Significant Accounting Policies
|12 Months Ended|
Dec. 31, 2018
|Accounting Policies [Abstract]|
|Significant Accounting Policies||
1. Significant Accounting Policies
W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer with substantially all of its operations in the Gulf of Mexico. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our 100% owned subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in Note 4.
Basis of Presentation
Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities improved in 2018 compared to the average realized prices in 2017.
In October 2018, we substantially changed our capital structure through the issuance of secured senior notes, which when combined with cash on hand, funded the repurchasing and retirement, repayment or redemption of all of the prior debt instruments. This transaction reduced the amount of debt outstanding and extended debt maturities with the new debt instruments maturing on November 1, 2023. In addition, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), which matures on October 18, 2022 and increased the borrowing base from $150.0 million to $250.0 million. See Note 2 for additional information.
We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate liquidity to fund our operations through February 2020, the period of assessment to qualify as a going concern. However, we cannot predict the potential changes in commodity prices, which could affect our operations, liquidity levels and compliance with debt obligations.
Certain reclassifications have been made to prior periods’ financial statements to conform to the current year presentation as follows: In the Consolidated Statements of Operations, interest income was reclassified from Other (income) expense, net to Interest expense, net, and amounts related to capitalized interest are included in the line Interest expense, net. Neither of these reclassifications changed Net income (loss) before income tax expense (benefit). In the Consolidated Statements of Cash Flows, within the Net cash provided by operating activities and the Net cash used in investing activities sections, adjustments were made to certain line items, of which did not change the total amounts previously reported. These adjustments did not affect the Consolidated Balance Sheets.
Accounting Standard Updates Effective January 1, 2018
Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018. The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business. In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business.
Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us as of January 1, 2018. We reviewed our contracts using the five-step revenue recognition model, which did not identify any changes required as to the amount or timing of revenue recognition. We adopted the new standard using the modified retrospective approach which did not result in any cumulative-effect adjustment on the date of adoption. The implementation of ASU 2014-09 resulted in a change in our reporting in the Consolidated Statements of Operations and we report revenue streams separately for crude oil, NGLs, natural gas and other revenues in compliance with the new standard.
We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.
We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied. Our contracts with customers are primarily short-term (less than 12 months). Our responsibilities to deliver a unit of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials.
We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production. At December 31, 2018 and 2017, $4.1 million and $4.7 million, respectively, were included in current liabilities related to natural gas imbalances.
Concentration of Credit Risk
Our customers are primarily large integrated oil and natural gas companies, large financial institutions and large trading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when considered necessary.
The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas:
** Less than 10%
We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.
Accounts Receivables and Allowance for Bad Debts
Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts:
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 7 for additional information.
Prepaid expenses and other assets
Amounts recorded in Prepaid expenses and other assets on the Consolidated Balance Sheets are expected to be realized within one year. The following table describes the major items for the periods presented:
Properties and Equipment
We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.
Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.
We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and other, net on the Consolidated Balance Sheets.
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.
Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. Oil and natural gas properties and equipment are recorded at cost using the full-cost method.
Oil and Natural Gas Properties and Other, Net – at cost
Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):
Ceiling Test Write-Down
Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.
We did not record a ceiling test write-down during 2018 or 2017. We recorded ceiling test write-downs in 2016, which was reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas. The ceiling test write-downs of the carrying value of our oil and natural gas properties was $279.1 million for 2016. If average crude oil and natural gas prices decrease significantly, it is possible that ceiling test write-downs could be recorded during 2019 or future periods.
Asset Retirement Obligations
We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. See Note 6 for additional information.
Oil and Natural Gas Reserve Information
We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 20 for additional information about our proved reserves.
Derivative Financial Instruments
Our market risk exposure relates primarily to commodity prices. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2018 and 2017, and as of December 31, 2018, we had open commodity derivative instruments. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates. During 2018 and 2017, we did not enter into any derivative instruments related to interest rates.
Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. Whenever we have entered into derivative contracts, we did not designate our derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in earnings.
Fair Value of Financial Instruments
We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments.
We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. See Note 13 for additional information.
Other Assets (long-term)
The major categories recorded in Other assets are presented in the following table (in thousands):
The major categories recorded in Accrued liabilities are presented in the following table (in thousands):
Debt Issued During 2016
We accounted for a debt exchange transaction in 2016, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”). Under ASC 470-60, the carrying value of the debt issued during 2016 (as described in Note 2) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the debt issued in 2016 in the Consolidated Statements of Operations since September 7, 2016 through October 18, 2018. Additionally, interest paid related to the debt issued in 2016 was classified as a financing activity in the Consolidated Statements of Cash Flows as required under ASC 470-60. See Note 2 for additional information.
Debt Issuance Costs
Debt issuance costs associated with our Credit Agreement are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our Credit Agreement is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt instruments is reported as a reduction in Long-term debt, less current portion – carrying value in the Consolidated Balance Sheets. See Note 2 for additional information.
Premiums Received and Discounts Provided on Debt Issuance
Premiums and discounts were recorded in Long-term debt, less current portion – carrying value in the Consolidated Balance Sheets and were amortized over the term of the related debt using the effective interest method.
Gain on Debt Transactions
During 2018, the refinancing of our capital structure resulted in a gain of $47.1 million as a result of writing off the carrying value adjustments related to the debt issued in 2016, partially offset by premiums paid to repurchase and retire, repay or redeem all of our prior debt instruments. The gains recorded in 2017 and 2016 of $7.8 million and $123.9 million, respectively, relate to the debt exchange transaction occurring during 2016. Differences in the utilization of the payment-in-kind option during 2017 resulted in adjustments to the gain previously recorded in 2016. See Note 2 for additional information.
Other Liabilities (long-term)
The major categories recorded in Other liabilities are presented in the following table (in thousands):
Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for additional information.
Other (Income) Expense, Net
For 2018, the amount consists of credits related to the de-recognition of certain liabilities that had exceeded the statute of limitations partially offset by expense related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program (as defined in Note 4). For 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. For 2016, the amount consists primarily of write-offs of debt issuance costs.
Earnings (Loss) Per Share
Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings (loss) per share under the two-class method when the effect is dilutive. See Note 14 for additional information.
Recent Accounting Developments
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a financing or operating lease. However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet. ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements. ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective or the full retrospective approach. We expect to adopt ASU 2016-02 using the modified retrospective approach. Our current operating lease that will be impacted by ASU 2016-02 is our lease for office space, which is in Houston, Texas and will result in an increase in assets and liabilities of approximately $5.0 million. Although we did not identify other arrangements impacted by ASU 2016-02, future arrangements related to equipment may be impacted depending on the facts and circumstances. As of December 31, 2018, we did not have any leases classified as financing leases.
In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (“ASU 2016-13”). The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018. We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.
In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”). The amendments in ASU 2017-12 require an entity to present the earnings effect of the hedging instrument in the same income statement line in which the earning effect of the hedged item is reported. This presentation enables users of financial statements to better understand the results and costs of an entity’s hedging program. Also, relative to current GAAP, this approach simplifies the financial statement reporting for qualifying hedging relationships. ASU 2017-12 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020. Early adoption is permitted, including adoption in an interim period. As we do not designate our commodity derivative instruments as qualifying hedging instruments, our assessment is this amendment will not impact the presentation of the changes in fair values of our commodity derivative instruments on our financial statements.
The entire disclosure for all significant accounting policies of the reporting entity.
Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef