.50 and an expiration date of February 2, 2018. The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and 2016 and the strike prices for exercising warrants as of January 31, 2016 : Expiration Strike Price at As of As of Date January 31, 2016 January 31, 2015 January 31, 2016 Class A Units — $ — Series 1 Warrants October 1, 2024 $ Series 2 Warrants October 1, 2024 $ Series 3 Warrants September 12, 2025 $ Series 4 Warrants September 12, 2025 $ Series 6 Warrants February 2, 2018 $ — The Company’s investment interest in Caliber is considered to be variable, and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk. The Company is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to its economic performance. Under the equity method, our investment will be adjusted each period for contributions made, distributions received, the change in the fair value of our holdings of equity investment derivatives of Caliber, our share of Caliber’s net income and accretion of any basis differences. Our maximum exposure to loss related to Caliber is limited to our equity investment. We evaluate our equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. As a result of the extended low commodity price environment, TUSA and other exploration and production companies have significantly curtailed their development activities. This has adversely impacted the fair value of our investment in Caliber. The carrying value of our investment in Caliber exceeded its fair value at January 31, 2016. Since we deemed this decline in fair value to be other than temporary, we recorded a net impairment of $25.0 million in fiscal year 2016. The following summarizes the activities related to the Company’s equity investment in Caliber for the years ended January 31, 2015 and 2016: For the Years Ended January 31, (in thousands) 2015 2016 Balance at beginning of year $ $ Capital contributions — — Distributions — Equity investment share of net income before intra-company profit eliminations Change in fair value of warrants Other than temporary impairment — Balance at end of year $ $ Fair value of trigger unit warrants and warrants at end of year $ $ Equity Investment Derivatives. At January 31, 2015 and 2016, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources. Financial Information of Unconsolidated Equity Method Investee. The following table summarizes the financial information of our equity method investee (in thousands): For the Years Ended January 31, (in thousands) 2014 2015 2016 Revenue $ $ $ Gross profit $ $ $ Net income (loss) $ $ $ January 31, 2015 January 31, 2016 Current assets $ $ Noncurrent assets Total assets $ $ Current liabilities $ $ Noncurrent liabilities Total liabilities $ $ Minority interests $ $ |
Capital Stock
Capital Stock | 12 Months Ended |
Jan. 31, 2016 | |
Capital Stock [Abstract] | |
Capital Stock | 10. CAPITAL STOCK The C ompany had 106. 5 million shares of common stock issued or reserved for issuance at January 31, 2016 . At January 31, 2016 , the Company had 7 5.8 million shares of common stock issued and outstanding . The Company also had 1.3 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan, 6.0 million shares of common stock reserved for issuance under its CEO Stand-Alone Stock Option Agreement, 2.8 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”), and 2.9 million shares of reserved common stock that remained available for issuance under the 2014 Plan. Lastly, the Company had 17.6 million shares of common stock reserved for issuance pursuant to the Convertible Note. The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. There were no common stock repurchases for the years ended January 31, 2016 and 2014. As of January 31, 2016 , the number of shares of common stock remaining available for repurchase under the Board approved program was 5,811,091 shares. |
Share-Based Compensation
Share-Based Compensation | 12 Months Ended |
Jan. 31, 2016 | |
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 on a straight-line basis over the applicable vesting period. On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions. The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries. The maximum number of shares of common stock issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions. For the years ended January 31, 2014 , 2015 and 2016 , the Company recorded share-based compensation as follows : For the Years Ended January 31, (in thousands) 2014 2015 2016 Restricted stock units $ $ $ Stock options RockPile Series B Units Less amounts capitalized to oil and natural gas properties Compensation expense $ $ $ Restricted Stock Units . During the year ended January 31, 2016 , the Company granted 1,983,843 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of January 31, 2016 , there was approximately $14.7 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.1 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. The following table summarizes the activity for our restricted stock units during the years ended January 31, 2014 , 2015 and 2016 : Weighted Average Number of Award Date Shares Fair Value Restricted stock units outstanding - January 31, 2013 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2014 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2015 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2016 $ Stock Options. The following table summarizes the stock options outstanding at January 31, 2016 : Remaining Exercise Price Contractual Life Number of Shares per Share (years) Outstanding Exercisable $ $ $ $ $ $ $ $ Weighted average exercise price per share $ $ Weighted average remaining contractual life As of January 31, 2016 , there was approximately $10.8 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.3 years. RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting equity awards that generally vest over a requisite service period of 3 to 5 years. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units. The Series B Units are intended to constitute “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93-27 and 2001-43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be zero. RockPile may designate a “Liquidation Value” applicable to each tranche of a Series B Unit grant so as to constitute a net profits interest. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile, be distributed with respect to the initial Series B Unit tranche if, immediately prior to the issuance of a new Series B Unit tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities) were distributed. The Series A Units are entitled to a return of contributed capital and an 8% preferred return on such capital before Series B Units participate in profits. The initial Series B tranche (Series B-1 Units) participates pro rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B-1 Unit until total cumulative distributions to the Series A Units total $40.0 million. As of January 31, 2015, the $40.0 million cumulative distribution threshold was met. Therefore, future distributions will be allocated to the Series B-1 Units until the per unit profits distributed to the Series B-1 Units is equivalent to the per unit profits distributed to the Series A Units. Thereafter, all further distributions will be distributed on a pro rata basis. Subsequently issued Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B-1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance. RockPile’s limited liability company agreement was amended on January 31, 2015 to permit distributions to holders of vested Series B Units as prepayment for future amounts payable to them upon a RockPile liquidity event. In the event a holder of vested Series B Units receives such a pre-liquidity event distribution, their capital account will be adjusted to reflect the prepayment. The following table summarizes the activity for RockPile’s Series B Units for the years ended January 31, 2014, 2015 and 2016: Series Series Series Series Series Series B-1 units B-2 units B-3 units B-4 units B-5 units B-6 units Total Units outstanding - January 31, 2013 — — — — Units forfeited — — — — — — — Units redeemed — — — — — — — Units granted — — — — — Units outstanding - January 31, 2014 — — — Units forfeited — — — — — Units redeemed — — — Units granted — — — Units outstanding - January 31, 2015 — — Units redeemed — — — — — — — Units granted — — — — Units forfeited — — — Units outstanding - January 31, 2016 Vested — — Unvested — — Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period. As of January 31, 2016 , there was approximately $1.9 million of unrecognized compensation expense related to unvested Series B Units. We expect to recognize such expense on a pro-rata basis on the Series B Units’ over the remaining vesting period of the related awards of 2.9 years. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Jan. 31, 2016 | |
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 2016 , by level within the fair value hierarchy: As of January 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total Assets: Commodity derivative assets $ — $ $ — $ Equity investment derivative assets $ — $ — $ $ Liabilities: RockPile earn-out liability $ — $ $ — $ As of January 31, 2016 (in thousands) Level 1 Level 2 Level 3 Total Assets: Commodity derivative assets $ — $ $ — $ Equity investment derivative assets $ — $ — $ $ Liabilities: Commodity derivative liabilities $ — $ — $ — $ — RockPile earn-out liability $ — $ $ — $ Commodity Derivative Instruments. The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating. In considering counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At January 31, 2016 , commodity derivative instruments utilized by the Company consist ed of swaps. The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange. As such, the Company has classified these commodity derivative instruments as Level 2. Caliber Class A Warrants (Series 1 through Series 4 and Series 6). The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“MCS”) model. For each MCS, the values of the Class A Units and Class A Warrants were forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. At January 31, 2016, the fair values of the underlying Class A Units and Class A Warrants were estimated employing an income approach using a MCS model and discounted cash flows, and a market approach based on observed valuation multiples for comparable public companies. Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company has classified these instruments as Level 3. Earn-out Liability. The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well Service, Inc. using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2. Nonrecurring Fair Value Measurements. For certain situations, the Company is also required to make fair value measurements for assets and liabilities in the consolidated balance sheet after their initial recognition. At January 31, 2016, the Company was required to make fair value measurements for comparisons to the carrying values of long-lived assets and its equity investment in Caliber Class A Units to assess whether any impairments were required. The Company determined its estimate of the fair value of long-lived assets, primarily oilfield services equipment, using discounted cash flow models, replacement cost estimates from a major third-party vendor, and a market approach based on estimates from an independent, third party appraiser. Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company considers the related long-lived assets as Level 3. As described above, the MCS model that is used by the Company to determine the fair value of the Caliber Class A Warrants is also used by the Company to determine the fair value of the Company’s investment in Caliber Class A Units in its other than temporary impairment evaluation, Therefore, the Company considers its investment in Caliber Class A Units as Level 3. Fair Value of Financial Instruments . The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above), and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable and the fair values of the other notes and mortgages payable is not significantly different than their carrying values. The fair value of the TUSA 6.75% Notes is derived from quoted market prices (Level 1). The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing (Level 3). This disclosure does not impact our financial position, results of operations or cash flows. The carrying values and fair values of the Company’s debt instruments are as follows : January 31, 2015 January 31, 2016 Carrying Estimated Carrying Estimated (in thousands) Value Fair Value Value Fair Value Revolving credit facilities $ $ $ $ TUSA 6.75% notes 5% convertible note Other notes and mortgages payable |
Income Taxes
Income Taxes | 12 Months Ended |
Jan. 31, 2016 | |
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) 2014 2015 2016 Current tax expense (benefit) $ — $ — $ Deferred tax expense (benefit) Federal State Foreign — — Valuation allowance - United States and Canada — — Total income tax provision (benefit) $ $ $ Income (loss) before income taxes $ $ $ Effective income tax rate A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35.0% to the Company’s income tax provision (benefit) is as follows: For the Years Ended January 31, (in thousands) 2014 2015 2016 Federal statutory tax expense (benefit) $ $ $ State income tax expense / (benefit), net of federal income tax benefit Permanent differences Difference in foreign tax rates Effect of tax rate change Credits State NOL adjustment — Bad debt deduction for receivables from Elmworth — Attribute reduction - cancellation of debt exclusion - Elmworth — Changes in valuation allowance Other Provision (benefit) for income taxes $ $ $ The components of Triangle’s net deferred income tax assets and liabilities are as follows: For the Years Ended January 31, (in thousands) 2015 2016 Deferred income tax assets: United States net losses carried forward $ United States oil and natural gas properties — Asset retirement obligations Accruals — Stock-based compensation Other Total deferred income tax assets Deferred income tax liabilities: United States oil and natural gas properties — Investment in Caliber Hedging liabilities Other — — Total deferred income tax liabilities Valuation allowance Net deferred income tax asset (liability) $ $ — As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $779.0 million for the year ended January 31, 2016. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $ 286.0 million at January 31, 2016. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of January 31, 2016 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. In fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense or for state income taxes. Triangle has also determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized since all Canadian exploration and production activities have ceased other than reclamation activities. Therefore, all remaining Canadian deferred tax assets will have a full valuation allowance placed against them. The Company has net operating loss carryovers as of January 31, 2016 of $286.0 million for federal income tax purposes and $280.2 million for financial reporting purposes. The difference of $5.8 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The United States NOL carryforwards begin expiring in 2024. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years. At January 31, 2015 and 2016, we have no unrecognized tax benefits that would impact our effective tax rate, and we have made no provisions for interest or penalties related to uncertain tax positions. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards. The tax years for fiscal years ending 2013 to 2016 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for examination for fiscal years 2013 to 2016, except for Colorado which is open for the fiscal years 2012 to 2016. We also file with various Canadian taxing authorities which remain open for fiscal years 2012 to 2016 . |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Jan. 31, 2016 | |
