UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended March 31, 2016

or

For the transition period from _______________ to ________________

Commission File Number 1-32414

 

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

 

(713) 626-8525

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company.    Yes  ¨    No  þ  

As of May 2, 2016, there were 76,508,829 shares outstanding of the registrant’s common stock, par value $0.00001.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

 

 

 

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PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY (DEFICIT)

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.  Basis of Presentation

Operations.  W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico.  The Company is 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 W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).  On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 2.  

Interim Financial Statements.  The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim periods and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements for annual periods.  In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year.  These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

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 and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ from those estimates.

Recent Events.  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 and future rate of growth.  The prices of these commodities began falling in the second half of 2014, continued to generally decline in 2015 and declined further in the first quarter of 2016.   Steps taken  during 2015 and 2016 to mitigate the effects of these lower prices include: (i) significantly reducing the budgeted capital spending for 2016; (ii) continuing the suspension of our drilling and completion activities at several locations; (iii) continued suspension of the regular quarterly common stock dividend; (iv) selling our interests in the Yellow Rose field in the fourth quarter of 2015; (v) reducing our headcount of employees and contractors; and (vi) continuing the implementation of numerous projects to reduce our operating costs.  See our Annual Report on Form 10-K for the year ended December 31, 2015 concerning risks related to our business and events occurring during 2015 and other information.  

In February 2016, we borrowed $340.0 million under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”).  On March 23, 2016, the banks reduced our borrowing base to $150.0 million from $350.0 million in connection with the spring borrowing base redetermination.  We are required to repay borrowings outstanding in excess of the redetermined borrowing base pursuant to the terms of the Credit Agreement.  On March 31, 2016, we repaid $52.0 million leaving an outstanding balance under the Credit Agreement of $288.0 million as of March 31, 2016.  We also had approximately $1.0 million of letters of credit outstanding as of March 31, 2016.  On May 2, 2016, we repaid an additional $12.0 million.  Additional payments are required of $64.0 million on May 30, 2016 and $64.0 million on June 30, 2016, in addition to interest payments on our long-term debt, which will bring total borrowings outstanding under the credit agreement in conformity with the borrowing base limitation.  See Note 5 for additional information.

    

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

In February and March 2016, we received several orders from the Bureau of Ocean Energy Management (“BOEM”) demanding that we provide additional supplemental bonding on certain Federal offshore oil and gas leases, rights of way and rights of use and easement owned and/or operated by the Company.  One order was rescinded and re-issued and another one was rescinded. The outstanding orders total approximately $260.8 million.  We have filed appeals with the Interior Board of Land Appeals (“IBLA”) regarding three of the BOEM orders - specifically the February order that required W&T to post a total of $159.8 million in supplemental bonding and two March orders requiring $68.0 million in supplemental bonding.  We have had discussions with the BOEM and its sister agency, the Bureau of Safety and Environmental Enforcement (“BSEE”), since receiving the orders.  The objective of the Company remains to reach a mutual agreement on the financial assurance requirements of the demands.  The issuance of any additional surety bonds to satisfy the BOEM orders or any future BOEM orders may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  We continue to have discussions with the BOEM regarding these matters.  See Notes 11 and 12 for additional information

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through March 31, 2017; however, we cannot predict how an extended period of low commodity prices or the impact of future bonding requirements will affect our operations, liquidity levels and compliance with debt covenants.

Ceiling Test Write-Down.  Under the full cost method of accounting, each quarter we are required to perform a “ceiling test,” 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 asset retirement obligations (“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.

Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas, we recorded ceiling test write-downs in the first quarter of 2016 and 2015, which are reported as a separate line in the Statements of Operations.  The average price using the SEC required methodology at March 31, 2016 was $42.77 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.40 per million British Thermal Unit  (“MMBtu”) for Henry Hub natural gas before adjustments.  Ceiling test write-downs of the carrying value of our oil and natural gas properties for the three months ended March 31, 2016 and 2015 were $116.6 million and $260.4 million, respectively.  The ceiling test write-down for the full year of 2015 was $987.2 million.  If crude oil and natural gas prices remain or decrease from current levels, it is probable that a ceiling test write-down will be recorded in the second quarter of 2016 and possibly in subsequent quarters during 2016.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Prepaid Expenses and Other.  Amounts recorded in Prepaid expenses and other on the Condensed Consolidated Balance Sheets are expected to be realized within one year.  Major categories are disclosed in the following table:

 

Recent Accounting Developments.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  We have not determined the effect ASU 2014-09 will have on the recognition of our revenue, if any, nor have we determined the method we will utilize upon adoption, which would be in the first quarter of 2018.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40).  The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter.  We do not expect the revised guidance to materially affect our evaluation as to being a going concern, or have an effect on our financial statements or related disclosures.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  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 finance or operating lease.  However, unlike current GAAP, which requires only capital 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.  Our current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston and New Orleans, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718).  The objective of ASU 2016-09 is for simplification involving several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  ASU 2016-09 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted.  We have not yet fully determined or quantified the effect ASU 2016-09 will have on our financial statements. 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

2.  Divestitures

2015 Divestiture

On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.8 million in cash, which includes certain customary post effective date price adjustments, and Ajax assumed responsibility for the related ARO and other associated liabilities.  The effective date of the sale was January 1, 2015.  A net purchase price adjustment of $1.0 million was recorded during the three months ended March 31, 2016.  Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas.  We retained a non-expense bearing overriding royalty interest (“ORRI”) in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the New York Mercantile Exchange (“NYMEX”) prompt month contract trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  

Under the full cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, 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 attributable to the cost center.  The sale to Ajax did not represent greater than 25% of the Company’s proved reserves of oil and natural gas attributable to the full cost pool.  As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.        

3.  Asset Retirement Obligations

Our ARO primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws.  

A summary of the changes to our ARO is as follows (in thousands):  

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

4.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.

For information about fair value measurements, refer to Note 6.

Commodity Derivatives

As of March 31, 2016, we have open crude oil and natural gas derivative contracts for a portion of our anticipated future production for the remainder of 2016.  These contracts were entered into during the second quarter of 2015.  The open oil derivative contracts are known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option.  These two-way collars provide price risk protection if crude oil prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits.  The oil contracts are based on WTI crude oil prices as quoted off the NYMEX.  The open natural gas derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices.  The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option.  These contracts may have the effect of reducing some of our incremental income from favorable price movements if the commodity price is above certain levels, but have unlimited upside potential if prices rise above those levels.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  The strike prices of both the oil and natural gas contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty.    

During the three months ended March 31, 2015, we did not have any open derivative contracts or any contracts that closed during the period.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

As of March 31, 2016, our open commodity derivative contracts were as follows:

The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as indicated in the following table (in thousands):

 

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

 

Cash receipts, net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows and were as follows (in thousands):

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Offsetting Commodity Derivatives

During 2016 and 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.  For the open derivative contracts as of March 31, 2016 and December 31, 2015, there would have been no difference if the contracts were presented on net basis.

5.  Long-Term Debt

Our long-term debt was as follows (in thousands):

 

8.5% Senior Notes

At March 31, 2016 and December 31, 2015, our outstanding senior notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019 (the “8.50% Senior Notes”), were classified as long-term at their carrying value.  Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums.  We are subject to various financial and other covenants under the indenture governing the 8.50% Senior Notes, and we were in compliance with those covenants as of March 31, 2016.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

9.00% Term Loan

At March 31, 2016 and December 31, 2015, our outstanding term loan, which bears an annual interest rate of 9.00% and matures on May 15, 2020 (the “9.00% Term Loan”), was classified as long-term at its carrying value.  Interest on the 9.00% Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the 9.00% Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts.  The 9.00% Term Loan is secured by a second priority lien covering our oil and gas properties to the extent such properties secure first priority liens granted to secure indebtedness under our Credit Agreement.  We are subject to various covenants under the terms governing the 9.00% Term Loan including, without limitation, covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities.  We were in compliance with those covenants as of March 31, 2016.  

