UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

For the quarterly period ended March 31, 2019

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  ☑    No  ☐  

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted 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 such files).    Yes  ☑    No  ☐

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

Indicate by check mark whether the registrant is a shell company.    Yes  ☐    No  ☑  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐

As of April 29, 2019, there were 140,644,033 shares outstanding of the registrant’s common stock, par value $0.00001.

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

2

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements

3

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

4

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 substantially all of its operations offshore in the Gulf of Mexico.  The Company is active in the exploration, development and acquisition of oil and natural gas properties.  Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and its 100%-owned subsidiary, W & T Energy VI, LLC, and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 4.  

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, 2018.

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.

Leases.  In February 2016, Accounting Standards Update 2016-02, Leases (Topic 842) (“ASU 2016-02”) was issued requiring an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases.  The classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses.  ASU 2016-02 also requires certain quantitative and qualitative disclosures about leasing arrangements.  Leases acquired to explore for or extract oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of this standard’s update.

ASU 2016-02 was effective for us in the first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019.  Consequently, upon transition, we recognized an ROU asset and a lease liability with no retained earnings impact.

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

As provided for in subsequent accounting standards updates related to ASU 2016-02, we are applying the following practical expedients which provide elections to:

Based on the results of our implementation process, we identified one operating lease in existence at January 1, 2019 subject to ASU 2016-02, which is our real estate lease for office space in Houston, Texas that terminates in December 2022.  We identified no finance leases.  

Houston Office Lease. Minimum future lease payments due under the lease as of March 31, 2019 are as follows: 2019 - $1.1 million; 2020 - $1.6 million; 2021 - $1.6 million and 2022 - $1.6 million.  Expense related to the Houston office lease for the three months ended March 31, 2019 and 2018 was $0.7 million each period.  

As of March 31, 2019, we recorded an ROU asset and a lease liability of $5.0 million using a discount rate of 9.75%.  The discount rate (or incremental borrowing rate) was determined using the interest rate of recently issued debt instruments that were issued at par and for a similar term as the term of our lease for the office space in Houston.    

After the adoption of the new standard update, the amounts recorded within our Condensed Consolidated Balance Sheet are as follows (in thousands):

The adoption of the new standard did not impact our Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows or Condensed Consolidated Statements of Changes in Shareholders’ Deficit.

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

Revenue Recognition.  We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied.  Our contracts with customers are primarily short-term (less than 12 months).  Our responsibilities to deliver a unit of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations.  These performance obligations are satisfied at the point in time control of each unit is transferred to the customer.  Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials.  

Reclassifications.  Certain reclassifications have been made to the prior period financial statements to conform to the current presentation as follows:  In the Condensed Consolidated Statements of Operations, interest income was reclassified from Other expense, net to Interest expense, net, which did not change Net (loss) income before income tax expense.  In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net Cash Used in Investing Activities of which did not change the total amount previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets.

Prepaid Expenses and Other Assets.  The amounts recorded are expected to be realized within one year and the major categories are presented in the following table (in thousands):

Oil and Natural Gas Properties and Other, Net – at cost.  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):

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

Other Assets (long-term).  The major categories are presented in the following table (in thousands):

Accrued Liabilities.  The major categories are presented in the following table (in thousands):

Other Liabilities (long-term).  The major categories are presented in the following table (in thousands):

Recent Accounting Developments.  

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (“ASU 2016-13”).  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018.  We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

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

In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”).  The amendments in ASU 2017-12 require an entity to present the earnings effect of the hedging instrument in the same income statement line in which the earning effect of the hedged item is reported.  This presentation enables users of financial statements to better understand the results and costs of an entity’s hedging program.  Also, relative to current GAAP, this approach simplifies the financial statement reporting for qualifying hedging relationships.  ASU 2017-12 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020.  Early adoption is permitted, including adoption in an interim period.  As we do not designate our commodity derivative instruments as qualifying hedging instruments, our assessment is this amendment will not impact the presentation of the changes in fair values of our commodity derivative instruments on our financial statements.

The SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification, which revised Regulation S-X, Rule 3-04, Changes in Stockholders’ Equity and Noncontrolling Interests.  The new requirement for registrants is to include a reconciliation of changes in stockholders’ equity (deficit) in interim periods for each period that for which a statement of operations is required to be filed.  The new requirement became effective for us for the quarter ended March 31, 2019.

2.  Long-Term Debt

The components of our long-term debt are presented in the following table (in thousands):

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

Credit Agreement

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), which matures on October 18, 2022.  The primary terms and covenants associated with the Credit Agreement are as follows, with capitalized terms defined under the Credit Agreement:

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on or before May 15 and November 14 each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company.  The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement.  The Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal property.  The interest rate on borrowings outstanding for the three months ended March 31, 2019 was 5.1%, which excludes debt issuance costs, commitment fees and other fees.  

9.75% Senior Second Lien Notes Due 2023

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and mature on November 1, 2023, and are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”).  The estimated annual effective interest rate on the Senior Second Lien Notes is 10.3%, which includes amortization of debt issuance costs.   Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year, beginning on May 1, 2019.  

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Senior Second Lien Notes contain covenants that limit or prohibit our ability and the ability of certain of our subsidiaries to: (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).  These covenants are subject to exceptions and qualifications set forth in the Indenture.  In addition, most of the above described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Senior Second Lien Notes an investment grade rating and no default exists with respect to the Senior Second Lien Notes.

10

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

Covenants  

As of March 31, 2019, we were in compliance with all applicable covenants of the Credit Agreement and Senior Second Lien Notes indenture.

Fair Value Measurements

For information about fair value measurements of our long-term debt, refer to Note 3.

3.  Fair Value Measurements  

Derivative Financial Instruments

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 open derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices.  Our open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value.  See Note 6, Derivative Financial Instruments, for additional information on our derivative financial instruments.    

The following table presents the fair value of our open derivative financial instruments (in thousands):

Long-Term Debt

We believe the carrying value of our debt under the Credit Agreement approximates fair value because the interest rates are variable and reflective of current market rates.  The fair value of our Senior Second Lien Notes was measured based using quoted prices, although the market is not a very active market.  The fair value of our long-term debt was classified as Level 2 within the valuation hierarchy.  See Note 2, Long-Term Debt for additional information on our long-term debt.

The following table presents the carrying value and fair value of our long-term debt (in thousands):

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

4.  Joint Venture Drilling Program

On March 12, 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico.  The projects are expected to be completed during the years 2018 through 2020, but some projects may possibly extend into years beyond 2020.  W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest.  Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T, are $361.4 million.  The JV Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed upon rates.  Any exceptions are approved by the Monza board.  W&T is or will be the operator of each well in the JV Drilling Program unless there is a designated third-party operator.

The members of Monza are made up of third-party investors, W&T and an entity owned and controlled by Mr. Tracy W. Krohn, our Chairman and Chief Executive Officer.  The Krohn entity invested as a minority investor on the same terms and conditions as the third-party investors and its investment is limited to 4.5% of total invested capital within Monza.  The entity affiliated with Mr. Krohn has made a capital commitment to Monza of $14.5 million.  

  As of March 31, 2019, members of Monza made partner capital contribution payments to Monza totaling $184.9 million, of which $70.2 million was contributed during the three months ended March 31, 2019.  Our net contribution to Monza, reduced by distributions received, as of March 31, 2019 was $58.9 million.  W&T may be obligated to fund certain cost overruns, subject to certain exceptions, for the JV Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

Consolidation and Carrying Amounts.  Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation.  We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interests in the Monza properties.  As of March 31, 2019, in the Condensed Consolidated Balance Sheet, we recorded $11.0 million, net, in Oil and natural gas properties and other, net, $3.3 million in Other assets and $5.0 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  As of December 31, 2018, in the Condensed Consolidated Balance Sheet, we recorded $8.8 million, net, in Oil and natural gas properties and other, net, $3.3 million in Other assets and $0.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  For the three months ended March 31, 2019, we recorded $1.6 million in Total revenues and $0.9 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.  No revenues or expenses were recorded in the three months ended March 31, 2018 in connection with our proportional interest in Monza’s operations.