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 in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $303.4 million was outstanding at January 31, 2016 . The agreements permit TUSA to build up credits against future monthly commitments for the excess of actual monthly revenues over the minimum monthly revenues. As of January 31, 2016, TUSA has built up a cumulative credit of $41.5 million. Credits may be carried forward for a period of four years from the date of the accrual. TUSA is required to pay Caliber for any deficiency of actual monthly revenues if no credits are available. TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date in March 2015. The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water. TUSA incurred fees to Caliber under these agreements of $15.0 million, $36.6 million and $53.9 million, d uring the years ended January 31, 2014, 2015 and 2016. TUSA had payables to Caliber of $5.0 million and $9.6 million at January 31, 2015 and 2016, respectively. TUSA also sold one salt water disposal well in fiscal year 2015 and one salt water disposal well in fiscal year 2016 to an affiliate of Caliber for net proceeds of $1.5 million and $6.0 million, respectively. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Jan. 31, 2016 | |
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 $0.8 million, $1.8 million, and $ 5.2 million for the fiscal years ended January 31, 2014, 2015, and 2016, respectively. As of January 31, 2016, the future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are: Annual Rental Amount Fiscal Year Ending January 31, (in thousands) 2017 $ 2018 $ 2019 $ 2020 $ 2021 and thereafter $ CEO Transaction Bonus Program. Pursuant to the Third Amended and Restated Employme nt Agreement, dated July 4, 2013 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its initial investment in the relevant entity (“Transaction Bonus”). The amount of this Transaction Bonus would be equivalent to 5% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the Transaction Bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. On January 31, 2015, Triangle and Mr. Samuels entered into a First Amendment to Third Amended and Restated Employment Agreement (the “First Amendment”) that modified the Employment Agreement to permit Triangle’s Board to authorize distributions to Mr. Samuels pursuant to his Transaction Bonus program in advance of defined liquidity events. Any Board authorized distribution to Mr. Samuels related to the Transaction Bonus program would reduce any future award payable to Mr. Samuels following a liquidity event. There are no clawback provisions in the First Amendment that would require Mr. Samuels to repay Triangle for any excess distributions or payments received. In connection with the First Amendment, the Board authorized the payment of a Transaction Bonus to Mr. Samuels of $1.9 million which was recorded as a liability as of January 31, 2015 and subsequently paid in the first quarter of fiscal year 2016. The Company has determined that the contingent liability associated with such a bonus is not probable at January 31, 2016 because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors and therefore, no amounts have been recorded in the accompanying consolidated balance sheets at January 31 , 2016. Other. In addition, the Company is a party from time to time to other claims and legal actions that arise in the ordinary course of business. The Company believes that the ultimate impact, if any, of these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity. |
Supplemental Disclosures Of Cas
Supplemental Disclosures Of Cash Flow Information | 12 Months Ended |
Jan. 31, 2016 | |
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) 2014 2015 2016 Cash paid during the period for: Interest expense $ $ $ Income taxes $ — $ $ — Non-cash investing activities: Additions (reductions) to oil and natural gas properties through: Increase (decrease) in accounts payable and accrued liabilities $ $ $ Issuance of common stock $ $ — $ — Capitalized stock based compensation $ $ $ Change in asset retirement obligations $ $ $ Acquisition of oilfield services equipment through notes payable and liabilities $ $ — $ — |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Jan. 31, 2016 | |
Quarterly Financial Information [Abstract] | |
Quarterly Financial Information | 17. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The Company’s quarterly financial information for fiscal years 2015 and 2016 is as follows: For the Year Ended January 31, 2016 (1) First Second Third Fourth (in thousands) Quarter Quarter Quarter Quarter Total revenue $ $ $ $ Income (loss) from operations (2) $ $ $ $ Net income (loss) $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ For the Year Ended January 31, 2015 (1) First Second Third Fourth (in thousands) Quarter Quarter Quarter Quarter Total revenue $ $ $ $ Income (loss) from operations (2) $ $ $ $ Net (loss) income $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ (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 Oil
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) | 12 Months Ended |
Jan. 31, 2016 | |
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, 2016, the Company’s oil and natural gas producing activities were conducted in the Williston Basin in the continental United States. All of our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams, Stark, or Dunn, or in the Montana counties of Roosevelt, Sheridan, Madison or Richland. The Company has ceased all Canadian exploration and production activities and its oil and natural gas properties were fully impaired as of January 31, 2012. Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Such prices are also adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices utilized in the calculation of a standardized measure of discounted future net cash flows related to proved oil and natural gas reserves (“Standardized Measure”) The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended January 31, 2016. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2014, January 31, 2015 and January 31, 2016 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. The reserve estimates presented in the following tables are expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”), thousands of barrels of natural gas liquids (“Mbbls”) and thousands of barrels of oil equivalent (“Mboe”). Crude Oil Natural Gas NGL (Mbbls) (MMcf) (Mbbls) Mboe Total proved reserves at January 31, 2013 — Revisions of previous estimates Purchase of reserves Extensions, discoveries and other additions Sale of reserves — Production Total proved reserves at January 31, 2014 Revisions of previous estimates Purchase of reserves Extensions, discoveries and other additions Sale of reserves — Production Total proved reserves at January 31, 2015 Revisions of previous estimates Purchase of reserves — — — — Extensions, discoveries and other additions Sale of reserves — — Production Total proved reserves at January 31, 2016 Proved Developed Reserves included above: January 31, 2013 — January 31, 2014 January 31, 2015 January 31, 2016 Proved Undeveloped Reserves included above: January 31, 2013 — January 31, 2014 January 31, 2015 January 31, 2016 The following average prices are reflected in the calculation of the Standardized Measure. These prices represent the unescalated twelve month arithmetic average of the first day of the month posted prices, adjusted for quality, energy content, transportation fees and regional price differentials. For the Years Ended January 31, 2014 2015 2016 Oil price per barrel $ $ $ Natural gas price per Mcf $ $ $ Natural gas liquids price per barrel $ $ $ Notable changes in proved reserves for fiscal year 2016 included: Revisions of previous estimates. In fiscal year 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 13.8 MMboe. Upward revisions of 9.4 MMboe that mostly related to well performance were more than offset by downward adjustments of 23.2 MMboe that resulted from proved reserves that became uneconomic on a PV-10 basis due to the significantly lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at January 31, 2016 as compared to January 31, 2015. Extensions and discoveries. In fiscal year 2016, extensions of 8.8 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of exploratory wells and proved undeveloped wells and the extensions of reserves for offsetting locations. Notable changes in proved reserves for fiscal year 2015 included: Purchase of reserves. In fiscal year 2015, total purchases of minerals in place of 4.2 MMboe were primarily attributable to the Marathon acquisition which is further described in the “Acquisitions” footnote, which increased the Company’s proved reserves. Extensions and discoveries. In fiscal year 2015, extensions of 17.0 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of wells, particularly operated wells, and other parties completing wells offsetting our properties. Notable changes in proved reserves for fiscal year 2014 included: Revisions of previous estimates. In fiscal year 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 4.3 MMboe. The upward revision in crude oil proved reserves was primarily due to longer production histories that favorably supported the increase in proved oil reserves. The 859 MMcf reduction in natural gas reserves and the 1,762 Mbbls increase in NGL reserves reflect agreements and arrangements at the end of fiscal year 2014 to have the majority of our proved natural gas reserves processed to extract NGLs and dry residue gas. Purchase of reserves. In fiscal year 2014, total purchases of minerals in place of 8.3 MMboe were primarily attributable to the Kodiak acquisition which is further described in the “Acquisitions” footnote, which increased the Company’s proved reserves. Extensions and discoveries. In fiscal year 2014, the 15.5 MMboe of proved reserves added by extensions and discoveries in North Dakota are primarily due to our successful completions of wells, particularly operated wells, and other parties completing wells offsetting our properties. Proved Undeveloped Reserves. At January 31, 2016, we had proved undeveloped oil and natural gas reserves of 10.4 M Mboe, down 12.5 M Mboe from 22.9 M Mboe at January 31, 2015. Changes in our proved undeveloped reserves are summarized in the following table: (Mboe) Gross Wells Net Wells Proved Undeveloped Reserves at January 31, 2013 Conversion to developed reserves in fiscal year 2014 Traded for net acres in other drill spacing units Revisions — — Acquisitions Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2014 Conversion to developed reserves in fiscal year 2015 Revisions Acquisitions Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2015 Conversion to developed reserves in fiscal year 2016 Revisions Acquisitions — — — Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2016 During fiscal year 2016, we invested approximately $48.0 million (averaging $8.3 million per net well) related to the drilling and completion of the 12 gross ( 5.8 net) wells that converted 2.7 M Mboe of proved undeveloped reserves to proved developed reserves. For proved undeveloped (“PUD”) locations at January 31, 2016, the following table provides further information on the timing and status of operated and non-operated locations: PUD Development Wells Locations Gross Net Proved undeveloped locations: For which Triangle operated wells are to be drilled and completed by January 31, 2021 For which non-operated wells were in-progress at January 31, 2016 and are expected to be completed in fiscal year 2017 — — — That are non-operated wells with drilling permits — — — That are non-operated wells to be drilled by January 31, 2021 Standardized Measure of Discounted Future Net Cash Flows Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2015 and 2016 (i) a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and (ii) changes in the Standardized Measure for fiscal years 2015 and 2016. Under that accounting guidance : · Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the fiscal year-end estimated future proved reserve quantities. · Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. · Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using fiscal year-end cost rates and assuming continuation of existing economic conditions. · Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and natural gas properties and (ii) net operating loss carryforwards relating to our oil and natural gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure. These assumptions do not necessarily reflect the Company’s expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations. The following summary sets forth the Company’s Standardized Measure for January 31, 2014, 2015 and 2016: For the Years Ended January 31, (in thousands) 2014 2015 2016 Future cash inflows $ $ $ Future costs: Production Development Future income tax expense — Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows relating to proved reserves $ $ $ Because the estimated salvage value of equipment exceeds the related abandonment costs for well plugging and site restoration costs, future development costs at January 31, 2016 of $150.1 million does not include any net abandonment costs. The principle sources of change in the Standardized Measure are shown in the following table: For the Years Ended January 31, (in thousands) 2014 2015 2016 Standardized measure, beginning of period $ $ $ Extensions and discoveries, net of future production and development costs Sales, net of production costs Previously estimated development costs incurred during the period Revision of quantity estimates Net change in prices, net of production costs Acquisition of reserves — Divestiture of reserves Accretion of discount Changes in future development costs Change in income taxes Change in production timing and other Standardized measure, end of period $ $ $ 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. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Jan. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | 19. SUBSEQUENT EVENTS On April 13, 2016, RockPile entered into Amendment No. 2 with Citibank, N.A., as administrative agent and collateral agent, and the banks and other financial institutions party thereto. Amendment No. 2 amends that certain Credit Agreement, dated March 25, 2014, as amended on November 13, 2014 (the “Credit Agreement”), as reported in Current Reports on Form 8-K filed with the SEC on March 31, 2014 and November 19, 2014, respectively, to waive any default or event of default that may have arisen or that may arise from the failure of RockPile to (i) comply with the financial performance covenants in the Credit Agreement as of January 31, 2016 and April 30, 2016, and (ii) deliver its audited financial statements for the fiscal year ending January 31, 2016 without any qualification from RockPile’s independent accountants. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility. |
Summary Of Significant Accoun27
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Jan. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
Basis Of Presentation | Basis of Presentation. These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts. No condensed consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented. |
Liquidity and Ability to Continue as a Going Concern | Liquidity and Ability to Continue as a Going Concern . The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, its liquidity outlook has changed since the third quarter of fiscal year 2016. Continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. These factors and the RockPile debt compliance issues raise substantial doubt about the Company’s ability to continue as a going concern. RockPile Liquidity and Covenants . On April 13, 2016, RockPile entered into Amendment No. 2 to the Credit Agreement (“Amendment No. 2”), which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 or may occur as of April 30, 2016. Following the execution of Amendment No. 2, RockPile is precluded from drawing additional funds absent further amendment of the facility. Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing as discussed further in Note 4. RockPile remains in discussions with its bank syndicate and various providers of external capital to refinance the existing indebtedness, but the success of these discussions and negotiations is uncertain. In addition, i f RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile. As a result, substantial doubt exists regarding the ability of RockPile, our oilfield services subsidiary, to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default. TUSA Liquidity and Covenants . As of January 31, 2016, TUSA had $243.8 million drawn, plus an additional $2.5 million outstanding in letters of credit, resulting in remaining available borrowing capacity of $103.7 million under the TUSA credit facility. On March 31, 2016, TUSA borrowed $103.7 million under its credit facility, representing the entire amount remaining thereunder relative to the current borrowing base of $350.0 million. As a result, no further extensions of credit currently are available under the TUSA credit agreement. As of January 31, 2016, TUSA was in compliance with all financial covenants under the TUSA credit facility. Although it is difficult to forecast future operations in this low commodity price environment, TUSA anticipates that it could breach its ratio of consolidated debt to EBITDA or its interest coverage ratio covenants (as defined in the credit agreement) in fiscal year 2017 if commodity prices do not recover or it is unable to obtain cure financing or a waiver or amendment from its lenders, with whom it is engaged in ongoing discussions . Also, the current ratio covenant could be adversely impacted if a redetermination significantly lowers the borrowing base. If TUSA were to breach a covenant in a future period, TUSA has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due ( 45 days after quarter ends and 90 days after its fiscal year end) to cure such a breach, also known as an equity cure. Although there are many risks and uncertainties in this environment, TUSA believes that it will be able to reach an agreement with its banks, find acceptable alternative financing or obtain equity cure contributions to prevent or cure an event of default under its credit facility. However, there can be no assurances that these plans can be achieved. If TUSA were to breach any financial covenants under its credit facility and such breach became an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes (as defined below) that could enable holders of the TUSA 6.75% Notes to declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable. While we believe our existing capital resources, including our cash flow from TUSA’s operations and cash on hand at TUSA and Triangle, are sufficient to conduct our operations of TUSA and Triangle through fiscal year 2017 and into fiscal year 2018, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted if oil and natural gas prices remain depressed for an extended period of time. Further, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations. If we are not able to meet our debt covenants in future periods, or if our borrowing base is significantly reduced, we may be required but unable to refinance or restructure all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the TUSA credit facility. Further, failing to comply with the financial and other restrictive covenants in the TUSA credit facility and the TUSA 6.75% Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations. Triangle Liquidity . Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful. |
Use of Estimates | Use of Estimates. In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of unproved properties, investment in equity method investees and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these consolidated financial statements. |
Principles of Consolidation | Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. The investment in Caliber is accounted for utilizing the equity method of accounting. |
Cash And Cash Equivalents | Cash and Cash Equivalents. 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 2016 Oil and natural gas sales $ $ Joint interest billings Oilfield services revenue Other Total accounts receivable $ $ 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): For the Years Ended January 31, 2014 2015 2016 Oil & Gas Customer A N/A Oil & Gas Customer B Oil & Gas Customer C N/A N/A Oilfield Services Customer A N/A N/A Oilfield Services Customer B N/A Oilfield services Customer C N/A N/A Oilfield services Customer D N/A 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. The loss of any significant oilfield services customer is detrimental to RockPile during this low price competitive pressure pumping and oilfield services environment but would not be expected to have a material adverse effect on the Company. |
Inventories | Inventories. Inventories, included in other current assets, consist of well equipment, sand, chemicals and ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors utilized in evaluating net realizable value. |
Oil And Natural Gas Properties | Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced. Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2014, 2015 and 2016 was $52.0 million, $106.9 million and $90.4 million, respectively. At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation. January 31, 2014 January 31, 2015 January 31, 2016 Oil (per Bbl) $ $ $ Natural gas (per MMbtu) $ $ $ Natural gas liquids (per Bbl) $ $ $ We recognized impairments to our proved oil and natural gas properties of $779.0 million for the year ended January 31, 2016, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the years ended January 31, 2014 and 2015. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids (“NGL”) prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date. The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. |
Oil And Natural Gas Reserves | 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 consisted of the following as of: (in thousands) January 31, 2015 January 31, 2016 Oilfield services equipment $ $ Accumulated depreciation Depreciable assets, net Assets not placed in service Total oilfield services equipment, net $ $ Land $ $ Building and leasehold improvements Vehicles Software, computers and office equipment Capital leases Accumulated depreciation Depreciable assets, net Assets not placed in service Total other property and equipment, net $ $ |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets. Long ‑lived assets such as property and equipment and identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long ‑lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long ‑lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined using various valuation techniques including discounted cash flow models, quoted market values, and third ‑party independent appraisals, as considered necessary. No impairment losses were recognized in fiscal years 2014 and 2015 and an impairment loss of $14.9 million, primarily related to oilfield services equipment, was recorded in fiscal year 2016. |
Debt Issuance Costs | Debt Issuance Costs. Debt issuance costs related to the TUSA 6.75% Notes and the Convertible Note, each as defined below, are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets, and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets, and are amortized to interest expense on a straight-line basis over the term of the agreement . |
Equity Investment | 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. |
Derivative 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) 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 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 and 2016. Oilfield Services Revenue . The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. |
Share-Based Compensation | Share- Based Compensation . Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the vesting period. The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. |
Earnings Per Share | Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted earnings per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive. The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented : For the Years Ended January 31, (in thousands) 2014 2015 2016 Dilutive — Anti-dilutive shares The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented: For the Years Ended January 31, (in thousands, except per share data) 2014 2015 2016 Net income (loss) attributable to common stockholders $ $ $ Effect of 5% convertible note conversion — Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion $ $ $ Basic weighted average common shares outstanding Effect of dilutive securities — Diluted weighted average common shares outstanding Basic net income (loss) per share $ $ $ Diluted net income (loss) per share $ $ $ |
Recent Accounting Developments | Adopted and Recently Issued Accounting Pronouncements . In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014 ‑ 09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014 ‑ 09 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 2014 ‑ 09 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its consolidated financial statements. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle. Early adoption is permitted. The Company adopted ASU 2015-03 and ASU 2015-15 as of January 31, 2016, and as a result, $9.8 million of debt issuance costs related to the TUSA 6.75% Notes and the Convertible Note were reclassified from other long-term assets to long-term debt in the Company’s consolidated balance sheet as of January 31, 2015. The Company elected to continue presenting the debt issuance costs associated with its credit facility as other long-term assets in the consolidated balance sheets. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted. The adoption of this standard will not have a material impact on the Company’s consolidated financial statements. In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination. Under ASU 2015-16, the cumulative impact of a measurement-period adjustment (including the impact on prior periods) should instead be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements. In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). The objective of this ASU is to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. This standard may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted. The Company adopted ASU 2015-17 as of January 31, 2016 on a retrospective basis, which represents a change in accounting principle. As a result, $19.5 million of deferred income taxes previously included within current liabilities were reclassified to noncurrent in the Company’s consolidated balance sheet as of January 31, 2015. In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after Dec. 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations. |
Reclassifications | Reclassifications . Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported. |
Summary Of Significant Accoun28
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
Schedule of accounts receivable | For the Years Ended January 31, 2015 2016 Oil and natural gas sales $ $ Joint interest billings Oilfield services revenue Other Total accounts receivable $ $ |
Percentages of oil and gas revenue from sales to customers and oilfield services customers | For the Years Ended January 31, 2014 2015 2016 Oil & Gas Customer A N/A Oil & Gas Customer B Oil & Gas Customer C N/A N/A Oilfield Services Customer A N/A N/A Oilfield Services Customer B N/A Oilfield services Customer C N/A N/A Oilfield services Customer D N/A N/A |
Schedule of 12 month simple average spot prices | January 31, 2014 January 31, 2015 January 31, 2016 Oil (per Bbl) $ $ $ Natural gas (per MMbtu) $ $ $ Natural gas liquids (per Bbl) $ $ $ |
Schedule of oilfield services equipment and other property and equipment | (in thousands) January 31, 2015 January 31, 2016 Oilfield services equipment $ $ Accumulated depreciation Depreciable assets, net Assets not placed in service Total oilfield services equipment, net $ $ Land $ $ Building and leasehold improvements Vehicles Software, computers and office equipment Capital leases Accumulated depreciation Depreciable assets, net Assets not placed in service Total other property and equipment, net $ $ |
Schedule of weighted average dilutive and anti-dilutive securities | For the Years Ended January 31, (in thousands) 2014 2015 2016 Dilutive — Anti-dilutive shares |
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) 2014 2015 2016 Net income (loss) attributable to common stockholders $ $ $ Effect of 5% convertible note conversion — Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion $ $ $ Basic weighted average common shares outstanding Effect of dilutive securities — Diluted weighted average common shares outstanding Basic net income (loss) per share $ $ $ Diluted net income (loss) per share $ $ $ |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Segment Reporting [Abstract] | |