Credit Agreement

The Credit Agreement provides a revolving bank credit facility.  Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders, and the Company and the lenders may each request one additional determination per year.  The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.  Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.  The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties.  The Credit Agreement terminates on November 8, 2018.

The Credit Agreement contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  These financial test ratios and limits as of March 31, 2016 and thereafter are: (i) the First Lien leverage Ratio must be less than 1.50 to 1.00; (ii) the Current Ratio must be greater than 1.00 to 1.00; and (iii) the Secured Debt Leverage Ratio must be less than 3.50 to 1.00.   As of March 31, 2016, our the First Lien Ratio was  1.48 to 1.00, the Current Ratio was 2.84 to 1.00 and the Secured Debt Leverage Ratio was 3.02 to 1.00.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the 8.50% Senior Notes and the 9.00% Term Loan, and these agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2016.

In February 2016, we borrowed $340.0 million under the Credit Agreement.  On March 23, 2016, the banks reduced our borrowing base to $150.0 million from $350.0 million in connection with the spring borrowing base redetermination.  We are required to repay borrowings outstanding in excess of the redetermined borrowing base pursuant to the terms of the Credit Agreement.  On March 31, 2016, we repaid $52.0 million leaving an outstanding balance under the Credit Agreement of $288.0 million as of March 31, 2016.  On May 2, 2016, we repaid an additional $12.0 million.  Additional payments are required of $64.0 million on May 31, 2016 and $64.0 million on June 30, 2016, in addition to interest payments on our long-term debt, which will bring total borrowings outstanding under the Credit Agreement in conformity with the borrowing base limitation.  The Company has sufficient available cash to make these payments.  The reduction in the borrowing base resulted in a proportional reduction in the unamortized costs related to the Credit Agreement of $1.4 million, which is included in the line Other (income) expense, net on the Condensed Statement of Operations.  

As of March 31, 2016 and December 31, 2015, we had $1.0 million and $0.9 million, respectively, of letters of credit outstanding under the revolving bank credit facility.  The estimated annual effective interest rate was 4.7% for the three months ended March 31, 2016 for average daily borrowings outstanding under the revolving bank credit facility.  The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.  

The foregoing description of the Credit Agreement does not purport to be complete and is qualified in its entirety by reference to the agreement.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

For information about fair value measurements for our 8.50% Senior Notes, 9.00% Term Loan and revolving bank credit facility, refer to Note 6.

6.  Fair Value Measurements  

We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads, credit risk and published commodity futures prices.  The fair values of our 8.50% Senior Notes and 9.00% Term Loan were based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2.  The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates.

The following table presents the fair value of our open derivatives and long-term debt, as reported in the Condensed Consolidated Balance Sheets (in thousands):

 

 

7.  Share-Based Compensation and Cash-Based Incentive Compensation

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders, and amendments to the Plan were approved by our shareholders in May 2013.  As allowed by the Plan, during 2015 and in 2014, the Company granted restricted stock units (“RSUs”) to certain of its employees. During the three months ended March 31, 2016, no RSUs were granted.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to typical adjustments at the end of the applicable performance period based on the achievement of certain predetermined criteria.  In addition to share-based compensation, the Company may grant to its employees cash-based incentive awards, which are a short-term component of the Plan and are typically based on the Company and the employee achieving certain pre-defined performance criteria.

During 2015, RSUs granted were subject to adjustments based on achievement of multiple performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2015 and (ii) Adjusted EBITDA as a percent of total revenues (“Adjusted EBITDA Margin”) for 2015.  For 2015, the Company was below target for Adjusted EBITDA and achieved the target for Adjusted EBITDA Margin.

During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i)  Adjusted EBITDA for 2014 and (ii) Adjusted EBITDA Margin for 2014.  For 2014, the Company achieved the target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

All RSUs  that are currently outstanding under the Plan are subject to employment-based criteria and vesting occurs in December of the second year after the grant.  For example, the RSUs granted during 2014, adjusted for 2014 performance described above, will vest in December 2016 to eligible employees assuming employment-based criteria are also satisfied.  

Under the Director Compensation Plan, shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during 2015, 2014 and 2013.  The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless approved by the Board.  

At March 31, 2016, there were 4,239,548 shares of common stock available for issuance in satisfaction of awards under the Plan and 444,024 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available for both plans are reduced when Restricted Shares or shares of common stock are granted.  RSUs reduce the shares available in the Plan when the RSUs are settled in shares of common stock, net of withholding tax.  Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date.

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant.  We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

Awards Based on Restricted Stock to Non-Employee Directors.  As of March 31, 2016, all of the unvested shares of Restricted Shares outstanding were issued to the non-employee directors.  Restricted Shares cannot be sold, transferred or disposed of during the restricted period.  The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such Restricted Shares, including the right to vote and receive dividends or other distributions paid with respect to the Restricted Shares.  The fair value of Restricted Shares was estimated by using the Company’s closing price on the grant date.

For the outstanding Restricted Shares issued to the non-employee directors as of March 31, 2016, vesting is expected to occur as follows:

 

There were no grants, forfeitures or vesting of Restricted Shares during the first quarter of 2016 or the first quarter of 2015.  

Awards Based on Restricted Stock Units.  As of March 31, 2016, the Company had outstanding RSUs issued to certain employees.  As described above, the RSUs granted during 2015 and 2014 were 100% performance based and were subject to pre-defined performance measures and employment-based criteria.  The fair values for the RSUs granted during 2015 and 2014 were determined using the Company’s closing price on the grant date.  

All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.  Dividend equivalents are earned at the same rate as dividends are paid on our common stock after achieving the specified performance requirement for that component of the RSUs.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

A summary of activity in 2016 related to RSUs is as follows:

 

For the outstanding RSUs issued to the eligible employees as of March 31, 2016, vesting is expected to occur as follows:  

 

 

  Share-Based Compensation.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

 

 

Unrecognized Share-Based Compensation.  As of March 31, 2016, unrecognized share-based compensation expense related to our awards of Restricted Shares and RSUs was $0.4 million and $10.3 million, respectively.  Unrecognized share-based compensation expense will be recognized through April 2018 for Restricted Shares and November 2017 for RSUs.

Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees and are typically payable in cash.  These awards are performance-based awards consisting of one or more business or individual performance criteria and a targeted level or levels of performance with respect to each such criterion.  Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.  

During 2015, the Company issued cash-based incentive awards for 2015 that, in addition to being performance-based awards related to 2015 criteria, the payment of such awards is contingent on the Company achieving the following financial condition on or before December 31, 2017:  Adjusted EBITDA less Interest Expense, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $300.0 million.  As the Company did not achieve this financial condition up through March 31, 2016, no amounts have been recognized to date related to the 2015 cash-based incentive awards.  Amounts recorded during the three months ended March 31, 2015 relate to the 2014 cash-based awards, for which costs were recognized from the award date through February 2015 (the service period), and adjustments were recorded to true up previous estimates to actual payments.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Share-Based Compensation and Cash-Based Incentive Compensation Expense.  A summary of incentive compensation expense is as follows (in thousands):  

 

 

8.  Income Taxes  

Our income tax benefit for the three months ended March 31, 2016 and 2015 was $4.9 million and $103.6 million, respectively.  Our annualized effective tax rate for the three months ended March 31, 2016 and 2015 was 2.5% and 28.9%, respectively.  Both of these percentages differ from the federal statutory rate of 35.0% primarily due to recording and adjusting a valuation allowance for our deferred tax assets.     

