Significant Accounting Policies

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4.

 

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”).

 

 

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  compared to the average realized prices in

 

 

In Accounting Standards Update - Leases () (“ASU -) was issued requiring an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases.  The classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses.  ASU - also requires certain quantitative and qualitative disclosures about leasing arrangements.  Leases acquired to explore for or extract oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are within the scope of this standard’s update.  ASU - was effective for us in the quarter of and we adopted the new standard using a modified retrospective approach, with the date of initial application on Consequently, upon transition, we recognized an ROU asset and a lease liability with retained earnings impact.  See Note  for additional information.

 

 

We consider all highly liquid investments purchased with original or remaining maturities of 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 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 be sufficient to enable the under-produced party to recoup its entitled share through production.  We do record receivables for those properties in which we have taken less than our ownership share of production.  At  and  million and  million, respectively, were included in current liabilities related to natural gas imbalances.

 

 

Our customers are primarily large integrated oil and natural gas companies and large commodity trading companies.  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 -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 or more of our receipts from sales of crude oil, NGLs and natural gas:

 

 

		Year Ended December 31,
		2019				2018				2017
Customer
Shell Trading (US) Co./ Shell Energy N.A.			11	%			30	%			46	%
BP Products North America			40	%			20	%			**
Vitol Inc.			12	%			14	%			15	%

 

 

We believe that the loss of any of the customers above would 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.

 

 

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 use the specific identification method of determining if an allowance for doubtful accounts is needed and the amounts recorded relate to certain joint interest owners.  The following table describes the balance and changes to the allowance for doubtful accounts (in thousands):

 

		2019				2018				2017
Allowance for doubtful accounts, beginning of period		$	9,692			$	9,114			$	7,602
Additional provisions for the year			206				1,233				1,512
Uncollectible accounts written off			—				(655	)			—
Allowance for doubtful accounts, end of period		$	9,898			$	9,692			$	9,114

 

 

 

Amounts recorded in on the Consolidated Balance Sheets are expected to be realized within year. The following table provides the primary components (in thousands):

 

		December 31,
		2019				2018
Derivatives – current (1)		$	7,266			$	60,687
Unamortized bonds/insurance premiums			4,357				5,197
Prepaid deposits related to royalties			7,980				8,872
Prepayment to vendors			10,202				864
Other			886				786
Prepaid expenses and other assets		$	30,691			$	76,406

 

 

 

We use the full-cost method of accounting for oil and natural gas properties and equipment, which are recorded at cost.  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 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 recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.  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.

 

Sales of proved and unproved oil and natural gas properties, whether or being amortized currently, are accounted for as adjustments of capitalized costs with 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 to 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. There were amounts excluded from amortization as of the dates presented in the following table (in thousands):

 

		December 31,
		2019				2018
Oil and natural gas properties and equipment		$	8,532,196			$	8,169,871
Furniture, fixtures and other			20,317				20,228
Total property and equipment			8,552,513				8,190,099
Less accumulated depreciation, depletion and amortization			7,803,715				7,674,678
Oil and natural gas properties and other, net		$	748,798			$	515,421

 

 

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 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 (ii) plus the cost of unproved oil and natural gas properties 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 -day-of-the-month commodity prices over the prior months for that period.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.

 

We did record a ceiling test write-down during or   If average crude oil and natural gas prices decrease significantly, it is possible that ceiling test write-downs could be recorded during  or in future periods.

 

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 such costs requires us to make judgments on both the costs and the timing of ARO.  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 for additional information.

 

 

We use the unweighted average of -day-of-the-month commodity prices over the preceding -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 -month average commodity prices.  Proved undeveloped reserves only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within years, with some limited exceptions allowed.  Refer to Note for additional information about our proved reserves.

 

 

We have exposure related to commodity prices and have used various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas.  We do enter into derivative instruments for speculative trading purposes.  We entered into commodity derivatives contracts during and and as of we had open commodity derivative instruments.  When we have outstanding borrowings on our revolving bank credit facility, we use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates.  During and we did 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.  We have elected to designate our derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in earnings.  These derivative instruments or have qualified for hedge accounting treatment. 