Selected financial information for operating segments | For the Year Ended January 31, 2016 Exploration Corporate and Oilfield and Consolidated (in thousands) Production Services Other Eliminations Total Revenues: Oil, natural gas and natural gas liquids sales $ $ — $ — $ — $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Impairments — Accretion of asset retirement obligations — — — Oilfield services — — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ As of January 31, 2016: Cash and cash equivalents $ $ $ $ — $ Net oil and natural gas properties $ $ — $ — $ $ Oilfield services equipment, net $ — $ $ — $ — $ Other property and equipment, net $ $ $ $ — $ Total assets $ $ $ $ $ Total liabilities $ $ $ $ $ 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 $ $ — $ — $ $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Accretion of asset retirement obligations — — — Oilfield services — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ As of January 31, 2015: Cash and cash equivalents $ $ $ $ — $ Net oil and natural gas properties $ $ — $ — $ $ Oilfield services equipment, net $ — $ $ — $ — $ Other property and equipment, net $ $ $ $ — $ Total assets $ $ $ $ $ Total liabilities $ $ $ $ $ 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 $ $ — $ — $ $ Oilfield services for third parties — — Intersegment revenues — — — Total revenues — Expenses: Lease operating and production taxes — — — Gathering, transportation and processing — — — Depreciation and amortization Accretion of asset retirement obligations — — — Oilfield services — — General and administrative, net of amounts capitalized: Salaries and benefits — Share-based compensation — Other general and administrative — Total operating expenses Income (loss) from operations Other income (expense) Income (loss) before income taxes $ $ $ $ $ |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Long-Term Debt [Abstract] | |
Long-term debt | (in thousands) January 31, 2015 January 31, 2016 TUSA credit facility due October 2018 $ $ RockPile credit facility due March 2019 TUSA 6.75% notes due July 2022 5% convertible note Other notes and mortgages payable Total principal Debt issuance costs Total debt Less current portion of debt: RockPile credit facility — Other notes and mortgages payable Total current portion of long-term debt Total long-term debt $ $ |
Scheduled annual maturities of long-term debt outstanding | For the Years Ending January 31, (in thousands): 2017 $ 2018 2019 2020 2021 Thereafter $ |
Hedging And Commodity Derivat31
Hedging And Commodity Derivative Financial Instruments (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Hedging And Commodity Derivative Financial 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: For the Years Ended January 31, (in thousands) 2014 2015 2016 Realized commodity derivative gains (losses) $ $ $ Unrealized commodity derivative gains (losses) Commodity derivative gains (losses), net $ $ $ |
Commodity derivative contracts | The Company’s commodity derivative contracts as of January 31, 2016 are summarized below: Weighted Weighted Weighted Contract Quantity Average Average Average Type Basis (1) (Bbl/d) Put Strike Call Strike Price February 1, 2016 to January 31, 2017 Swap NYMEX n/a n/a $ February 1, 2017 to January 31, 2018 Swap NYMEX n/a n/a $ (1) “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange. |
Fair values of commodity derivatives | (in thousands) January 31, 2015 January 31, 2016 Current Assets: Crude oil derivative contracts $ $ Other Long-Term Assets: Crude oil derivative contracts — Total derivative asset $ $ Long-Term Liabilities: Crude oil derivative contracts $ — $ — Total derivative liability $ — $ — |
Oil And Natural Gas Properties
Oil And Natural Gas Properties (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Oil And Natural Gas Properties [Abstract] | |
Capitalized costs incurred in oil and natural gas production, exploration and development activities | For the Years Ended January 31, (in thousands) 2014 2015 2016 Costs incurred during the period Acquisition of properties: Proved $ $ $ Unproved Exploration Development Oil and natural gas expenditures Asset retirement obligations, net $ $ $ |
Costs not being amortized | Fiscal Year Costs Incurred 2013 (in thousands) and prior 2014 2015 2016 Acquisition $ $ $ $ Exploration — Capitalized interest — Total $ $ $ $ |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Acquisitions [Abstract] | |
Purchase price and estimated fair values of assets acquired and liabilities assumed | Purchase price (in thousands): As of June 30, 2014 Cash $ Total consideration given $ Fair value allocation of purchase price: Oil and natural gas properties: Proved properties $ Unproved properties Total oil and natural gas properties Accounts payable Asset retirement obligations assumed Fair value of net assets acquired $ |
Pro forma financial information | For the Years Ended January 31, (in thousands, except per share data) 2014 2015 Operating revenues $ $ Net income (loss) $ $ Earnings (loss) per common share Basic $ $ Diluted $ $ Weighted average common shares outstanding: Basic Diluted |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Asset retirement obligations | For the Years Ended January 31, (in thousands) 2015 2016 Balance at the beginning of the period $ $ Liabilities incurred Revision of estimates Sale of assets Liabilities settled Accretion Balance at the end of the period Less current portion of obligations Long-term ARO $ $ |
Equity Investment And Equity 35
Equity Investment And Equity Investment Derivatives (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Equity Investment [Abstract] | |
Equity investment holdings in Caliber | Expiration Strike Price at As of As of Date January 31, 2016 January 31, 2015 January 31, 2016 Class A Units — $ — Series 1 Warrants October 1, 2024 $ Series 2 Warrants October 1, 2024 $ Series 3 Warrants September 12, 2025 $ Series 4 Warrants September 12, 2025 $ Series 6 Warrants February 2, 2018 $ — |
Summary of activities related to company's equity investment | For the Years Ended January 31, (in thousands) 2015 2016 Balance at beginning of year $ $ Capital contributions — — Distributions — Equity investment share of net income before intra-company profit eliminations Change in fair value of warrants Other than temporary impairment — Balance at end of year $ $ Fair value of trigger unit warrants and warrants at end of year $ $ |
Results of unconsolidated equity method investee | For the Years Ended January 31, (in thousands) 2014 2015 2016 Revenue $ $ $ Gross profit $ $ $ Net income (loss) $ $ $ January 31, 2015 January 31, 2016 Current assets $ $ Noncurrent assets Total assets $ $ Current liabilities $ $ Noncurrent liabilities Total liabilities $ $ Minority interests $ $ |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Share-Based Compensation [Abstract] | |
Share-based compensation expense | For the Years Ended January 31, (in thousands) 2014 2015 2016 Restricted stock units $ $ $ Stock options RockPile Series B Units Less amounts capitalized to oil and natural gas properties Compensation expense $ $ $ |
Activity in restricted stock units | Weighted Average Number of Award Date Shares Fair Value Restricted stock units outstanding - January 31, 2013 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2014 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2015 $ Units granted $ Units forfeited $ Units vested $ Restricted stock units outstanding - January 31, 2016 $ |
Stock options outstanding by exercise price | The following table summarizes the stock options outstanding at January 31, 2016 : Remaining Exercise Price Contractual Life Number of Shares per Share (years) Outstanding Exercisable $ $ $ $ $ $ $ $ Weighted average exercise price per share $ $ Weighted average remaining contractual life |
Series B unit activity | Series Series Series Series Series Series B-1 units B-2 units B-3 units B-4 units B-5 units B-6 units Total Units outstanding - January 31, 2013 — — — — Units forfeited — — — — — — — Units redeemed — — — — — — — Units granted — — — — — Units outstanding - January 31, 2014 — — — Units forfeited — — — — — Units redeemed — — — Units granted — — — Units outstanding - January 31, 2015 — — Units redeemed — — — — — — — Units granted — — — — Units forfeited — — — Units outstanding - January 31, 2016 Vested — — Unvested — — |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Fair Value Measurements [Abstract] | |
Financial assets and liabilities accounted for at fair value | As of January 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total Assets: Commodity derivative assets $ — $ $ — $ Equity investment derivative assets $ — $ — $ $ Liabilities: RockPile earn-out liability $ — $ $ — $ As of January 31, 2016 (in thousands) Level 1 Level 2 Level 3 Total Assets: Commodity derivative assets $ — $ $ — $ Equity investment derivative assets $ — $ — $ $ Liabilities: Commodity derivative liabilities $ — $ — $ — $ — RockPile earn-out liability $ — $ $ — $ |
Carrying value and fair value of debt instruments | January 31, 2015 January 31, 2016 Carrying Estimated Carrying Estimated (in thousands) Value Fair Value Value Fair Value Revolving credit facilities $ $ $ $ TUSA 6.75% notes 5% convertible note Other notes and mortgages payable |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Income Taxes [Abstract] | |
Income tax provision (benefit) | For the Years Ended January 31, (in thousands) 2014 2015 2016 Current tax expense (benefit) $ — $ — $ Deferred tax expense (benefit) Federal State Foreign — — Valuation allowance - United States and Canada — — Total income tax provision (benefit) $ $ $ Income (loss) before income taxes $ $ $ Effective income tax rate |
Reconciliation of income tax provision (benefit) | For the Years Ended January 31, (in thousands) 2014 2015 2016 Federal statutory tax expense (benefit) $ $ $ State income tax expense / (benefit), net of federal income tax benefit Permanent differences Difference in foreign tax rates Effect of tax rate change Credits State NOL adjustment — Bad debt deduction for receivables from Elmworth — Attribute reduction - cancellation of debt exclusion - Elmworth — Changes in valuation allowance Other Provision (benefit) for income taxes $ $ $ |
Components of net deferred income tax assets and liabilities | For the Years Ended January 31, (in thousands) 2015 2016 Deferred income tax assets: United States net losses carried forward $ United States oil and natural gas properties — Asset retirement obligations Accruals — Stock-based compensation Other Total deferred income tax assets Deferred income tax liabilities: United States oil and natural gas properties — Investment in Caliber Hedging liabilities Other — — Total deferred income tax liabilities Valuation allowance Net deferred income tax asset (liability) $ $ — |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Future minimum lease payments under operating leases | Annual Rental Amount Fiscal Year Ending January 31, (in thousands) 2017 $ 2018 $ 2019 $ 2020 $ 2021 and thereafter $ |
Supplemental Disclosures of C40
Supplemental Disclosures of Cash Flow Information (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Supplemental Disclosures of Cash Flow Information [Abstract] | |
Supplemental cash flow information | For the Years Ended January 31, (in thousands) 2014 2015 2016 Cash paid during the period for: Interest expense $ $ $ Income taxes $ — $ $ — Non-cash investing activities: Additions (reductions) to oil and natural gas properties through: Increase (decrease) in accounts payable and accrued liabilities $ $ $ Issuance of common stock $ $ — $ — Capitalized stock based compensation $ $ $ Change in asset retirement obligations $ $ $ Acquisition of oilfield services equipment through notes payable and liabilities $ $ — $ — |
Quarterly Financial Informati41
Quarterly Financial Information (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Quarterly Financial Information [Abstract] | |
Quarterly financial information | For the Year Ended January 31, 2016 (1) First Second Third Fourth (in thousands) Quarter Quarter Quarter Quarter Total revenue $ $ $ $ Income (loss) from operations (2) $ $ $ $ Net income (loss) $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ For the Year Ended January 31, 2015 (1) First Second Third Fourth (in thousands) Quarter Quarter Quarter Quarter Total revenue $ $ $ $ Income (loss) from operations (2) $ $ $ $ Net (loss) income $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ (1) Amounts reported for the quarter period. There were immaterial reclassifications for the periods presented between operating expenses and other income (expense). |
Supplemental Information On O42
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Tables) | 12 Months Ended |
Jan. 31, 2016 | |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |
Changes in estimated proved reserves | Crude Oil Natural Gas NGL (Mbbls) (MMcf) (Mbbls) Mboe Total proved reserves at January 31, 2013 — Revisions of previous estimates Purchase of reserves Extensions, discoveries and other additions Sale of reserves — Production Total proved reserves at January 31, 2014 Revisions of previous estimates Purchase of reserves Extensions, discoveries and other additions Sale of reserves — Production Total proved reserves at January 31, 2015 Revisions of previous estimates Purchase of reserves — — — — Extensions, discoveries and other additions Sale of reserves — — Production Total proved reserves at January 31, 2016 Proved Developed Reserves included above: January 31, 2013 — January 31, 2014 January 31, 2015 January 31, 2016 Proved Undeveloped Reserves included above: January 31, 2013 — January 31, 2014 January 31, 2015 January 31, 2016 |
Prices used in calculation of Standardized Measure | For the Years Ended January 31, 2014 2015 2016 Oil price per barrel $ $ $ Natural gas price per Mcf $ $ $ Natural gas liquids price per barrel $ $ $ |
Proved undeveloped reserves | (Mboe) Gross Wells Net Wells Proved Undeveloped Reserves at January 31, 2013 Conversion to developed reserves in fiscal year 2014 Traded for net acres in other drill spacing units Revisions — — Acquisitions Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2014 Conversion to developed reserves in fiscal year 2015 Revisions Acquisitions Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2015 Conversion to developed reserves in fiscal year 2016 Revisions Acquisitions — — — Extensions and discoveries of proved reserves Proved Undeveloped Reserves at January 31, 2016 |
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, 2021 For which non-operated wells were in-progress at January 31, 2016 and are expected to be completed in fiscal year 2017 — — — That are non-operated wells with drilling permits — — — That are non-operated wells to be drilled by January 31, 2021 |
Future cash inflows relating to proved oil and natural gas reserves | For the Years Ended January 31, (in thousands) 2014 2015 2016 Future cash inflows $ $ $ Future costs: Production Development Future income tax expense — Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows relating to proved reserves $ $ $ |
Principle sources of change in the Standard Measure | For the Years Ended January 31, (in thousands) 2014 2015 2016 Standardized measure, beginning of period $ $ $ Extensions and discoveries, net of future production and development costs Sales, net of production costs Previously estimated development costs incurred during the period Revision of quantity estimates Net change in prices, net of production costs Acquisition of reserves — Divestiture of reserves Accretion of discount Changes in future development costs Change in income taxes Change in production timing and other Standardized measure, end of period $ $ $ |
Description of Business - (Deta
Description of Business - (Details) - item | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Basis Of Presentation [Abstract] | ||
Number of major focus lines of business | 3 | |
Number of wells being reclaimed | 5 |
Summary Of Significant Accoun44
Summary Of Significant Accounting Policies - Liquidity & Going Concern - (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Jan. 31, 2016 | Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | Oct. 31, 2015 | Apr. 30, 2015 | Jul. 18, 2014 |
Line of Credit Facility [Line Items] | ||||||||
Long-term Line of Credit | $ 355,772 | $ 355,772 | $ 224,159 | |||||
Letters of Credit Outstanding, Amount | 2,500 | 2,500 | ||||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 0 | 103,700 | 103,700 | |||||
Proceeds from Lines of Credit | 320,789 | 504,159 | $ 211,820 | |||||
Credit Agreement Borrowing Base | 350,000 | 350,000 | 350,000 | $ 350,000 | $ 435,000 | |||
TUSA [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Long-term Line of Credit | $ 243,772 | $ 243,772 | $ 119,272 | |||||
Proceeds from Lines of Credit | $ 103,700 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.75% | 6.75% | ||||||
Letter of Credit [Member] | TUSA [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Number of days before which cash capital contribution be obtained | 10 days | |||||||
Number of days from quarter end cash capital contribution be obtained | 45 days | |||||||
Number of days from fiscal year end cash capital contribution be obtained | 90 days | |||||||
TUSA 6.75% Notes [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.75% | 6.75% | 6.75% | 6.75% |
Summary Of Significant Accoun45
Summary Of Significant Accounting Policies - Accounts Receivable - (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Accounts receivable | $ 53,302 | $ 171,911 | |
Depreciation and amortization expense | $ 90,400 | $ 106,900 | $ 52,000 |
Oil & Gas Customer A [Member] | |||
Concentration Risk, Percentage | 13.00% | 22.00% | |
Oil & Gas Customer B [Member] | |||
Concentration Risk, Percentage | 10.00% | 12.00% | 15.00% |
Oil & Gas Customer C [Member] | |||
Concentration Risk, Percentage | 12.00% | ||
Oilfield Services Customer A [Member] | |||
Concentration Risk, Percentage | 15.00% | ||
Oilfield Services Customer B [Member] | |||
Concentration Risk, Percentage | 12.00% | 13.00% | |
Oilfield Services Customer C [Member] | |||
Concentration Risk, Percentage | 16.00% | ||
Oilfield Services Customer D [Member] | |||
Concentration Risk, Percentage | 11.00% | ||
Oil and natural gas sales [Member] | |||
Accounts receivable | $ 11,432 | $ 21,445 | |
Joint interest billings [Member] | |||
Accounts receivable | 25,820 | 72,354 | |
Oilfield services revenue [Member] | |||
Accounts receivable | 11,920 | 59,408 | |
Other [Member] | |||
Accounts receivable | $ 4,130 | $ 18,704 | |
Minimum [Member] | |||
Equity method ownership percentage | 20.00% | ||
Maximum [Member] | |||
Equity method ownership percentage | 50.00% |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Consolidation (Details) $ in Millions | 12 Months Ended | ||
Jan. 31, 2016USD ($)$ / MMBTU$ / bbl | Jan. 31, 2015$ / MMBTU$ / bbl | Jan. 31, 2014$ / MMBTU$ / bbl | |
Impairment charges | |||
Impairment of oil and natural gas properties | $ | $ 779 | ||
Crude Oil Reserves [Member] | |||
Trailing 12 month simple average spot prices: | |||
Trailing 12 Month simple average spot prices | 48.93 | 91.22 | 97.49 |
Natural Gas Reserves [Member] | |||
Trailing 12 month simple average spot prices: | |||
Trailing 12 Month simple average spot prices | $ / MMBTU | 2.53 | 4.20 | 3.73 |
Natural Gas Liquids Reserves [Member] | |||
Trailing 12 month simple average spot prices: | |||
Trailing 12 Month simple average spot prices | 24.97 | 50.07 | 54.25 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Oilfield Services Equipment Schedule (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | Jul. 18, 2014 | |
Property, Plant and Equipment [Line Items] | ||||
Accumulated depreciation | $ (14,939) | $ (6,384) | ||
Depreciable assets, net | 42,479 | 46,120 | ||
Assets not placed in service | 395 | 1,247 | ||
Total oilfield services equipment and other property and equipment, net | 42,874 | 47,367 | ||
Oilfield services equipment - net | 48,445 | 87,549 | ||
Impairment of long lived assets | $ 14,900 | $ 0 | $ 0 | |
TUSA 6.75% Notes [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Debt instrument, interest rate | 6.75% | 6.75% | 6.75% | |
Oilfield Service Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | $ 110,992 | $ 105,938 | ||
Accumulated depreciation | (63,367) | (28,805) | ||
Depreciable assets, net | 47,625 | 77,133 | ||
Assets not placed in service | 820 | 10,416 | ||
Land [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | 6,838 | 7,888 | ||
Building And Leasehold Improvements [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | 37,149 | 33,625 | ||
Vehicles [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | 5,036 | 4,811 | ||
Software, Computers And Office Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | 7,451 | 5,327 | ||
Capital Leases [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total Depreciable Assets | $ 944 | $ 853 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Jan. 31, 2016 | Oct. 31, 2015 | Jul. 31, 2015 | Apr. 30, 2015 | Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Earnings Per Share, Diluted, Other Disclosures [Abstract] | |||||||||||
Weighted Average Number Diluted Shares Outstanding Adjustment | 17,421 | 15,979 | |||||||||
Anti-dilutive shares | 10,156 | 6,905 | 5,250 | ||||||||
Earnings Per Share Reconciliation [Abstract] | |||||||||||
Net income (loss) attributable to common stockholders | $ (161,796) | $ (286,999) | $ (193,346) | $ (180,199) | $ 38,905 | $ 25,398 | $ 14,552 | $ 14,542 | $ (822,340) | $ 93,397 | $ 73,480 |
Effect of 5% Convertible Note conversion | 4,135 | 3,392 | |||||||||
Net income (loss) attributable to common shareholders after effect of debt conversion | $ (822,340) | $ 97,532 | $ 76,872 | ||||||||
Weighted Average Number of Shares Outstanding Reconciliation [Abstract] | |||||||||||
Basic weighted average common shares outstanding | 75,502 | 83,611 | 68,579 | ||||||||
Effect of dilutive securities | 17,421 | 15,979 | |||||||||
Diluted weighted average common shares outstanding | 75,502 | 101,032 | 84,558 | ||||||||
Basic net income (loss) per share | $ (2.14) | $ (3.80) | $ (2.56) | $ (2.39) | $ 0.50 | $ 0.30 | $ 0.17 | $ 0.17 | $ (10.89) | $ 1.12 | $ 1.07 |
Diluted net income (loss) per share | $ (2.14) | $ (3.80) | $ (2.56) | $ (2.39) | $ 0.42 | $ 0.26 | $ 0.15 | $ 0.15 | $ (10.89) | $ 0.97 | $ 0.91 |
Summary of Significant Accoun49
Summary of Significant Accounting Policies - Additional Info. (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 |
Adopted and Recently Issued Accounting Pronouncements | ||
Debt issuance costs, reclassification | $ (3,877) | $ (4,209) |
Long-term debt | (789,043) | (789,809) |
Deferred income tax liabilities noncurrent, reclassification | $ 53,441 | |
Adjustments for New Accounting Principle, Early Adoption [Member] | Accounting Standards Update 2015-03 [Member] | ||
Adopted and Recently Issued Accounting Pronouncements | ||
Long-term debt | 9,800 | |
Adjustments for New Accounting Principle, Early Adoption [Member] | Accounting Standards Update 2015-17 [Member] | ||
Adopted and Recently Issued Accounting Pronouncements | ||
Deferred income tax liabilities current, reclassification | 19,500 | |
Deferred income tax liabilities noncurrent, reclassification | $ 19,500 | |
TUSA [Member] | ||
Adopted and Recently Issued Accounting Pronouncements | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.75% | |
TUSA [Member] | Adjustments for New Accounting Principle, Early Adoption [Member] | Accounting Standards Update 2015-03 [Member] | ||
Adopted and Recently Issued Accounting Pronouncements | ||
Debt issuance costs, reclassification | $ 9,800 |
Segment Reporting - Selected fi
Segment Reporting - Selected financial information (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Jan. 31, 2016USD ($) | Oct. 31, 2015USD ($) | Jul. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Jan. 31, 2015USD ($) | Oct. 31, 2014USD ($) | Jul. 31, 2014USD ($) | Apr. 30, 2014USD ($) | Jan. 31, 2016USD ($)segment | Jan. 31, 2015USD ($) | Jan. 31, 2014USD ($) | |
Information regarding reportable segments | |||||||||||
Number of reportable segments | segment | 2 | ||||||||||
Revenues | |||||||||||
Oil, natural gas and natural gas liquids sales | $ 181,228 | $ 284,502 | $ 160,548 | ||||||||
Oilfield services for third parties | 176,901 | 288,453 | 98,199 | ||||||||
Total revenues | $ 64,964 | $ 65,144 | $ 109,733 | $ 118,288 | $ 156,988 | $ 174,196 | $ 141,989 | $ 99,782 | 358,129 | 572,955 | 258,747 |
Expenses | |||||||||||
Lease operating and production taxes | 58,995 | 55,477 | 32,460 | ||||||||
Gathering, transportation and processing | 25,910 | 18,520 | 4,302 | ||||||||
Depreciation and amortization | 121,374 | 124,055 | 58,011 | ||||||||
Impairments | 793,900 | ||||||||||
Accretion of asset retirement obligations | 376 | 167 | 56 | ||||||||
Oilfield services | 163,452 | 216,596 | 82,327 | ||||||||
Salaries and benefits | 28,241 | 32,207 | 17,299 | ||||||||
Share-based compensation | 17,394 | 7,919 | 7,830 | ||||||||
Other general and administrative | 16,670 | 22,631 | 9,500 | ||||||||
Total operating expenses | 1,226,312 | 477,572 | 211,785 | ||||||||
INCOME (LOSS) FROM OPERATIONS | (155,688) | $ (285,185) | $ (213,368) | $ (213,942) | 877 | $ 33,534 | $ 38,489 | $ 22,483 | (868,183) | 95,383 | 46,962 |
Other income (expense) | (7,554) | 43,514 | 34,459 | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (875,737) | 138,897 | 81,421 | ||||||||
Cash and cash equivalents | 115,769 | 67,871 | 115,769 | 67,871 | |||||||
Net oil and natural gas properties | 406,540 | 1,126,090 | 406,540 | 1,126,090 | |||||||
Oilfield services equipment, net | 48,445 | 87,549 | 48,445 | 87,549 | |||||||
Other property and equipment, net | 42,874 | 47,367 | 42,874 | 47,367 | |||||||
Total assets | 753,148 | 1,645,041 | 753,148 | 1,645,041 | |||||||
Total liabilities | 1,017,730 | 1,100,023 | 1,017,730 | 1,100,023 | |||||||
Corporate, and Other [Member] | |||||||||||
Expenses | |||||||||||
Depreciation and amortization | 1,565 | 921 | 620 | ||||||||
Impairments | 1,142 | ||||||||||
Oilfield services | 308 | ||||||||||
Salaries and benefits | 10,432 | 11,559 | 6,864 | ||||||||
Share-based compensation | 15,052 | 6,255 | 6,113 | ||||||||
Other general and administrative | 5,027 | 2,991 | 1,339 | ||||||||
Total operating expenses | 33,218 | 22,034 | 14,936 | ||||||||
INCOME (LOSS) FROM OPERATIONS | (33,218) | (22,034) | (14,936) | ||||||||
Other income (expense) | (26,505) | (2,353) | 38,998 | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (59,723) | (24,387) | 24,062 | ||||||||
Cash and cash equivalents | 34,922 | 49,069 | 34,922 | 49,069 | |||||||
Other property and equipment, net | 16,206 | 15,443 | 16,206 | 15,443 | |||||||
Total assets | 97,397 | 131,107 | 97,397 | 131,107 | |||||||
Total liabilities | 157,420 | 203,812 | 157,420 | 203,812 | |||||||
Consolidation, Eliminations [Member] | |||||||||||
Revenues | |||||||||||
Oilfield services for third parties | (441) | (6,073) | (4,407) | ||||||||
Eliminations And Other [Member] | |||||||||||
Revenues | |||||||||||
Other | (32,776) | (123,577) | (91,019) | ||||||||
Total revenues | (33,217) | (129,650) | (95,426) | ||||||||
Expenses | |||||||||||
Depreciation and amortization | (3,769) | (15,507) | (8,302) | ||||||||
Oilfield services | (20,642) | (84,854) | (60,012) | ||||||||
Total operating expenses | (24,411) | (100,361) | (68,314) | ||||||||
INCOME (LOSS) FROM OPERATIONS | (8,806) | (29,289) | (27,112) | ||||||||
Other income (expense) | (1,993) | (2,322) | (3,376) | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (10,799) | (31,611) | (30,488) | ||||||||
Net oil and natural gas properties | (85,580) | (74,782) | (85,580) | (74,782) | |||||||
Total assets | (85,751) | (88,196) | (85,751) | (88,196) | |||||||
Total liabilities | (171) | (13,414) | (171) | (13,414) | |||||||
Exploration and Production [Member] | Operating Segments [Member] | |||||||||||
Revenues | |||||||||||
Oil, natural gas and natural gas liquids sales | 181,228 | 284,502 | 160,548 | ||||||||
Total revenues | 181,228 | 284,502 | 160,548 | ||||||||
Expenses | |||||||||||
Lease operating and production taxes | 58,995 | 55,477 | 32,460 | ||||||||
Gathering, transportation and processing | 25,910 | 18,520 | 4,302 | ||||||||
Depreciation and amortization | 91,213 | 116,633 | 56,788 | ||||||||
Impairments | 779,000 | ||||||||||
Accretion of asset retirement obligations | 376 | 167 | 56 | ||||||||
Salaries and benefits | 1,161 | 6,028 | 3,541 | ||||||||
Share-based compensation | 1,537 | 1,155 | 1,127 | ||||||||
Other general and administrative | 3,375 | 9,042 | 3,939 | ||||||||
Total operating expenses | 961,567 | 207,022 | 102,213 | ||||||||
INCOME (LOSS) FROM OPERATIONS | (780,339) | 77,480 | 58,335 | ||||||||
Other income (expense) | 25,400 | 51,216 | (172) | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (754,939) | 128,696 | 58,163 | ||||||||
Cash and cash equivalents | 47,997 | 14,980 | 47,997 | 14,980 | |||||||
Net oil and natural gas properties | 492,120 | 1,200,872 | 492,120 | 1,200,872 | |||||||
Other property and equipment, net | 9,030 | 9,679 | 9,030 | 9,679 | |||||||
Total assets | 621,803 | 1,399,482 | 621,803 | 1,399,482 | |||||||
Total liabilities | 719,626 | 745,638 | 719,626 | 745,638 | |||||||
Exploration and Production [Member] | Eliminations And Other [Member] | |||||||||||
Expenses | |||||||||||
Depreciation and amortization | 200 | 9,600 | 4,800 | ||||||||
Oilfield services revenue [Member] | Operating Segments [Member] | |||||||||||
Revenues | |||||||||||
Oilfield services for third parties | 177,342 | 294,526 | 102,606 | ||||||||
Other | 32,776 | 123,577 | 91,019 | ||||||||
Total revenues | 210,118 | 418,103 | 193,625 | ||||||||
Expenses | |||||||||||
Depreciation and amortization | 32,365 | 22,008 | 8,905 | ||||||||
Impairments | 13,758 | ||||||||||
Oilfield services | 184,094 | 301,142 | 142,339 | ||||||||
Salaries and benefits | 16,648 | 14,620 | 6,894 | ||||||||
Share-based compensation | 805 | 509 | 590 | ||||||||
Other general and administrative | 8,268 | 10,598 | 4,222 | ||||||||
Total operating expenses | 255,938 | 348,877 | 162,950 | ||||||||
INCOME (LOSS) FROM OPERATIONS | (45,820) | 69,226 | 30,675 | ||||||||
Other income (expense) | (4,456) | (3,027) | (991) | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (50,276) | 66,199 | $ 29,684 | ||||||||
Cash and cash equivalents | 32,850 | 3,822 | 32,850 | 3,822 | |||||||
Oilfield services equipment, net | 48,445 | 87,549 | 48,445 | 87,549 | |||||||
Other property and equipment, net | 17,638 | 22,245 | 17,638 | 22,245 | |||||||
Total assets | 119,699 | 202,648 | 119,699 | 202,648 | |||||||