 During the three months ended March 31, 2016 and 2015, we recorded a valuation allowance of $60.0 million and $22.5 million, respectively, related to federal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  In addition, the realization depends on the ability to carryback certain items to prior years for refunds of taxes previously paid.  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.  As of March 31, 2016 and December 31, 2015, we had a valuation allowance related to Federal, Louisiana and Alabama net operating losses and other deferred taxes.  The tax years 2012 through 2015 remain open to examination by the tax jurisdictions to which we are subject.   

We recognize interest and penalties related to unrecognized tax benefits in income tax expense.  During the three months ended March 31, 2016 and 2015, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

9.  Earnings Per Share

The following table presents the calculation of basic and diluted loss per common share (in thousands, except per share amounts):

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

10.  Dividends

During the three months ended March 31, 2016 and the full year of 2015, we did not pay any dividends and a suspension of dividends remains in effect.    

 

11.  Contingencies

Supplemental Bonding Requirements by the BOEM.  The significant reductions in crude oil and natural gas pricing since the middle of 2014 have adversely impacted our financial strength and have resulted in our inability to meet the relevant financial strength and reliability criteria set forth in the BOEM Notice To Lessee #2008-N07, Supplemental Bond Procedures, (“NTL #2008-N07”).  Both W&T Offshore, Inc. and its subsidiary are now subject to supplemental bonding.  In February and March 2016, we received several orders from the BOEM demanding that we provide additional supplemental bonding on certain Federal offshore oil and gas leases, rights of way and rights of use and easement owned and/or operated by the Company.  One order was rescinded and re-issued and another one was rescinded.  The outstanding orders total approximately $260.8 million.  We have had discussions with the BOEM and its sister agency, the BSEE, since receiving the orders.  See Note 12 for information on events occurring subsequent to March 31, 2016 for this item.

The issuers of such surety bonds may request, and in some cases, have requested, collateral, which could be significant and could impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.    

Notification by ONRR of Fine for Non-compliance.  In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment.  We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment.  On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the notice.  We intend to contest the fine to the fullest extent possible.  A hearing on this matter is scheduled with an Administrative Law Judge on June 21, 2016 in Houston, Texas.  The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of March 31, 2016 or December 31, 2015.        

Apache Lawsuit.   On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement (“JOA”) related to deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  That lawsuit, styled Apache Corporation v. W&T Offshore, Inc., is currently pending in the United States District Court for the Southern District of Texas.  Apache contends that W&T has failed to pay its proportional share of the costs associated with plugging and abandoning three wells that are subject to the JOA.  We contend that the costs incurred by Apache are excessive and unreasonable.  Apache seeks an award of unspecified actual damages, interest, court costs, and attorneys’ fees.  In February 2015, we made a payment to Apache for our net share of the amounts that we believe are reasonable to plug and abandon the three wells.  Our estimate of the potential exposure ranges from zero to $32 million related to this matter, which excludes potential interest, court costs and attorneys’ fees. 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Insurance Claims.  During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (“Excess Policies”) (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company, National Liability & Fire Insurance Company (“Starr Marine”)  and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas (the “District Court”) seeking a determination that our Excess Policies do not cover removal-of-wreck and debris claims arising from Hurricane Ike except to the extent we have first exhausted the limits of our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm coverage) with only removal-of-wreck and debris claims.  The court consolidated the various suits filed by the underwriters.  In January 2013, we filed a motion for summary judgment seeking the court’s determination that such Excess Policies do not require us to exhaust the limits of our Energy Package policies with only removal-of-wreck and debris claims.  In July 2013, the District Court ruled in favor of the underwriters, adopting their position that the Excess Policies cover removal-of-wreck and debris claims only to the extent the limits of our Energy Package policies have been exhausted with removal-of-wreck and debris claims.  We appealed the decision in the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and, in June 2014, the Fifth Circuit reversed the District Court’s ruling and ruled in our favor.  The underwriters filed three separate briefs requesting a rehearing or a certification to the Texas Supreme Court, all of which the Court denied.  A brief was subsequently filed by one underwriter requesting a rehearing to the District Court of the Fifth Circuit’s decision, which the District Court denied.  Claims of approximately $43 million were filed, of which approximately $1 million was paid under the Energy Package and of which approximately $1 million was paid under our Comprehensive General Liability policy.  One of the underwriters, Liberty Mutual Insurance Co., paid its portion of the settlement (approximately $5 million), in addition to a portion of interest owed.  The other underwriters have not paid, and we filed a lawsuit in September 2014 against these underwriters for amounts owed, interest, attorney fees and damages.  Subsequent to the filing of that lawsuit, Liberty Mutual Insurance Co. paid additional interest and Starr Marine has paid its portion ($5 million) of the first excess liability policy without interest.  The lawsuit includes interest not paid by Starr Marine. The revised estimate of potential reimbursement is approximately $31 million, plus interest, attorney fees and damages, if any.  Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Condensed Consolidated Balance Sheets and recoveries from claims made on these Excess Policies will be recorded as reductions in this line item, which will reduce our future depreciation, depletion, amortization and accretion (“DD&A”) rate.

Royalties.  In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the IBLA.  W&T’s brief was filed in November 2014 and we expect the briefing before the IBLA to be completed in 2016.

The ONRR has publicly announced an “unbundling” initiative to review the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  In the second quarter of 2015, pursuant to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that is processed through a specific processing plant.  The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases.  The Company intends to submit a response to the preliminary determination asserting the reasonableness of its own allocation methodology of such costs.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods.  The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Notices of Proposed Civil Penalty Assessment.  The Company currently has three open Incidents of Noncompliance (“INCs”) issued by the BSEE, which have not been settled as of the filing of this Form 10-Q.  The INC’s were issued during 2015 and relate to three separate offshore locations with occurrence dates ranging from July 2012 to June 2014.  The proposed civil penalties for these INCs total $7.1 million.  The Company has accrued approximately $1.0 million, which is the Company’s best estimate of the final settlement once all appeals have been exhausted.  The Company’s position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.      

Iberville School Board Lawsuit.  In August, 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against the Company (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that this property has allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities.  The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  We cannot currently estimate our potential exposure, if any, related to this lawsuit.  We are currently, and intend to continue, vigorously defending this litigation.

Other Claims.  We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business.  In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties.  In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold.  In addition, the BOEM considers all owners of record title and/or operating rights interest in an Outer Continental Shelf (“OCS”) lease to be jointly and severally liable for the satisfaction of the supplemental bonding obligations and/or decommissioning obligations.  Accordingly, we may be required to satisfy supplemental bonding obligations or decommissioning obligations of a defaulting owner of record title and/or operating rights interest in an OCS lease in which we are (or in some cases were) an owner of record title and/or operating rights interest in the same OCS lease.  We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties.  Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

Contingent Liability Recorded.  There were no material expenses recognized related to accrued and settled claims, complaints and fines for the three months ended March 31, 2016 and 2015.  As of March 31, 2016 and December 31, 2015, we had no material amounts recorded in liabilities for claims, complaints and fines.  

