| 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 |