Total liabilities | $ 140,855 | $ 163,987 | $ 140,855 | $ 163,987 |
Long-Term Debt - Schedule of lo
Long-Term Debt - Schedule of long-term debt (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 | Jul. 18, 2014 |
Debt Instrument [Line Items] | |||
Credit facility | $ 355,772 | $ 224,159 | |
TUSA 6.75% notes | 398,419 | 429,500 | |
5% Convertible Note | 142,799 | 135,877 | |
Other notes and mortgages payable | 14,065 | 10,605 | |
Total principal | 911,055 | 800,141 | |
Deferred loan costs | (7,924) | (9,829) | |
Total debt | 903,131 | 790,312 | |
Other notes and mortgages payable | (2,088) | (503) | |
Total current portion of long-term debt | (114,088) | (503) | |
Total long-term debt | $ 789,043 | $ 789,809 | |
TUSA 6.75% Notes [Member] | |||
Debt instrument, interest rate | |||
Debt instrument, interest rate | 6.75% | 6.75% | 6.75% |
Convertible Notes [Member] | |||
Debt instrument, interest rate | |||
Debt instrument, interest rate | 5.00% | 5.00% | |
TUSA [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | $ 243,772 | $ 119,272 | |
Debt instrument, interest rate | |||
Debt instrument, interest rate | 6.75% | ||
Rockpile [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | $ 112,000 | $ 104,887 | |
Revolving Credit Facility [Member] | Rockpile [Member] | |||
Debt Instrument [Line Items] | |||
Total current portion of long-term debt | $ (112,000) |
Long-Term Debt - TUSA credit fa
Long-Term Debt - TUSA credit facility - (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | Oct. 31, 2015 | Apr. 30, 2015 | Nov. 25, 2014 |
Line of Credit Facility [Line Items] | |||||||
Credit agreement borrowing base | $ 350,000 | $ 350,000 | $ 350,000 | $ 435,000 | |||
Letters of Credit Outstanding, Amount | 2,500 | ||||||
Line of Credit Facility, Remaining Borrowing Capacity | 0 | 103,700 | |||||
Proceeds from Lines of Credit | $ 320,789 | $ 504,159 | $ 211,820 | ||||
TUSA [Member] | |||||||
Line of Credit Facility [Line Items] | |||||||
Credit facility, maximum borrowing capacity | $ 1,000,000 | ||||||
Letter of credit sublimit | $ 15,000 | ||||||
Proceeds from Lines of Credit | $ 103,700 | ||||||
Percentage of Oil and Gas Interests Used For Collateral | 80.00% | ||||||
Minimum [Member] | TUSA [Member] | Letter of Credit [Member] | |||||||
Line of Credit Facility [Line Items] | |||||||
Credit facility, commitment fee percentage | 0.375% | ||||||
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, basis spread on interest rate | 0.50% | ||||||
Eurodollar Rate Plus 1% [Member] | Maximum [Member] | TUSA [Member] | |||||||
Line of Credit Facility [Line Items] | |||||||
Credit facility, basis spread on interest rate | 1.50% | ||||||
Eurodollar [Member] | Minimum [Member] | TUSA [Member] | |||||||
Line of Credit Facility [Line Items] | |||||||
Credit facility, basis spread on interest rate | 1.50% | ||||||
Eurodollar [Member] | Maximum [Member] | TUSA [Member] | |||||||
Line of Credit Facility [Line Items] | |||||||
Credit facility, basis spread on interest rate | 2.50% |
Long-Term Debt - Rockpile credi
Long-Term Debt - Rockpile credit facility - (Details) - Rockpile [Member] $ in Millions | Jan. 31, 2016item | Jan. 31, 2016 | Nov. 13, 2014USD ($) | Mar. 25, 2014USD ($) |
Debt Instrument [Line Items] | ||||
Duration over which TUSA may exercise cure right | 4 | |||
Number of days before which cash capital contribution be obtained | 10 days | |||
Number of days from quarter end cash capital contribution be obtained | 45 days | |||
Number of days from fiscal year end cash capital contribution be obtained | 120 days | |||
Federal Funds Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, basis spread on interest rate | 0.50% | |||
Eurodollar Rate Plus 1% [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, margin on dollar amount based on usage | 1.00% | 1.00% | ||
Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, maximum borrowing capacity | $ | $ 150 | $ 100 | ||
Letter of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, fronting fee percentage | 0.125% | |||
Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.50% | |||
Number of fiscal quarters in which TUSA may exercise cure right | 2 | |||
Number of times TUSA may exercise cure rights | 5 | |||
Maximum [Member] | Eurodollar Rate Plus 1% [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, basis spread on interest rate | 2.25% | |||
Maximum [Member] | Eurodollar [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, basis spread on interest rate | 3.25% | |||
Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.375% | |||
Minimum [Member] | Eurodollar Rate Plus 1% [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, basis spread on interest rate | 1.50% | |||
Minimum [Member] | Eurodollar [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility, basis spread on interest rate | 2.50% |
Long-Term Debt - TUSA 6.75% Not
Long-Term Debt - TUSA 6.75% Note - (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jul. 18, 2014 | |
Debt Instrument [Line Items] | |||
Gain (loss) on extinguishment of debt | $ 17,927 | $ 6,610 | |
TUSA 6.75% Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 450,000 | ||
Debt instrument, interest rate | 6.75% | 6.75% | 6.75% |
Offering costs | $ 10,500 | ||
Face value of notes repurchased | 31,100 | $ 20,500 | |
Repurchased amount | 13,200 | 13,900 | |
Gain (loss) on extinguishment of debt | $ 17,900 | $ 6,600 | |
TUSA 6.75% 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% | ||
Debt instrument redemption price percentage redeemed with cash proceeds | 106.75% | ||
TUSA 6.75% Notes [Member] | Redemption Due to Change in Control Events [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, percentage | 101.00% | ||
TUSA 6.75% Notes [Member] | Redemption after july 15, 2017 [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, percentage | 105.063% | ||
TUSA 6.75% Notes [Member] | Redemption after July 15, 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, percentage | 103.375% | ||
TUSA 6.75% Notes [Member] | Redemption after July 15, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, percentage | 101.688% | ||
TUSA 6.75% Notes [Member] | Redemption after July 15, 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, percentage | 100.00% |
Long-Term Debt - Convertible no
Long-Term Debt - Convertible note - (Details) - USD ($) | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Debt Instrument [Line Items] | ||
Accrued interest | $ 1,700,000 | $ 2,250,000 |
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 | $ 22,800,000 | |
Redemption criteria, share price for 20 consecutive days | $ 11 | |
Redemption criteria, number of consecutive trading days | 20 days |
Long-Term Debt - Maturities of
Long-Term Debt - Maturities of long-term debt (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 |
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2,017 | $ 114,088 | |
2,018 | 1,656 | |
2,019 | 245,430 | |
2,020 | 676 | |
2,021 | 706 | |
Thereafter | 548,499 | |
Total principal | $ 911,055 | $ 800,141 |
Hedging And Commodity Derivat57
Hedging And Commodity Derivative Financial Instruments - Components of commodity derivative gains (losses) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Aug. 31, 2015USD ($) | Jan. 31, 2016USD ($)Counterparty | Jan. 31, 2015USD ($) | Jan. 31, 2014USD ($) | |
Hedging And Commodity Derivative Financial Instruments [Abstract] | ||||
Number of counterparties | Counterparty | 6 | |||
Realized commodity derivative gains (losses) | $ 9,300 | $ 71,940 | $ 11,422 | $ (4,643) |
Unrealized commodity derivative gains (losses) | (33,393) | 52,628 | 5,725 | |
Commodity derivatives gains (losses), net | $ 38,547 | $ 64,050 | $ 1,082 |
Hedging And Commodity Derivat58
Hedging And Commodity Derivative Financial Instruments - Summary of commoodity derivative contracts - (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Aug. 31, 2015USD ($)bbl / item$ / bbl | Jan. 31, 2016USD ($)bbl / item$ / bbl | Jan. 31, 2015USD ($) | Jan. 31, 2014USD ($) | |
Derivative [Line Items] | ||||
Quantity, (bbls) | bbl / item | 2,000 | |||
Notional Disclosures [Abstract] | ||||
Realized commodity derivative gains (losses) | $ | $ 9,300 | $ 71,940 | $ 11,422 | $ (4,643) |
Average fixed price | $ / bbl | 60.34 | |||
Fiscal 2017 Swap [Member] | ||||
Derivative [Line Items] | ||||
End date | February 1, 2016 to January 31, 2017 | |||
Contract type | Swap | |||
Basis | NYMEX | |||
Quantity, (bbls) | bbl / item | 2,175 | |||
Weighted Average Price | $ / bbl | 56.13 | |||
Fiscal 2018 Swap [Member] | ||||
Derivative [Line Items] | ||||
End date | February 1, 2017 to January 31, 2018 | |||
Contract type | Swap | |||
Basis | NYMEX | |||
Quantity, (bbls) | bbl / item | 2,745 | |||
Weighted Average Price | $ / bbl | 53.36 |
Hedging And Commodity Derivat59
Hedging And Commodity Derivative Financial Instruments - Fair values of commodity derivatives - (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative Assets | $ 21,382 | $ 54,775 |
Crude Oil Derivative Contract [Member] | Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Assets | 12,370 | $ 54,775 |
Crude Oil Derivative Contract [Member] | Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Assets | $ 9,012 |
Oil And Natural Gas Propertie60
Oil And Natural Gas Properties - Capitalized costs incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Acquisition of properties: | |||
Proved | $ 655 | $ 90,920 | $ 80,201 |
Unproved | 155 | 47,858 | 41,377 |
Exploration | 58,660 | 180,174 | 96,731 |
Development | 93,756 | 226,765 | 216,046 |
Oil and natural gas expenditures | 153,226 | 545,717 | 434,355 |
Asset retirement obligation, net | 1,156 | 1,818 | 676 |
Total costs incurred | $ 154,382 | $ 547,535 | $ 435,031 |
Oil And Natural Gas Propertie61
Oil And Natural Gas Properties - Property acquisitions and drilling of wells (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Issuance of common stock for oil and gas properties | $ 2.4 | ||
Capitalized internal land and geology department costs | $ 4.3 | $ 4.8 | 3.7 |
Unproved Leaseholds [Member] | Oil and Gas Properties [Member] | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Business Combination, Consideration Transferred | $ 0.8 | $ 138.8 | $ 121.6 |
Oil And Natural Gas Propertie62
Oil And Natural Gas Properties - Oil and gas property costs amortized and not being amortized (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Duration for Unproved property costs to be reclassified to proved property costs | 5 years | |||
Unproved properties [Member] | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Cumulative costs not being amortized | $ 78,400 | |||
Amounts transferred to amortization base | 35,100 | $ 67,200 | $ 14,500 | |
2,016 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 68 | |||
Exploration | 691 | |||
Capitalized Interest | 4,802 | |||
Total | $ 5,561 | |||
2,015 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 33,554 | |||
Exploration | 224 | |||
Capitalized Interest | 2,045 | |||
Total | $ 35,823 | |||
2,014 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | 20,320 | |||
Exploration | 1,039 | |||
Capitalized Interest | 254 | |||
Total | $ 21,613 | |||
2013 and prior | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition | $ 15,370 | |||
Total | $ 15,370 |
Acquisitions - Acquisitions of
Acquisitions - Acquisitions of interests in oil and gas properties (Details) $ in Thousands | 1 Months Ended | ||
Jun. 30, 2014USD ($)a | Aug. 31, 2013USD ($)a | Jan. 31, 2015USD ($) | |
Kodiak Oil And Natural Gas Property [Member] | |||
Business Acquisition [Line Items] | |||
Number of acres purchased | a | 5,600 | ||
Cash paid for acquisition | $ 83,800 | ||
Number of leasehold interest acres that could be exchanged | a | 600 | ||
Marathon Oil And Gas [Member] | |||
Business Acquisition [Line Items] | |||
Number of acres purchased | a | 41,100 | ||
Cash paid for acquisition | $ 90,352 | ||
Net downward adjustment included in the purchase price consideration | $ 9,600 | ||
Acquisition transaction costs | $ 1,300 |
Acquisitions - Purchase price a
Acquisitions - Purchase price and estimated values of assets acquired and liabilities assumed (Details) - Marathon Oil And Gas [Member] $ in Thousands | 1 Months Ended |
Jun. 30, 2014USD ($) | |
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 - Proforma Financi
Acquisitions - Proforma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Jan. 31, 2015 | Jan. 31, 2014 | |
Acquisitions [Abstract] | ||
Operating revenue | $ 584,696 | $ 312,081 |
Net income (loss) | $ 96,438 | $ 91,579 |
Earnings (loss) per common share, basic | $ 1.15 | $ 1.22 |
Earnings (loss) per common share, diluted | $ 1 | $ 1.04 |
Weighted average common shares outstanding, basic | 83,611 | 75,047 |
Weighted average common shares outstanding, diluted | 101,032 | 91,026 |
Pro forma depreciation, amortization and accretion expense | $ 3,400 | $ 16,500 |
Asset Retirement Obligations -C
Asset Retirement Obligations -Change in asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Balance, beginning of period | $ 8,578 | $ 4,629 |
Liabilities incurred | 1,268 | 1,821 |
Revision of estimates | 1,281 | 2,737 |
Sales of assets | (30) | (29) |
Liabilities settled | (1,400) | (747) |
Accretion | 376 | 167 |
Balance, end of period | 10,073 | 8,578 |
Less current portion of obligations | (560) | (5,391) |
Long-term asset retirement obligations | $ 9,513 | $ 3,187 |
Asset Retirement Obligations -
Asset Retirement Obligations - Significant portions of the current asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Asset retirement obligations, current | $ 560 | $ 5,391 |
Revision of estimates | 1,281 | 2,737 |
Reclamation Of Man Made Ponds And Plugging And Abandonment Of Well Bores and Plug And Abandon Vertical Wells [Member] | ||
Asset retirement obligations, current | 4,900 | 4,800 |
Canada [Member] | Internal Engineering Re-assessment [Member] | ||
Revision of estimates | $ 1,300 | $ 2,700 |
Equity Investment And Equity 68
Equity Investment And Equity Investment Derivatives - Equity Investment - (Details) - Caliber Midstream Partners, L.P. [Member] - USD ($) | Feb. 02, 2015 | Jan. 31, 2016 | Jan. 31, 2015 |
Class A Units [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investments, units held | $ 7,000,000 | $ 7,000,000 | |
Class A Units [Member] | FREIF Caliber Holdings [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Capital contributions | $ 34,000,000 | ||
Equity method investments, Class A Units received | 2,720,000 | ||
Equity method investments, units held | $ 17,720,000 | ||
Equity method ownership percentage | 71.70% | ||
Equity method investments, warrants received | 906,667 | ||
Class A Units [Member] | Triangle Caliber Holdings LLC [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Capital contributions | $ 0 | ||
Equity method investments, units held | $ 7,000,000 | ||
Equity method ownership percentage | 28.30% | ||
Equity method investments, warrants received | 3,626,667 | ||
Series 1 To 4 Warrants [Member] | Triangle Caliber Holdings LLC [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investments, warrants received | 2,357,334 | ||
Series 6 Warrants [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investments, units held | $ 1,269,333 | ||