 

12.  Subsequent Events  

Supplemental Bonding Requirements by the BOEM.  Subsequent to March 31, 2016, we have filed appeals with the IBLA regarding three of the BOEM orders - specifically the February order that required W&T to post a total of $159.8 million in supplemental bonding and two March orders requiring $68.0 million in supplemental bonding.  The objective of the Company remains to reach a mutual agreement on the financial assurance requirements of the demands.  The issuance of any additional surety bonds to satisfy the BOEM orders or any future BOEM orders may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  We continue to have discussions with the BOEM regarding these matters.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

13.  Supplemental Guarantor Information

Our payment obligations under the 8.50% Senior Notes, the 9.00% Term Loan and the Credit Agreement (see Note 5) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including:  

(1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale or other disposition does not violate the Asset Sales provisions (as such terms are define in certain debt documents);

(2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of certain debt documents;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in certain debt documents) or upon satisfaction and discharge of the certain debt documents;

(5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary as described in certain debt documents, provided no event of default has occurred and is continuing.

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  Transfers of property were made from the Parent Company to the Guarantor Subsidiaries.  As these transfers were transactions between entities under common control, the prior period financial information has been retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance.  None of the adjustments had any effect on the consolidated results for the current or prior periods presented.  

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Condensed Consolidating Balance Sheet as of March 31, 2016

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Balance Sheet as of December 31, 2015

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Statement of Operations for the Three Months Ended March 31, 2016

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Condensed Consolidating Statement of Operations for the Three Months Ended March 31, 2015

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2016

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2015

 

 

 

 

 

 

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q.  The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (“the “Exchange Act”), which involve risks, uncertainties and assumptions.  If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, 2015 and may be discussed or updated from time to time in subsequent reports filed with the SEC.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend to update these forward-looking statements.  Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries and references to “Parent Company” are solely to W&T Offshore, Inc.

Overview

We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 54 offshore fields in federal and state waters (50 producing and four fields capable of producing).  We currently have under lease approximately 850,000 gross acres, with approximately 500,000 gross acres on the shelf and approximately 350,000 gross acres in the deepwater.  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC.  

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the first quarter of 2016 were comprised of 48.3% oil and condensate, 9.1% NGLs and 42.6% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one barrel oil equivalent (“Boe”) for oil, NGLs and natural gas has differed significantly from time to time.  In the first quarter of 2016, revenues from the sale of oil and NGLs made up 72.0% of our total revenues compared to 69.6% for the first quarter of 2015.  For the first quarter of 2016, our combined total production was 10.3% lower than the first quarter of 2015 due to lower NGLs and natural gas production.  For the first quarter of 2016, our total revenues were 39.2% lower than the first quarter of 2015 due primarily to significantly lower realized prices for oil, NGLs and natural gas.  See Results of Operations – Three months ended March 31, 2016 Compared to the Three Months ended March 31, 2015 in this Item for additional information on our revenues and production.

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On October 15, 2015, we sold our interests in the Yellow Rose onshore field in the Permian Basin to Ajax.  Our interest in the field covered approximately 25,800 net acres.  During the first quarter of 2015, the Yellow Rose field accounted for approximately 7% of our production and revenues.  In connection with the sale, we retained a non-expense bearing ORRI in production from the working interests sold, which percentage varies on a sliding scale from one percent for each month that the NYMEX prompt month contract trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  Internal estimates of proved reserves at the date of the sale were 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas.  Including adjustments from an effective date of January 1, 2015, the adjusted sales price was $370.8 million of cash and the buyer assumed the ARO associated with our interests in the Yellow Rose field, which we had estimated at $6.9 million at the time of the sale, and the buyer assumed other liabilities of $1.1 million.  We used a portion of the proceeds of the sale to repay all the outstanding borrowings under our revolving bank credit facility, while the remaining balance of approximately $98 million was added to available cash.  

Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  Beginning in the second half of 2014 and continuing through the first quarter of 2016, crude oil prices have fallen dramatically from a peak of over $100 per barrel for WTI in June 2014.  In addition, prices of NGLs and natural gas have fallen significantly from 2014 levels.  The current market imbalance is predominantly supply driven caused by a number of issues that are described below:

The U.S. Energy Information Administration (“EIA”) estimates the worldwide crude oil and petroleum liquids supply will exceed demand in 2016, resulting in crude oil and other petroleum liquids inventories increasing by 1.4 million barrels per day.  The estimate of inventory build for 2016 has been increased from the previous estimate of 0.7 million barrels per day.  In addition, the inventory build for 2015 was revised upwards from 1.9 million barrels per day to 2.1 million barrels per day.  EIA estimates inventory builds in each quarter of 2016 and the first half of 2017, and forecasts the first inventory withdraw occurring in the third quarter of 2017.         Comparing the first quarter of 2016 to the first quarter of 2015, worldwide supply increased by 0.9 million barrels per day, primarily due to increases from OPEC, while U.S. and Canada supply was basically flat between the two quarters.  EIA’s estimate for 2016 has supply increasing over 2015 by 0.5 million barrels per day, with Iran accounting for most of the increase and partially offset by decreases in the U.S. and the North Sea.  EIA’s forecast for supply from OPEC does not assume any production cuts from collaborative agreements.  EIA’s estimate has consumption increasing in 2016 over 2015 by 1.2 million barrels per day, with the increases coming primarily from China and other Asian countries.  Downside risk was noted for China as their economic growth may be less than expected.

While many U.S. producers reduced capital in 2015 compared to 2014 and have further reduced capital budgets for 2016, the impact of reduced drilling did not reduce overall oil and other liquids production in the U.S. for the first quarter of 2016, as production was basically flat from the first quarter of 2015.  Per EIA’s estimates, U.S. oil production will decrease in the second quarter of 2016 compared to the first quarter of 2016 and will continue to decrease throughout the remainder of 2016.  U.S. oil production for the balance of 2016 is estimated to be lower than the respective prior year quarters by 0.5 to 1.0 million barrels per day.  

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During the first quarter of 2016, our average realized oil sales price was $26.73, down from $43.04 per barrel (37.9% lower) for the first quarter of 2015.  The two primary benchmarks reported upon are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $33.35 per barrel for the first quarter of 2016, down from $48.49 per barrel (31.2% lower) for the first quarter of 2015.  Brent crude average oil prices decreased to $33.84 per barrel for the first quarter of 2016, down from $53.98 per barrel (37.3% lower) for the first quarter of 2015.  Our average realized oil sales price or the first quarter of 2016 differs from the benchmark crude prices due to premiums or discounts (referred to as differentials), volume weighting and other factors.  All of our oil for the first quarter of 2016 was produced offshore in the Gulf of Mexico and is characterized as Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Just like crude oil prices, the differentials for our offshore crude oil have also experienced volatility.  For example, the monthly average differentials of WTI versus LLS, HLS and Poseidon for the first quarter of 2016 were a positive $1.60 and $0.80, and a negative $3.71 per barrel, respectively, compared to positive $2.60 and $1.42, and a negative $2.14 per barrel, respectively, for the first quarter of 2015.  The majority of our crude oil is priced similar to Poseidon and, therefore, is experiencing negative differentials.  In addition, a few of our crude oil fields have a negative quality bank adjustment and production from two of our crude oil fields is being transported via barge, which is more expensive than pipeline transportation.