 

 

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 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 that some portion or all of them will be realized.  We recognize uncertain tax positions in our financial statements when it is more likely than that we will sustain the benefit taken or expected to be taken.  We classify interest and penalties related to uncertain tax positions in income tax expense.  See Note for additional information.

 

The major categories recorded in are presented in the following table (in thousands):

 

		December 31,
		2019				2018
Appeal bond deposits		$	6,925			$	6,925
Escrow deposit – Apache lawsuit (Note 18)			—				49,500
Unamortized debt issuance costs			3,798				4,773
Investment in White Cap, LLC			2,590				2,586
Derivatives			2,653				21,275
Unamortized brokerage fee for Monza			3,423				2,277
Proportional consolidation of Monza's other assets (Note 4)			5,308				3,275
ROU assets (Note 7)			7,936				—
Other			814				936
Total other assets		$	33,447			$	91,547

 

 

The major categories recorded in are presented in the following table (in thousands):

 

		December 31,
		2019				2018
Accrued interest		$	10,180			$	12,385
Accrued salaries/payroll taxes/benefits			2,377				2,320
Incentive compensation plans			9,794				10,817
Litigation accruals			3,673				3,673
Lease liability (Note 7)			2,716				—
Derivatives			1,785				—
Other			371				416
Total accrued liabilities		$	30,896			$	29,611

 

 

We accounted for a debt exchange transaction in which is described in Note as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification - (“ASC -).  Under ASC - the carrying value of the debt issued during (as described in Note ) is measured using all future undiscounted payments (principal and interest); therefore, interest expense was recorded for the debt issued in in the Consolidated Statements of Operations since through Additionally, interest paid related to the debt issued in was classified as a financing activity in the Consolidated Statements of Cash Flows as required under ASC -  See Note for additional information.

 

 

Debt issuance costs associated with the Sixth Amended and Restated Credit Agreement (the “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 (noncurrent) and unamortized debt issuance costs associated with our other debt instruments are reported as a reduction in in the Consolidated Balance Sheets.  See Note for additional information.

 

 

Discounts were recorded in in the Consolidated Balance Sheets and were amortized over the term of the related debt using the effective interest method.

 

 

During the refinancing of our capital structure resulted in a gain of million as a result of writing off the carrying value adjustments related to the debt issued in partially offset by premiums paid to repurchase and retire, repay or redeem all of our prior debt instruments.  During differences in the utilization of the payment-in-kind option resulted in a gain.  See Note for additional information.

 

 

The major categories recorded in are presented in the following table (in thousands):

 

		December 31,
		2019				2018
Dispute related to royalty deductions		$	4,687			$	4,687
Dispute related to royalty-in-kind			250				2,235
Lease liability (Note 7)			4,419				—
Apache lawsuit (Note 18)			—				49,500
Uncertain tax positions including interest/penalties (Note 13)			—				11,523
Other			632				745
Total other liabilities (long-term)		$	9,988			$	68,690

 

 

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 for additional information.

 

 

For  the amount consists primarily of federal royalty obligation reductions claimed in the current year related to capital deductions from prior periods, and partially offset by expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program (as defined in Note ).  For the amount consists primarily 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.  For the amount consists primarily of expense items related to the Apache Corporation ("Apache") lawsuit, partially offset by loss-of-use reimbursements from a -party for damages incurred at of our platforms. 

 

 

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 per share under the -class method when the effect is dilutive.  See Note for additional information.

 

 

In the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update - () (“ASU -) and subsequently issued additional guidance on this topic.  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 - is effective for fiscal years beginning after and early adoption is permitted for fiscal years beginning after Our assessment is this amendment will have a material impact on our financial statements.

 

In the FASB issued Accounting Standards Update - (“ASU -) and subsequently issued additional guidance on this topic.  The amendments in ASU - 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 - is effective for fiscal years beginning after and interim periods within fiscal years beginning after Early adoption is permitted, including adoption in an interim period.  As we do designate our commodity derivative instruments as qualifying hedging instruments, our assessment is this amendment will impact the presentation of the changes in fair values of our commodity derivative instruments on our financial statements.