Strike price | $ 12.50 | ||
Series 6 Warrants [Member] | Triangle Caliber Holdings LLC [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investments, warrants received | 1,269,333 | ||
Strike price | $ 12.50 |
Equity Investment And Equity 69
Equity Investment And Equity Investment Derivatives - Equity investment holdings summary - (Details) - Caliber Midstream Partners, L.P. [Member] - USD ($) | Jan. 31, 2016 | Jan. 31, 2015 |
Class A Units [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Warrants held | $ 7,000,000 | $ 7,000,000 |
Series 1 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Strike price | $ 12.78 | |
Warrants held | $ 6,615,467 | 5,600,000 |
Series 2 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Strike price | $ 22.09 | |
Warrants held | $ 2,835,200 | 2,400,000 |
Series 3 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Strike price | $ 22.09 | |
Warrants held | $ 3,544,000 | 3,000,000 |
Series 4 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Strike price | $ 28.09 | |
Warrants held | $ 2,362,667 | $ 2,000,000 |
Series 6 Warrants [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Strike price | $ 12.50 | |
Warrants held | $ 1,269,333 |
Equity Investment And Equity 70
Equity Investment And Equity Investment Derivatives - Equity investment activity summary (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Schedule of Equity Method Investments [Line Items] | ||
Equity investment, Beginning balance | $ 64,411 | |
Impairment of investment in Caliber | (24,979) | |
Equity investment, Ending balance | 45,600 | $ 64,411 |
Caliber Midstream Partners, L.P. [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investment, Beginning balance | 64,411 | 68,536 |
Distributions | (6,080) | |
Equity investment share of net income before intra-company profit eliminations | 3,070 | 1,402 |
Change in fair value of warrants | 3,098 | 553 |
Impairment of investment in Caliber | (24,979) | |
Equity investment, Ending balance | 45,600 | 64,411 |
Fair value of warrants | $ 3,600 | $ 504 |
Equity Investment And Equity 71
Equity Investment And Equity Investment Derivatives - Financial Information of Equity Method Investee (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES | |||
Revenue | $ 64,345 | $ 42,995 | $ 11,384 |
Gross Profit | 29,630 | 16,918 | 8,395 |
Net income (loss) | 8,605 | 4,875 | $ 2,617 |
Current assets | 26,606 | 56,993 | |
Noncurrent assets | 429,534 | 423,013 | |
Total assets | 456,140 | 480,006 | |
Current liabilities | 9,806 | 45,585 | |
Noncurrent liabilities | 194,015 | 192,032 | |
Total liabilities | 203,821 | 237,617 | |
Minority interests | $ 14,432 | $ 15,373 |
Capital Stock (Details)
Capital Stock (Details) - USD ($) $ in Millions | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Common stock issued or reserved | 106,500,000 | |
Common stock, shares issued | 75,807,111 | 75,174,442 |
Common stock, shares outstanding | 75,807,111 | 75,174,442 |
Stock Repurchase authorized (Tranche 1) | $ 25 | |
Common stock repurchased (in shares) | 0 | |
Authorized shares remaining repurchase | 5,811,091 | |
2011 Omnibus Incentive Plan | ||
Shares reserved for issuance | 1,300,000 | |
2014 Plan | ||
Shares reserved for issuance | 2,800,000 | |
Shares reserved for future grants | 2,900,000 | |
CEO Stand-Alone Stock Option Agreement | ||
Shares reserved for issuance | 6,000,000 | |
Convertible Notes Payable [Member] | ||
Shares reserved for issuance | 17,600,000 |
Share-Based Compensation - Shar
Share-Based Compensation - Share based compensation expense by award type (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Additional shares to be awarded under prior plans | 0 | ||
Compensation expense before capitalized amount | $ 18,959 | $ 9,062 | $ 9,221 |
Less amounts capitalized to oil and natural gas properties | (1,565) | (1,143) | (1,391) |
Compensation expense | 17,394 | 7,919 | 7,830 |
Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense before capitalized amount | 10,345 | 6,254 | 7,496 |
Employee Stock Option | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense before capitalized amount | 7,809 | 2,299 | 1,135 |
Series B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense before capitalized amount | $ 805 | $ 509 | $ 590 |
2014 Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares reserved under Plan | 6,000,000 |
Share-Based Compensation - Acti
Share-Based Compensation - Activity for restricted stock units - (Details) - Restricted Stock Units - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Restricted stock units granted | 1,983,843 | 1,523,700 | 1,440,133 |
Unrecognized compensation | $ 14.7 | ||
Unrecognized compensation, recognition period | 2 years 1 month 6 days | ||
Number of shares per vesting unit | 1 | ||
Outstanding, Unvested Beginning Balance | 2,914,045 | 2,875,628 | 2,524,085 |
Units granted, number of units | 1,983,843 | 1,523,700 | 1,440,133 |
Units forfeited, Number of units | (574,605) | (394,921) | (141,909) |
Units that vested, Number of Shares | (867,438) | (1,090,362) | (946,681) |
Outstanding, Unvested Ending Balance | 3,455,845 | 2,914,045 | 2,875,628 |
Outstanding, Weighted-Average Award Date Fair Value, Beginning Balance | $ 7.92 | $ 6.62 | $ 6.68 |
Units granted, Weighted Average Award Date Fair Value | 4.74 | 9.42 | 6.95 |
Units forfeited, Weighted Average Award Date Fair Value | 7.06 | 7.21 | 6.58 |
Units that vested, Weighted Average Award Date Fair Value | 7.81 | 7.04 | 6.71 |
Outstanding, Weighted-Average Grant Date Fair Value, Ending Balance | $ 6.35 | $ 7.92 | $ 6.62 |
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 1 year | ||
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based awards vesting period | 5 years |
Share-Based Compensation - Stoc
Share-Based Compensation - Stock options - (Details) - Employee Stock Option $ / shares in Units, $ in Millions | 12 Months Ended |
Jan. 31, 2016USD ($)$ / sharesshares | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Outstanding options | 6,700,000 |
Number of shares exercisable | 1,433,310 |
Weighted average exercise price per share | $ / shares | $ 11.54 |
Weighted average remaining contractual life (years) | 7 years 4 months 2 days |
Weighted average exercise price per share (exercisable) | $ / shares | $ 11.70 |
Weighted average remaining contractual life (years) (exercisable) | 7 years 3 months 15 days |
Unrecognized compensation cost related to stock options | $ | $ 10.8 |
Unrecognized compensation, recognition period | 2 years 3 months 18 days |
$7.50 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 7.50 |
Remaining contractual life | 7 years 5 months 5 days |
Outstanding options | 750,000 |
Number of shares exercisable | 150,000 |
$8.50 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 8.50 |
Remaining contractual life | 7 years 5 months 5 days |
Outstanding options | 750,000 |
Number of shares exercisable | 150,000 |
$10.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 10 |
Remaining contractual life | 7 years 5 months 5 days |
Outstanding options | 1,500,000 |
Number of shares exercisable | 300,000 |
$12.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 12 |
Remaining contractual life | 7 years 5 months 5 days |
Outstanding options | 1,500,000 |
Number of shares exercisable | 300,000 |
$15.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 15 |
Remaining contractual life | 7 years 5 months 5 days |
Outstanding options | 1,500,000 |
Number of shares exercisable | 300,000 |
$12.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 12 |
Remaining contractual life | 5 years 7 months 10 days |
Outstanding options | 233,333 |
Number of shares exercisable | 77,770 |
$14.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 14 |
Remaining contractual life | 5 years 7 months 10 days |
Outstanding options | 233,333 |
Number of shares exercisable | 77,770 |
$16.00 [Member] | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Exercise Price per Share | $ / shares | $ 16 |
Remaining contractual life | 8 years 7 months 10 days |
Outstanding options | 233,334 |
Number of shares exercisable | 77,770 |
Share-Based Compensation - Rock
Share-Based Compensation - Rockpile share based compensation - (Details) $ in Millions | 12 Months Ended | ||
Jan. 31, 2016USD ($)classshares | Jan. 31, 2015shares | Jan. 31, 2014shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 5,302,000 | 4,070,000 | 3,160,000 |
Units forfeited | (226,800) | ||
Units redeemed | (180,000) | ||
Units granted | 655,000 | 1,412,000 | 910,000 |
Outstanding, Number of Units, Ending Balance | 5,730,200 | 5,302,000 | 4,070,000 |
Outstanding, Vested | 3,449,600 | ||
Outstanding, Unvested, Ending Balance | 2,280,600 | ||
Series B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation | $ | $ 1.9 | ||
Unrecognized compensation, recognition period | 2 years 10 months 24 days | ||
Series B-1 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 2,920,000 | 3,100,000 | 3,100,000 |
Units redeemed | (180,000) | ||
Outstanding, Number of Units, Ending Balance | 2,920,000 | 2,920,000 | 3,100,000 |
Outstanding, Vested | 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 | 60,000 | 60,000 |
Outstanding, Number of Units, Ending Balance | 60,000 | 60,000 | 60,000 |
Outstanding, Vested | 60,000 | ||
Series B-3 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 910,000 | 910,000 | |
Units forfeited | (96,000) | ||
Units granted | 910,000 | ||
Outstanding, Number of Units, Ending Balance | 814,000 | 910,000 | 910,000 |
Outstanding, Vested | 352,000 | ||
Outstanding, Unvested, Ending Balance | 462,000 | ||
Series B-4 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding, Number of Units, Beginning Balance | 1,412,000 | ||
Units forfeited | (90,800) | ||
Units granted | 1,412,000 | ||
Outstanding, Number of Units, Ending Balance | 1,321,200 | 1,412,000 | |
Outstanding, Vested | 117,600 | ||
Outstanding, Unvested, Ending Balance | 1,203,600 | ||
Series B-5 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units granted | 397,500 | ||
Outstanding, Number of Units, Ending Balance | 397,500 | ||
Outstanding, Unvested, Ending Balance | 397,500 | ||
Series B-6 Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units forfeited | (40,000) | ||
Units granted | 257,500 | ||
Outstanding, Number of Units, Ending Balance | 217,500 | ||
Outstanding, Unvested, Ending Balance | 217,500 | ||
Rockpile [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of classes of equity | class | 2 | ||
Rockpile [Member] | Series A | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Preferred return on investment | 8.00% | ||
Cumulative distributions to be made to Series A before distributions to Series B | $ | $ 40 | ||
Rockpile [Member] | Series B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares reserved under Plan | 6,000,000 | ||
Rockpile [Member] | Minimum [Member] | Series B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining vesting period | 3 years | ||
Share-based awards vesting period | 3 years | ||
Rockpile [Member] | Maximum [Member] | Series B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining vesting period | 5 years | ||
Share-based awards vesting period | 5 years |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and liabilities table - (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | 12 Months Ended | |
Jan. 31, 2015 | Jan. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rockpile earn-out liability | $ (1,825) | |
Commodity derivative Liabilities | $ (1,265) | |
Crude Oil Derivative Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 54,775 | 21,382 |
Equity Investment Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 504 | 3,600 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rockpile earn-out liability | (1,825) | |
Commodity derivative Liabilities | (1,265) | |
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 | 54,775 | 21,382 |
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 | $ 3,600 |
Fair Value Measurements - Debt
Fair Value Measurements - Debt instruments carrying value - (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 | Jul. 18, 2014 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Revolving credit facilities, carrying value | $ 355,772 | $ 224,159 | |
Revolving credit facilities, fair value | 355,772 | 224,159 | |
TUSA 6.75% notes, carrying value | 398,419 | 429,500 | |
TUSA 6.75% notes, fair value | 71,051 | 303,871 | |
5% convertible note, carrying value | 142,799 | 135,877 | |
5% convertible note, fair value | 125,310 | 137,790 | |
Other notes and mortgages payable, carrying value | 14,065 | 10,605 | |
Other notes and mortgages payable, fair value | $ 14,065 | $ 10,605 | |
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 6.75% Notes [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt instrument, interest rate | 6.75% | 6.75% | 6.75% |
Income Taxes - Income tax provi
Income Taxes - Income tax provision (benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Income Taxes [Abstract] | |||
Current tax expense (benefit) | $ 44 | ||
Deferred income tax expense (benefit), Federal | (302,941) | $ 42,400 | $ 7,324 |
Deferred income tax expense (benefit), State | (23,400) | 3,100 | 617 |
Deferred income tax expense (benefit), Foreign | 100 | ||
Valuation allowance - United States and Canada | 272,800 | ||
Income tax expense (benefit) | (53,397) | 45,500 | 7,941 |
Income (loss) before income taxes | $ (875,737) | $ 138,897 | $ 81,421 |
Effective income tax rate | 6.10% | 33.00% | 10.00% |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of the income tax provision (benefit) to the federal statutory rate (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Income Taxes [Abstract] | |||
Federal statutory rate | 35.00% | ||
Federal statutory tax expense (benefit) | $ (306,508) | $ 48,613 | $ 28,498 |
State income tax expense / (benefit), net of federal income tax benefit | (23,899) | 3,618 | 2,324 |
Permanent differences | 3,200 | 3,196 | 3,221 |
Difference in foreign tax rates | 222 | 539 | 164 |
Effect of tax rate change | 227 | (147) | (258) |
Credits | (106) | (338) | (100) |
State NOL adjustment | 669 | 1,061 | |
Bad debt deduction for receivables from Elmworth | (736) | (14,517) | |
Attribute reduction - cancellation of debt exclusion - Elmworth | 380 | 8,466 | |
Changes in valuation allowance | 272,781 | (7,464) | (26,364) |
Other | 373 | 2,473 | 456 |
Income tax expense (benefit) | $ (53,397) | $ 45,500 | $ 7,941 |
Effective income tax rate | 6.10% | 33.00% | 10.00% |
Statutory income tax rate | 35.00% |
Income Taxes -Components of net
Income Taxes -Components of net deferred income tax assets and liabilities (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 |
Income Taxes [Abstract] | ||
United States net losses carried forward | $ 104,464 | $ 48,443 |
United States oil and natural gas properties | 199,920 | |
Asset retirement obligation | 3,073 | 2,592 |
Accruals | 1,138 | |
Stock-based compensation | 7,155 | 3,182 |
Other | 251 | 2,395 |
Total deferred income tax assets | 314,863 | 57,750 |
United States oil and natural gas properties | (56,531) | |
Investment in Caliber | (32,613) | (32,661) |