EIA projects average crude oil prices for WTI and Brent to decrease for the year 2016 over 2015 by approximately $14.00 per barrel and $18.00 per barrel, respectively, and to increase in 2017 by approximately $6.00 per barrel for each.  One factor identified by EIA that could cause crude oil prices to deviate significantly from their projections is capacity of global oil storage (which is unknown) to absorb the continuing inventory builds.  If the cost of storage increases due to using marginal storage options such as oil tankers, crude oil prices could experience downward pressure.  Other factors noted that may have a significant impact on future crude oil prices include the pace of economic growth and unplanned supply disruptions.  In addition, the strength in the U.S. dollar relative to other currencies also has an impact on crude pricing.  Because all barrels are traded in U.S. dollars, as the U.S. dollar gains strength, crude prices are lower in U.S. dollars but are more expensive in other currencies.

During the first quarter of 2016, our average realized NGLs sales price decreased 17.0% compared to the first quarter of 2015.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During the first quarter of 2016, average prices for domestic ethane decreased 14% and average domestic propane prices decreased 28% from the first quarter of 2015.  Average price decreases for other domestic NGLs were 22% to 30%.  The price changes were reflective of the price changes for crude oil and natural gas.  Per EIA, production of ethane and propane increased in the first quarter of 2016 over the first quarter of 2015 by 14% and 7%, respectively.  Ethane and propane inventory levels for the first quarter of 2016 were higher than the comparable quarter in 2015.  The number of heating degree days for the winter of 2016 were lower than the prior year, which contributed to the higher propane inventory levels.  As long as U.S. crude oil and natural gas production remain high and the price ratio of crude oil to natural gas remains wide (as measured on a six to one energy equivalency), the production of NGLs may continue to be high relative to historical norms, which would in turn suggest continued weak prices, or possibly further price reductions, especially for the prices of ethane and propane.  Many natural gas processing facilities have been and will likely continue re-injecting ethane back into the natural gas stream after processing due to insufficient ethane demand, which negatively impacts production and natural gas prices.  Once propane is extracted from the natural gas stream, it is not re-injected and is sold as a separate component.  As propane inventories build with no offsetting increase in demand, propane prices are expected to continue to be weak or weaken further.

During the first quarter of 2016, our average realized natural gas sales price decreased 33.2% compared to the first quarter of 2015.  According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 31.4% lower in the first quarter of 2016 from the first quarter of 2015.  Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation.   However, with the surplus of natural gas that has plagued the industry since 2012, natural gas prices have been weak and the fluctuations in prices have been limited to the lower end of the price range.  Heating degree days for the first quarter of 2016 were 18% lower than the first quarter of 2015, which has a direct impact on demand for natural gas.  The U.S. natural gas inventories at the end of March 2016 were slightly above the previous end-of-March record high set in 2012 and were 67% higher than the same period last year.  U.S. consumption decreased in the first quarter of 2016 compared to the first quarter of 2015 by 6%, which was basically the same percentage decrease for production.  Consumption decreases came from lower residential and commercial usage and partially offset by higher electric power usage.  

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The average price of natural gas continues to be weak from an overall economic standpoint, and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers may continue to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas continuing to be produced as a by-product of oil drilling,  (iii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iv) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply.

EIA projects natural gas prices to decrease for the year 2016 to $2.25 per Mcf compared to $2.71 per Mcf in 2015.  U.S. production is projected to be higher in 2016 compared to 2015 by 1% despite the decrease in drilling activity.  Natural gas usage for power generation is expected to remain in the 33%-34% range for 2016 and 2017, which is approximately equivalent to 2015 due to lower natural gas prices compared to coal and new Federal regulations related to coal usage.  

During the first quarter of 2016, the number of rigs drilling for oil and natural gas in the U.S. is significantly below 2014 levels due to lower crude oil and natural gas prices.  According to Baker Hughes, the oil rig count at December 2014, December 2015 and March 2016 was 1,482, 536 and 362, respectively.  The number of rigs drilling for oil as of March 2016 was a seven-year low.  The U.S. natural gas rig count at December 2014, December 2015 and March 2016 was 328, 162 and 88, respectively. The U.S. natural gas rig count as of March 2016 was a 29-year low (the extent of data provided by Baker Hughes).  In the Gulf of Mexico, there were 54 rigs (42 oil and 12 natural gas) at the end of 2014; 25 rigs (20 oil and five natural gas) as of the end of 2015; and 24 rigs (19 oil and five natural gas) as of March 2016.  The majority of working rigs in the Gulf of Mexico are currently “floaters” with very few jack-up rigs working.

As required by the full cost accounting rules, we perform our ceiling test calculation each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials.  The average price using the SEC required methodology at March 31, 2016 was $42.77 per barrel for WTI crude oil and $2.40 per MMBtu for Henry Hub natural gas before adjustments.  Due to the decrease in the 12-month average price for both crude oil and natural gas, we recorded ceiling test write-downs of the carrying value of our oil and natural gas properties in the first quarter of 2016 of $116.6 million.  For the first quarter and full year of 2015, the ceiling test write-downs were $260.4 million and $987.2 million, respectively.  Incurrence of further write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs.

At this time, we expect to incur a further ceiling test impairment write-down in the second quarter of 2016 assuming commodities prices do not increase dramatically.  While it is difficult to project future impairment write-downs in light of numerous variables involved, the following price sensitivity calculation using basic assumptions is provided to illustrate the impact of lower commodities pricing on impairment charges and proved reserves volumes.  Assuming pro-forma 12-month average prices were determined by using the April 1, 2016 and May 1, 2016 benchmark commodities prices of $33.25 and $42.50 per barrel for WTI crude oil and $1.93 and $1.91 per MMBtu for Henry Hub natural gas, respectively, (before adjustments).  Then also assume May 1, 2016 prices are used as a proxy for June 1, 2016 prices and removing the second quarter 2015 prices from the 12-month average, we calculated that the benchmark 12-month average prices would decrease to $39.38 per barrel for WTI crude oil and $2.22 per MMBtu for Henry Hub natural gas (before adjustments).  If such pro-forma pricing was used in our ceiling test calculation as of March 31, 2016, and assuming no other changes, our ceiling test impairment write-down for the first quarter of 2016 would have increased by $106.2 million to $222.8 million

Using pro forma 12-month average commodity prices computed as described in the previous paragraph, our proved reserves would have decreased by approximately 3.1 MMBoe.  This is as a result of removing 27% of our proved undeveloped reserves due to the lack of economic viability at such prices, and reductions at some fields due to shortened time horizons.  The foregoing calculation was made without regard to additions or other further revisions to proved reserves estimated at March 31, 2016 other than as a result of such pricing changes.

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In February 2016, we borrowed $340 million under the Credit Agreement.  On March 23, 2016, the banks reduced our borrowing base to $150 million from $350 million in connection with the spring borrowing base redetermination.  We are required to repay borrowings outstanding in excess of the redetermined borrowing base pursuant to the terms of the Credit Agreement.  On March 31, 2016, we repaid $52 million leaving an outstanding balance under the Credit Agreement of $288 million as of March 31, 2016.  In addition, we had approximately $1 million of letters of credit outstanding as of March 31, 2016.  On May 2, 2016, we repaid an additional $12 million.  Additional payments are required of $64 million on May 30, 2016 and $64 million on June 30, 2016, in addition to interest payments on our long-term debt, which will bring total borrowings outstanding under the Credit Agreement in conformity with the borrowing base limitation.  See Financial Statements – Note 5 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

The significant reductions in crude oil and natural gas pricing commencing in the second half 2014 have adversely impacted the Company’s financial strength and have resulted in the Company’s inability to meet the relevant financial strength and reliability criteria set forth in the NTL #2008-N07.  Prior to 2015, we were partially exempt from providing such financial assurances under our corporate structure.  Currently, substantially all of our operations are subject to supplemental bonding.  In February and March 2016, we received several orders from the BOEM demanding that we provide additional supplemental bonding on certain Federal offshore oil and gas leases, rights of way and rights of use and easement owned and/or operated by the Company.  One order was rescinded and re-issued and another one was rescinded.  The outstanding orders total approximately $261 million.  We have filed appeals with the IBLA regarding three of the BOEM orders - specifically the February order that required W&T to post a total of approximately $160 million in supplemental bonding and two March orders requiring approximately $68 million in supplemental bonding.  We have had discussions with the BOEM and its sister agency, the BSEE, since receiving the orders.  The objective of the Company remains to reach a mutual agreement on the financial assurance requirements.  The issuance of any additional surety bonds to satisfy the BOEM orders or any future BOEM orders may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  We continue to have discussions with the BOEM regarding these matters.  See our Annual Report on Form 10-K for the year ended December 31, 2015, Item 1A, Risk Factors, for additional information.

Due to the continued deterioration of commodity prices and the outlook for the remainder of 2016, we have set our 2016 capital expenditure budget at $15 million.  This is a significant reduction from our 2015 and 2014 incurred capital expenditures of $231 million and $630 million, respectively.  We have the flexibility to make this reduction to our 2016 capital expenditure budget because we have no long term rig commitments and no pressure from partners to drill or complete a well.  Moreover, we expect our deepwater projects completed in 2015, combined with new production from our Ewing Bank 910 A-8 well, will help with 2016 production levels.  However, unplanned downtime, pipeline maintenance, and well performance are factors leading to lower estimated production in 2016 from 2015.  We do not expect to lose drilling opportunities at this spending level and have no significant lease expiration issues in 2016.  In addition, our plans include spending $76 million in 2016 for ARO, which is an increase from $33 million spent on ARO in 2015.  

On the cost side, we have seen relatively significant reductions in our lease operating expenses as a result of our cost reduction programs combined with reduced rates from vendors for supplies, equipment and contract labor.  These cost reduction programs and reduced supplier rates have also lowered capital expenditures, ARO settlements and ARO estimates.  

Our short-term focus is on conserving capital and maintaining liquidity.  In light of our limited access to capital and liquidity, we are not pursuing any significant acquisitions at this time.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans. See our Annual Report on Form 10-K for the year ended December 31, 2015, Item 1A, Risk Factors, for additional information.  

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Results of Operations

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

 

NM – not meaningful

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The Company drilled onshore wells during 2015, which were included with the sale of the Yellow Rose field in October 2015 and were excluded in the table above as the Company has sold, relinquished or let expire essentially all onshore leasehold interest.  

Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015

Revenues.  Total revenues decreased $50.2 million, or 39.2%, to $77.7 million for the first quarter of 2016 as compared to the first quarter of 2015.  Oil revenues decreased $30.6 million, or 37.5%, NGLs revenues decreased $2.5 million, or 32.9%, natural gas revenues decreased $16.9 million, or 45.5% and other revenues decreased $0.2 million.  The decrease in oil revenues was attributable to a 37.9% decrease in the average realized sales price to $26.73 per barrel for the first quarter of 2016 from $43.04 per barrel for the first quarter of 2015, with sales volumes up slightly.  The decrease in NGLs revenues was attributable to a 17.0% decrease in the average realized sales price to $13.96 per barrel for the first quarter of 2016 from $16.81 per barrel for the first quarter of 2015 and a decrease of 19.2% in sales volumes.  The decrease in natural gas revenues resulted from a 33.2% decrease in the average realized natural gas sales price to $2.01 per Mcf for the first quarter of 2016 from $3.01 per Mcf for the first quarter of 2015 and from a decrease of 18.4% in sales volumes.  Overall, production declined 10.3% on a BOE basis.  We experienced increases in production at the Mississippi Canyon 698 field (Big Bend) and the Mississippi Canyon 782 field (Dantzler), which began production in the fourth quarter of 2015.  Also, production increases were achieved at the Mississippi Canyon 582 field (Medusa), the Main Pass 108 field and the Brazos A-133 field.  Offsetting were production declines primarily from the sale of the Yellow Rose field; decreases at Ship Shoal 349 (Mahogany) due primarily to pipeline and operational issues; natural production declines at Mississippi Canyon 243 (Matterhorn), Garden Banks 302 (Power Play), Mississippi Canyon 506 (Wrigley), Viosca Knoll 783 (Tahoe) and Garden Banks 293 (Pyrenees) and other fields; and production deferrals affecting various fields.  Production deferrals, which occurred at multiple locations, were attributable to third-party pipeline outages, operational issues, and maintenance.  We estimate production deferrals were 0.8 million barrels of oil equivalent (“MMBoe”) during the first quarter of 2016 compared to 0.5 million MMBoe for the first quarter of 2015.

Revenues from oil and liquids as a percent of our total revenues were 72.0% for the first quarter of 2016 compared to 69.6% for the first quarter of 2015.  Our average realized NGLs sales price as a percent of our average realized oil sales price increased to 52.2% for the first quarter of 2016 compared to 39.1% for the first quarter of 2015.    

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $8.9 million, or 16.6%, to $44.5 million in the first quarter 2016 compared to the first quarter of 2015.  On a per Boe basis, lease operating expenses decreased to $11.28 per Boe during the first quarter of 2016 compared to $12.13 per Boe during the first quarter of 2015.  On a component basis, base lease operating expenses decreased $5.2 million, workover expense decreased $1.9 million and insurance premiums decreased $1.6 million.  Base lease operating expenses decreased primarily due to lower costs from service providers and the sale of the Yellow Rose field; partially offset by lower production handling fees (cost offsets) at our Matterhorn field and increases in expenses related to our new deepwater fields at Dantzler and Big Bend.  The decrease in workover costs was primarily due to the sale of the Yellow Rose field.  

Production taxes.  Production taxes decreased $0.1 million to $0.5 million for the first quarter of 2016 compared to the first quarter of 2015.  Most of our production is from federal waters where no production taxes are imposed.  Our Fairway field, which is in state waters, is subject to production taxes.

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Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, decreased to $16.17 per Boe for the first quarter of 2016 from $28.55 per Boe for the first quarter of 2015.  On a nominal basis, DD&A decreased to $63.7 million, or 49.2%, for the first quarter of 2016 from $125.5 million for the first quarter of 2015.  DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2015 (the first quarter 2016 ceiling test write-down will not affect the DD&A rate until the second quarter of 2016) and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A.  In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field reserves.  Other factors affecting the DD&A rate are lower future development costs on remaining reserves and lower proved reserves volumes.    

Ceiling test write-down of oil and natural gas properties. For the first quarter of 2016, we recorded a non-cash ceiling test write-down of $116.6 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down is the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas.  For the first quarter of 2015, the ceiling test write-down was $260.4 million.  See Financial Statements and Supplementary Data – Note 1 - Basis of Presentation under Part I, Item 1 of this Form 10-Q, which provides a description of the ceiling test limit determination, and above under the section Overview in this Item regarding our prospects for a future significant ceiling test write-down and a price sensitivity computation.  

General and administrative expenses (“G&A”).  G&A decreased to $16.4 million, or 20.8%, for the first quarter of 2016 from $20.8 million for the first quarter of 2015 primarily due to decreases in headcount related expense (salaries, benefits, and contractor expenses) and costs related to surety bonds (due to timing), partially offset by higher legal and professional services costs and higher medical claims.  G&A on a per BOE basis was $4.17 per Boe for the first quarter of 2016 compared to $4.72 per Boe for the first quarter of 2015.

Derivative gain. For the first quarter of 2016, there was a $2.5 million net derivative gain recorded for derivative contracts for crude oil and natural gas.  We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production.  For the first quarter of 2015, there were no derivative contracts.  

Interest expense.  Interest expense incurred was $27.8 million in the first quarter of 2016, up from $22.9 million in the first quarter of 2015.  The increase was primarily attributable to increased borrowings on the revolving bank credit facility and the issuance of the 9.00% Term Loan in May 2015 with an aggregate principal of $300.0 million.  The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million in both periods.  During the first quarter of 2016 and 2015, $0.3 million and $1.8 million, respectively, of interest costs were capitalized related to unevaluated oil and natural gas properties.  The decrease is primarily attributable to the sale of the Yellow Rose field in the fourth quarter of 2015 and reclassifying certain unevaluated properties to the full cost pool during the first quarter of 2016 and the full year of 2015.  

Other (income) expense, net.  Effective in March 2016, the borrowing base on the revolving bank credit facility was redetermined and reduced to $150.0 million from $350.0 million.  The reductions in the borrowing base resulted in a proportional reduction of $1.4 million in the unamortized debt issuance costs related to the revolving bank credit facility.  

Income tax benefit. Our income tax benefit for the first quarter of 2016 and 2015 was $4.9 million and $103.6 million, respectively, with the change attributable primarily to changes in the pre-tax loss and changes in the valuation allowance recorded for the respective periods.  Our annualized effective tax rate for the first quarter of 2016 and 2015 was 2.5% and 28.9%, respectively, and differs from the federal statutory rate of 35% primarily due to recording and adjusting a valuation allowance related to federal and state deferred tax assets.  During the three months ended March 31, 2016 and 2015, we recorded valuation allowances of $60.0 million and $22.5 million, respectively, related to federal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  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. 

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Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our asset retirement obligations.  We have funded such activities with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.  These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.

Due to the decline of commodity prices that commenced in the second half of 2014, we expect our future revenues, earnings, liquidity and ability to invest in future reserve growth to continue to be negatively impacted.  Other potential negative impacts of such price weakness include:

As a result of the potential for these events, we have engaged legal and financial advisors to assist the Board of Directors and our management team to evaluate the various alternatives available to us, which may include, among other things, securities offerings and other financing activities, joint ventures and sales of properties.  We may also from time to time seek to retire or purchase our outstanding debt through open market or privately negotiated cash purchases or exchange our existing debt for equity securities or debt securities or term loans, which may be secured by a lien on our assets.  Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.  The amounts involved may be material.  However, no assurances can be given that any of these alternatives will be available in 2016 or in future years.  

In addition, these events could impact our ability to comply with the covenants under our Credit Agreement or other debt instruments, which would force us to engage the lenders or bondholders in discussions regarding further amendments or covenant relief.  We may have to reduce future cash outlays for capital expenditures and other activities until such time as operating margins improve sufficiently and market conditions recover or stabilize.  Realization of any of these events would depend on the longevity and severity of such price weakness.

In February 2016, we borrowed $340 million under the Credit Agreement.  On March 23, 2016, the banks reduced our borrowing base to $150 million from $350 million in connection with the spring borrowing base redetermination.  We are required to repay borrowings outstanding in excess of the redetermined borrowing base pursuant to the terms of the Credit Agreement.  On March 31, 2016, we repaid $52 million leaving an outstanding balance under the Credit Agreement of $288 million as of March 31, 2016.  In addition, we had approximately $1 million of letters of credit outstanding as of March 31, 2016.  On May 2, 2016, we repaid an additional $12 million.  Additional payments are required of $64 million on May 30, 2016 and $64 million on June 30, 2016, in addition to interest payments on our long-term debt, which will bring total borrowings outstanding under the Credit Agreement in conformity with the borrowing base limitation.  See Financial Statements – Note 5 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

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In February and March 2016, we received several orders from the BOEM demanding that we provide additional supplemental bonding on certain Federal offshore oil and gas leases, rights of way and rights of use and easement owned and/or operated by the Company.  One order was rescinded and re-issued and another one was rescinded.  The outstanding orders total approximately $261 million.  We have filed appeals with the IBLA regarding three of the BOEM orders - specifically the February order that required W&T to post a total of approximately $160 million in supplemental bonding and two March orders requiring approximately $68 million in supplemental bonding.  We have had discussions with the BOEM and its sister agency, the BSEE, since receiving the orders.  The objective of the Company remains to reach a mutual agreement on the financial assurance requirements.  The issuance of any additional surety bonds to satisfy the BOEM orders or any future BOEM orders may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  We continue to have discussions with the BOEM regarding these matters.  See our Annual Report on Form 10-K for the year ended December 31, 2015, Item 1A, Risk Factors, for additional information.  

Cash Flow and Working Capital.  Net cash provided by operating activities for the first quarter of 2016 and 2015 was $29.7 million and $52.9 million, respectively.  Cash flows from operating activities, before changes in working capital and ARO settlements, were a negative $9.3 million in the first quarter of 2016, a decrease of $39.5 million compared to the $30.2 million generated during the first quarter of 2015.  The change in cash flows excluding working capital and ARO settlements was primarily due to lower realized prices for all our commodities - oil, NGLs and natural gas and lower production volumes, partially offset by lower operating expenses.  Our combined average realized sales price per Boe decreased 32.6%, which lowered revenues $42.1 million.  Combined volumes on a Boe basis decreased 10.3%, which lowered revenues by $7.8 million.  

The changes in working capital and ARO settlements increased operating cash flows by $39.0 million and $22.8 million in the first quarter of 2016 and 2015, respectively, resulting in a difference of $16.2 million.  The 9.00% Term Loan was issued in May 2015, which increased accrued interest between the two periods.  In addition, settlements of ARO liabilities were lower in the first quarter of 2016 compared to the first quarter of 2015.  

Net cash used in investing activities during the first quarter of 2016 and 2015 was $32.6 million and $135.2 million, respectively, which represents our investments in oil and gas properties and equipment.  There were no acquisitions of significance during the first quarter of 2016 and 2015.  Investments in oil and natural gas properties on an accrual basis in the first quarter of 2016 were $12.9 million compared to $82.8 million in the first quarter of 2015.  The majority of expenditures during the first quarter of 2016 related to investments in the deepwater.  In addition, adjustments from working capital changes associated with investing activities used net cash of $20.7 million in the first quarter of 2016 compared to net cash usage of $52.2 million in the first quarter of 2015.    

Net cash provided by financing activities for the first quarter of 2016 and 2015 was $288.1 million and $67.0 million, respectively.  The net cash provided for the first quarter of 2016 and 2015 was attributable to borrowings on the revolving bank credit facility.  

Credit Agreement and Long-Term Debt.  At March 31, 2016, $288.0 million was outstanding under our revolving bank credit facility.  At December 31, 2015, we did not have any borrowings outstanding on the revolving bank credit facility.  During the first quarter of 2016, the outstanding borrowings on the revolving bank credit facility ranged from zero to $340.0 million.  At March 31, 2016 and December 31, 2015, $900.0 million in aggregate principal amount of our 8.50% Senior Notes and $300.0 million in aggregate principal amount of our 9.00% Term Loan were outstanding.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  The spring redetermination occurred in March 2016, which is discussed above.  The lenders and the Company have the option for an additional redetermination every year.  The Credit Agreement contains financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement, the 8.50% Senior Notes and the 9.00% Term Loan as of March 31, 2016.  See Financial Statements - Note 5 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.  