Hedging liabilities | (8,276) | (20,806) |
Total deferred non-current income tax liability | (40,889) | (109,998) |
Valuation allowance | $ (273,974) | (1,193) |
Net deferred income tax asset (liability) | $ (53,441) |
Income Taxes - Operating loss c
Income Taxes - Operating loss carryforwards (Details) - USD ($) $ in Millions | 12 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Income Taxes [Abstract] | ||
Impairment of oil and natural gas properties | $ 779 | |
Net operating loss carryforward | 286 | |
Operating loss carryovers for financial reporting purposes | 280.2 | |
Net operating loss carryforwards that do not benefit financial statements | 5.8 | |
Unrecognized tax benefits | 0 | $ 0 |
Provision for uncertain tax positions | $ 0 | $ 0 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Millions | 12 Months Ended | ||
Jan. 31, 2016USD ($)item | Jan. 31, 2015USD ($)item | Jan. 31, 2014USD ($) | |
Related Party Transaction [Line Items] | |||
Term of gathering services agreements | 5 years | ||
Number of salt water disposal wells sold | item | 1 | 1 | |
Proceeds from sale of salt water disposal wells | $ 6 | $ 1.5 | |
TUSA [Member] | |||
Related Party Transaction [Line Items] | |||
Contractual Obligation, Cumulative Credit | $ 41.5 | ||
Term of carryforward of credit | 4 years | ||
Revenues from related parties | $ 53.9 | 36.6 | $ 15 |
Payables to related party | $ 9.6 | $ 5 | |
Caliber North Dakota LLC [Member] | |||
Related Party Transaction [Line Items] | |||
Term of midstream agreements with Caliber | 15 years | ||
Minimum commitment over term of agreements | $ 405 | ||
Remaining commitment | $ 303.4 |
Commitments And Contingencies -
Commitments And Contingencies - Future minimum lease payments under operating leases (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Non-cancelable operating leases: | |||
Operating Leases, Rent Expense | $ 5,200 | $ 1,800 | $ 800 |
Future minimum lease payments under operating eases: | |||
2,017 | 9,476 | ||
2,018 | 8,939 | ||
2,019 | 8,241 | ||
2,020 | 8,007 | ||
2021 and thereafter | $ 17,719 |
Commitments and Contingencies85
Commitments and Contingencies - Additional disclosures (Details) - Chief Executive Officer [Member] $ in Millions | 12 Months Ended |
Jan. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Contingent liability for bonus payout to CEO | $ 1.9 |
Caliber Midstream Partners, L.P. [Member] | |
Long-term Purchase Commitment [Line Items] | |
Percentage bonus payout of gain on sale of subsidiary | 5.00% |
Rockpile [Member] | |
Long-term Purchase Commitment [Line Items] | |
Percentage bonus payout of gain on sale of subsidiary | 3.50% |
Supplemental Disclosures Of C86
Supplemental Disclosures Of Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Supplemental Disclosures of Cash Flow Information [Abstract] | |||
Interest expense | $ 32,319 | $ 19,713 | $ 1,419 |
Income taxes | 600 | ||
Increase (decrease) in accounts payable and accrued liabilities | (87,570) | 47,838 | 30,785 |
Issuance of common stock | 2,438 | ||
Capitalized stock-based compensation | 1,565 | 1,143 | 1,391 |
Change in asset retirement obligations | $ 1,156 | $ 1,818 | 673 |
Acquisition of oilfield services equipment through notes payable and liabilities | $ 1,990 |
Quarterly Financial Informati87
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Jan. 31, 2016 | Oct. 31, 2015 | Jul. 31, 2015 | Apr. 30, 2015 | Jan. 31, 2015 | Oct. 31, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Quarterly Financial Information [Abstract] | |||||||||||
Total revenue | $ 64,964 | $ 65,144 | $ 109,733 | $ 118,288 | $ 156,988 | $ 174,196 | $ 141,989 | $ 99,782 | $ 358,129 | $ 572,955 | $ 258,747 |
Income (loss) from operations | (155,688) | (285,185) | (213,368) | (213,942) | 877 | 33,534 | 38,489 | 22,483 | (868,183) | 95,383 | 46,962 |
Net income (loss) | (161,796) | (286,999) | (193,346) | (180,199) | 38,905 | 25,398 | 14,552 | 14,542 | (822,340) | 93,397 | 73,480 |
Net income (loss) attributable to common stockholders | $ (161,796) | $ (286,999) | $ (193,346) | $ (180,199) | $ 38,905 | $ 25,398 | $ 14,552 | $ 14,542 | $ (822,340) | $ 93,397 | $ 73,480 |
Net income (loss) per common share - basic | $ (2.14) | $ (3.80) | $ (2.56) | $ (2.39) | $ 0.50 | $ 0.30 | $ 0.17 | $ 0.17 | $ (10.89) | $ 1.12 | $ 1.07 |
Net income (loss) per common share - diluted | $ (2.14) | $ (3.80) | $ (2.56) | $ (2.39) | $ 0.42 | $ 0.26 | $ 0.15 | $ 0.15 | $ (10.89) | $ 0.97 | $ 0.91 |
Supplemental Information On O88
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Reserve estimates (Details) | 12 Months Ended | |||
Jan. 31, 2016MBoeMMcfMBbls | Jan. 31, 2015MBoeMMcfMBbls | Jan. 31, 2014MBoeMMcfMBbls | Jan. 31, 2013MBoeMMcfMBbls | |
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance (Energy) | MBoe | 58,870 | 40,314 | 14,637 | |
Revisions of previous estimates (Energy) | MBoe | (13,813) | 1,558 | 4,344 | |
Purchase of reserves (Energy) | MBoe | 4,150 | 8,313 | ||
Extensions, discoveries and other additions (Energy) | MBoe | 8,753 | 17,027 | 15,502 | |
Sale of reserves (Energy) | MBoe | (29) | (3) | (553) | |
Production (Energy) | MBoe | (4,897) | (4,176) | (1,929) | |
Total proved reserves, ending balance (Energy) | MBoe | 48,884 | 58,870 | 40,314 | |
Proved developed (Energy) | MBoe | 38,465 | 35,978 | 16,995 | 5,969 |
Proved undeveloped, Energy | MBoe | 10,419 | 22,892 | 23,319 | 8,668 |
Crude Oil Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | 48,091 | 31,916 | 12,539 | |
Revisions of previous estimates | (12,309) | 2,087 | 2,727 | |
Purchase of reserves | 3,655 | 6,836 | ||
Extensions, discoveries and other additions | 7,100 | 13,946 | 12,059 | |
Sale of reserves | (29) | (2) | (491) | |
Production | (3,952) | (3,511) | (1,754) | |
Total proved reserves, ending balance | 38,901 | 48,091 | 31,916 | |
Proved Developed, Volume | 30,328 | 29,605 | 13,734 | 4,985 |
Proved Undeveloped, Volume | 8,573 | 18,486 | 18,182 | 7,554 |
Natural Gas Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | MMcf | 40,185 | 26,504 | 12,585 | |
Revisions of previous estimates | MMcf | (10,360) | 1,475 | (859) | |
Purchase of reserves | MMcf | 2,928 | 4,714 | ||
Extensions, discoveries and other additions | MMcf | 5,113 | 11,710 | 11,064 | |
Sale of reserves | MMcf | (3) | (374) | ||
Production | MMcf | (3,115) | (2,429) | (626) | |
Total proved reserves, ending balance | MMcf | 31,823 | 40,185 | 26,504 | |
Proved Developed, Volume | MMcf | 26,001 | 24,136 | 10,930 | 5,906 |
Proved Undeveloped, Volume | MMcf | 5,822 | 16,049 | 15,574 | 6,679 |
Natural Gas Liquids Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Total proved reserves, beginning balance | 4,081 | 3,981 | ||
Revisions of previous estimates | 223 | (776) | 1,762 | |
Purchase of reserves | 7 | 690 | ||
Extensions, discoveries and other additions | 801 | 1,129 | 1,599 | |
Production | (426) | (260) | (70) | |
Total proved reserves, ending balance | 4,679 | 4,081 | 3,981 | |
Proved Developed, Volume | 3,803 | 2,350 | 1,440 | |
Proved Undeveloped, Volume | 876 | 1,731 | 2,541 |
Supplemental Information On O89
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Average prices reflected in the calculation of the Standardized Measure (Details) | 12 Months Ended | ||
Jan. 31, 2016$ / Mcfe$ / bbl | Jan. 31, 2015$ / Mcfe$ / bbl | Jan. 31, 2014$ / Mcfe$ / bbl | |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |||
Oil price per barrel | 38.41 | 79.71 | 93.09 |
Natural gas price per Mcf | $ / Mcfe | 0.55 | 6.09 | 3.99 |
Natural gas liquids price per barrel | 2.45 | 34.61 | 44.10 |
Supplemental Information On O90
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Changes in proved reserves (Details) $ in Thousands | 12 Months Ended | ||||||||||
Jan. 31, 2016USD ($)MMcf | Jan. 31, 2016USD ($)MBbls | Jan. 31, 2016USD ($)MBoe | Jan. 31, 2016USD ($)MMBoe | Jan. 31, 2016USD ($)item | Jan. 31, 2015USD ($)MMcf | Jan. 31, 2015USD ($)MBbls | Jan. 31, 2015USD ($)MBoe | Jan. 31, 2015USD ($)MMBoe | Jan. 31, 2015USD ($)item | Jan. 31, 2014USD ($)itemMBoeMMcfMBbls | |
Reserve Quantities [Line Items] | |||||||||||
Upward revision of reserve | MMBoe | 9.4 | ||||||||||
Downward adjustment of reserve | MMBoe | 23.2 | ||||||||||
Proved undeveloped reserve (MBOE) ending balance | 10,419 | 10.4 | 22,892 | 22.9 | 23,319 | ||||||
Unused Elements | |||||||||||
Net increase and decrease on proved undeveloped reserve BOE 1 | MMBoe | 12.5 | ||||||||||
Estimated future net costs | $ | $ 636,433 | $ 636,433 | $ 636,433 | $ 636,433 | $ 636,433 | $ 1,798,580 | $ 1,798,580 | $ 1,798,580 | $ 1,798,580 | $ 1,798,580 | $ 1,263,799 |
Gross Wells [Member] | |||||||||||
Unused Elements | |||||||||||
Proved undeveloped wells, became developed during period | item | 12 | 30 | 32 | ||||||||
Net Wells [Member] | |||||||||||
Unused Elements | |||||||||||
Proved undeveloped wells, became developed during period | item | 5.8 | 18.5 | 7.9 | ||||||||
Crude Oil Reserves [Member] | |||||||||||
Reserve Quantities [Line Items] | |||||||||||
Proved reserves added by extensions and discoveries | 7,100 | 13,946 | 12,059 | ||||||||
Revisions of previous estimates | (12,309) | 2,087 | 2,727 | ||||||||
Increase in reserves due to purchase of proved properties | 3,655 | 6,836 | |||||||||
Natural Gas Reserves [Member] | |||||||||||
Reserve Quantities [Line Items] | |||||||||||
Proved reserves added by extensions and discoveries | MMcf | 5,113 | 11,710 | 11,064 | ||||||||
Revisions of previous estimates | MMcf | (10,360) | 1,475 | (859) | ||||||||
Increase in reserves due to purchase of proved properties | MMcf | 2,928 | 4,714 | |||||||||
Natural Gas Liquids Reserves [Member] | |||||||||||
Reserve Quantities [Line Items] | |||||||||||
Proved reserves added by extensions and discoveries | 801 | 1,129 | 1,599 | ||||||||
Revisions of previous estimates | 223 | (776) | 1,762 | ||||||||
Increase in reserves due to purchase of proved properties | 7 | 690 |
Supplemental Information On O91
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Proved undeveloped reserves (Details) $ in Millions | 12 Months Ended | ||||||
Jan. 31, 2016MBoe | Jan. 31, 2016MMBoe | Jan. 31, 2016item | Jan. 31, 2016USD ($) | Jan. 31, 2015MBoe | Jan. 31, 2015item | Jan. 31, 2014itemMBoe | |
Reserve Quantities [Line Items] | |||||||
Proved undeveloped reserve (MBOE) beginning balance | 22,892 | 22.9 | 23,319 | 8,668 | |||
Became developed reserves during fiscal year | MBoe | (2,668) | (8,461) | (3,701) | ||||
Traded for net acres in drill spacing units | MBoe | (353) | ||||||
Net revisions | MBoe | (14,693) | 1,676 | 84 | ||||
Acquisition of additional interests in PUD location | MBoe | 528 | 5,466 | |||||
Extensions and discoveries of proved reserves | MBoe | 4,888 | 5,830 | 13,155 | ||||
Proved undeveloped reserve (MBOE) ending balance | 10,419 | 10.4 | 22,892 | 23,319 | |||
Investment in drilling and completion of wells | $ | $ 48 | ||||||
Investment in drilling and completion per well | $ | $ 8.3 | ||||||
Gross Wells [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved undeveloped wells, beginning balance | 103 | 104 | 59 | ||||
Proved undeveloped wells, became developed during period | (12) | (30) | (32) | ||||
Proved undeveloped wells, traded for net acres in other drill spacing units | (4) | ||||||
Proved undeveloped wells, net revisions | (66) | (14) | |||||
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 6 | 13 | |||||
Proved undeveloped wells, extensions and discoveries | 18 | 37 | 68 | ||||
Proved undeveloped wells, ending balance | 43 | 103 | 104 | ||||
Net Wells [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved undeveloped wells, beginning balance | 54 | 52.5 | 19.8 | ||||
Proved undeveloped wells, became developed during period | (5.8) | (18.5) | (7.9) | ||||
Proved undeveloped wells, traded for net acres in other drill spacing units | (0.8) | ||||||
Proved undeveloped wells, net revisions | (39) | 4.7 | |||||
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations | 1.3 | 11.8 | |||||
Proved undeveloped wells, extensions and discoveries | 8.4 | 14 | 29.6 | ||||
Proved undeveloped wells, ending balance | 17.6 | 54 | 52.5 |
Supplemental Information On O92
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Proved undeveloped locations (Details) | 12 Months Ended |
Jan. 31, 2016item | |
PUD Locations [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2021 | 32 |
Proved undeveloped locations non-operated wells to be drilled by January 31,2021 | 11 |
Proved undeveloped locations additions to proved undeveloped reserves | 43 |
Development Wells Gross [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2021 | 32 |
Proved undeveloped locations non-operated wells to be drilled by January 31,2021 | 11 |
Proved undeveloped locations additions to proved undeveloped reserves | 43 |
Development Wells Net [Member] | |
Development Wells Drilled [Line Items] | |
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2021 | 15.9 |
Proved undeveloped locations non-operated wells to be drilled by January 31,2021 | 1.7 |
Proved undeveloped locations additions to proved undeveloped reserves | 17.6 |
Supplemental Information On O93
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Standardized Measure (Details) - USD ($) $ in Thousands | Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | Jan. 31, 2013 |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | ||||
Future cash inflows | $ 1,523,105 | $ 4,219,155 | $ 3,252,079 | |
Future costs: | ||||
Production | (736,573) | (1,586,288) | (1,118,508) | |
Development | (150,099) | (439,749) | (505,432) | |
Future income tax expense | (394,538) | (364,340) | ||
Future net cash flows | 636,433 | 1,798,580 | 1,263,799 | |
10% discount factor | (307,649) | (977,088) | (690,564) | |
Standardized measure of discounted future net cash flows relating to proved reserves | 328,784 | 821,492 | 573,235 | $ 211,352 |
Future development costs | $ 150,099 | $ 439,749 | $ 505,432 |
Supplemental Information On O94
Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) - Sources of change in the Standardized Measure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jan. 31, 2016 | Jan. 31, 2015 | Jan. 31, 2014 | |
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract] | |||
Standardized measure, beginning of period | $ 821,492 | $ 573,235 | $ 211,352 |
Extensions and discoveries, net of future production and development costs | 28,807 | 312,185 | 333,140 |
Sales, net of production costs | (96,450) | (210,505) | (123,786) |
Previously estimated development costs incurred during the period | 71,047 | 121,282 | 66,724 |
Revision of quantity estimates | (89,939) | 24,115 | 73,598 |
Net change in prices, net of production costs | (677,165) | (141,200) | 19,173 |
Acquisition of reserves | 91,327 | 99,683 | |
Divestitures of reserves | (776) | (72) | (7,341) |
Accretion of discount | 98,281 | 67,790 | 22,486 |
Changes in future development costs | 12,042 | 57,259 | 7,699 |
Change in income taxes | 161,322 | (56,652) | (91,161) |
Change in production timing and other | 123 | (17,272) | (38,332) |
Standardized measure, end of period | $ 328,784 | $ 821,492 | $ 573,235 |
Percentage of discount on future cash flows from proved reserves | 10.00% |