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Derivative Financial Instruments.  From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility.  As of March 31, 2016, we had outstanding open derivatives for crude oil and natural gas.  These derivatives provide downside protection against a portion of our remaining 2016 production and will provide cash inflows when crude oil or natural gas prices average below $40.00 per barrel and $2.25 per MMBtu, respectively, in a month.  See Financial Statements - Note 4 - Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Insurance Claims and Insurance Coverage.  During 2008, Hurricane Ike caused substantial property damage.  Substantially all the costs related to Hurricane Ike have been incurred and we submitted claims under our insurance policies effective at that time, of which $161.2 million has been collected through December 31, 2015.  In June 2014, the Fifth Circuit reversed a lower court’s ruling in holding that our Excess Policies cover removal-of-wreck and debris claims arising from Hurricane Ike, even though we exhausted the limits of our Energy Package with non-removal-of-wreck and debris claim.  Several of the underwriters have not paid us amounts we claim are due under such Excess Policies in accordance with the Fifth Circuit ruling.  We filed a lawsuit in September 2014 against certain underwriters for amounts owed, interest, attorney fees and damages.  We subsequently received reimbursement from certain underwriters of the Excess Policies of approximately $10 million.  We believe we are still owed additional reimbursement of removal-of-wreck costs of approximately $31 million, plus interest, attorney fees and damages, if any.  Given the Fifth Circuit’s ruling, we expect to be reimbursed and compensated for all these costs, interest, fees and damages.  See Financial Statements - Note 11 - Contingencies under Part I, Item 1 of this Form 10-Q for additional information.

We currently carry multiple layers of insurance coverage in our Energy Package covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.  We have $75.0 million of named windstorm (hurricane and tropical storm) coverage for certain of our offshore properties and wells and an additional $75.0 million for certain properties and wells at our higher value fields.  We have $50.0 million of named windstorm coverage for our lower value offshore properties for the cost of removal in excess of scheduled ARO amounts.  The well control, named windstorm and physical damage coverage is effective until June 1, 2016.  A per-occurrence retention amount of $30.0 million for named windstorm events must be satisfied by us before our insurers will indemnify us for losses and we co-insure 15% of our named windstorm coverage.  The risk exposure varies per property and we have exposure for applicable retentions, co-insurance amounts and coverage limits. We also have other smaller per-occurrence retention amounts for various other events. Coverage for pollution causing a negative environmental impact is provided under the well control and named windstorm sections of the policy.

Our general and excess liability policies are effective until May 1, 2017 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE.  

Although we were able to renew our general and excess liability policies, and Energy Package in May 2016 and June of 2015, respectively, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims.  However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims.  We do not carry business interruption insurance.

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Capital Expenditures.  The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  The following table presents our capital expenditures on an accrual basis for exploration, development and other leasehold costs and acquisitions:

 

The following table presents our exploration and development capital expenditures on an accrual basis geographically:

 

Our capital expenditures for the first quarter of 2016 were financed by cash flow from operating activities, sales of properties, borrowings on our revolving bank credit facility and cash on hand.  

The following table presents our offshore wells drilled based on a completed basis:

The Company drilled onshore wells during 2015, which were included with the sale of the Yellow Rose field in October 2015 and were excluded in the table above as the Company has sold, relinquished or let expire essentially all onshore leasehold interest.  

Exploration Activities.  During the first quarter of 2016, the Ewing Bank 954 A-8 exploration well, which is part of the Ewing Bank 910 field, was completed and began producing on March 1, 2016.   Subsequent to March 31, 2016, we had no wells being drilled.  In 2015, we had one offshore well where drilling was deferred and the rig continues to be stacked on location.  

Divestitures.  Periodically, we sell properties as part of the management of our property portfolio.  As previously discussed, in 2015 we sold our interest in the Yellow Rose field for $370.8 million cash after adjustments, reduced related ARO for $6.9 million and transferred the obligation of other related liabilities of $1.1 million.    See Financial Statements - Note 2 – Divestitures under Part I, Item 1 of this Form 10-Q for additional information.      

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Capital Expenditure Budget for 2016.  Because of the continued deterioration of commodity prices and the outlook for the remainder of 2016, our capital expenditure budget for 2016 is $15 million.  In light of our limited access to capital and liquidity, we are not pursuing any significant acquisitions at this time.  See the Overview section in this Item for additional information.

Income Taxes.  During the first quarter of 2016 and 2015, we did not make any income tax payments nor receive any refunds of significance.  For the remainder of 2016, we expect that a substantial portion of our income tax will be deferred and payments, if any, will be primarily related to state taxes.  We have $418.4 million of Federal net operating loss carryforwards (tax basis) available to offset future federal taxable income in 2016 and forward.  We also have $12.1 million of alternative minimum tax credit carryforwards (tax basis) available to be utilized in 2016 and forward.  

Dividends.  During the first quarter of 2016 and the full year of 2015, we did not pay any dividends and a suspension of dividends remains in effect.  

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO at March 31, 2016 and December 31, 2015 were $359.8 million and $378.3 million, respectively.  Our estimate of ARO spending for the April 2016 to March 2017 time period is $83.8 million.  As each of these estimates are for work to be performed in the future, and in the case of our non-current ARO, are for many years in the future, actual expenditures could be substantially different than our estimates.  See our Annual Report on Form 10-K for the year ended December 31, 2015, Item 1A, Risk Factors, for additional information.    

Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 3 – Asset Retirement Obligations, Note 5 – Long-Term and Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q.  As of March 31, 2016, drilling rig commitments were approximately $4.8 million compared to $7.0 million as of December 31, 2015.  The current drilling rig commitments expire within one year from March 31, 2016.  Except for scheduled utilization, other contractual obligations as of March 31, 2016 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Annual Report under Part II, Item 7 on Form 10-K for the year ended December 31, 2015.

Critical Accounting Policies

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2015.  Also refer to Financial Statements - Note 1 -  Basis of Presentation under Part 1, Item 1 of this Form 10-Q.  

Recent Accounting Pronouncements

See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1, of this Form 10-Q.  

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the first quarter of 2016 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2015.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2015.  

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Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely.  Oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability and could have further impact on our business in the future.  As of March 31, 2016, we had open derivative contracts related to a portion of estimated production for the remainder of 2016.  We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments.  Use of these contracts may reduce the effects of volatile oil prices, but they also may limit future income from favorable price movements.  See Financial Statements - Note 4 - Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk.  As of March 31, 2016, we had $288.0 million outstanding on our revolving bank credit facility.  The revolving bank credit facility has a variable interest rate, which is primarily impacted by the rates for the LIBOR and the margin, which ranges from 2.25% to 3.25% depending on the amount outstanding.  As of March 31, 2016, we did not have any derivative instruments related to interest rates.

Item 4.  Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our CEO and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of March 31, 2016, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended March 31, 2016, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.  

 

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PART II – OTHER INFORMATION

 

Item 1.  Legal Proceedings

See Part I, Item 1, Financial Statements – Note 11 – Contingencies, of this Form 10-Q for information on various legal matters.  

Item 1A.  Risk Factors  

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2015, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of the recent decrease in crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2015 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2015.

 

Item 6.  Exhibits

The exhibits to this report are listed in the Exhibit Index.

 

 

 

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on May 5, 2016.

 

 

 

 

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EXHIBIT INDEX

 

 

 

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