Additionally, during the three-months ended March 31, 2019, we received cash calls from Monza of $66.3 million, of which $65.2 million is included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners as of March 31, 2019.

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

5.  Asset Retirement Obligations

Our asset retirement obligations (“ARO”) represent the estimated present value of the amount incurred to plug, abandon and remediate our properties at the end of their productive lives.  

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

6.  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 crude oil and natural gas.  All of the present derivative counterparties are also lenders or affiliates of lenders participating in our Credit Agreement.  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.  We are not required to provide additional collateral to the derivative counterparties 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.

During 2018, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected future production.  The crude oil contracts were based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  The open contracts as of March 31, 2019 are presented in the following tables:

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

The following amounts were recorded in the Condensed Consolidated Balance Sheets in the categories presented and include the fair value of open contracts, and closed contracts which had not yet settled (in thousands):  

The amounts recorded on the Condensed Consolidated Balance Sheets are on a gross basis.  If these were recorded on a net settlement basis, it would not have resulted in any differences in reported amounts.  

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

Cash receipts on commodity derivative contract settlements, net, 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)

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

Awards to Employees.  In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by our shareholders.  During 2018 and 2017, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees.  RSUs are a long-term compensation component, and are subject to satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period based on the results achieved.  In addition to share-based awards, the Company may grant to its employees cash-based incentive awards under the Plan, which were used as a short-term and long-term compensation component of the 2018 awards, and were subject to satisfaction of certain predetermined performance criteria.

As of March 31, 2019, there were 11,852,592 shares of common stock available for issuance in satisfaction of awards under the Plan.  The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, which shares of common stock were issued net of withholding tax through the withholding of shares.  The Company has the option following vesting to settle RSUs in stock or cash, or a combination of stock and cash.  The Company expects to settle RSUs that vest in the future using shares of common stock.  

RSUs currently outstanding relate to the 2018 and 2017 grants, which were subject to predetermined performance criteria applied against the applicable performance period.  These RSUs continue to be subject to employment-based criteria and vesting generally occurs in December of the second year after the grant.  See the table below for anticipated vesting by year.

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award.  Compensation cost is based on the fair value of the equity instrument on the date of grant.  The fair values for the RSUs granted during 2018 and 2017 were determined using the Company’s closing price on the grant date.  We also estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.  

A summary of activity related to RSUs during the three months ended March 31, 2019 is as follows:

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

For the outstanding RSUs issued to the eligible employees as of March 31, 2019, vesting is expected to occur as follows (subject to forfeitures):  

Awards to Non-Employee Directors.  Under the W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, 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 2018, 2017 and 2016.  As of March 31, 2019, there were 128,980 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced on a one-to-one basis when Restricted Shares are granted.  

We recognize compensation cost for share-based payments to non-employee directors over the period during which the recipient is required to provide service in exchange for the award.  Compensation cost is based on the fair value of the equity instrument on the date of grant.  The fair values for the Restricted Shares granted were determined using the Company’s closing price on the grant date.   No forfeitures were estimated for the non-employee directors’ awards.

The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless approved by the Board of 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.

For the outstanding Restricted Shares issued to the non-employee directors as of March 31, 2019, vesting is expected to occur as follows (subject to any forfeitures):

Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  The tax benefit related to compensation expense recognized under share-based payment arrangements was not meaningful and was minimal due to adjustments in the valuation allowance.  A summary of incentive compensation expense under share-based payment arrangements is as follows (in thousands):

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

Unrecognized Share-Based Compensation.  As of March 31, 2019, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $5.5 million and $0.3 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2020 for RSUs and April 2021 for Restricted Shares.  

Cash-Based Incentive Compensation. In addition to share-based awards, cash-based awards were granted under the Plan to eligible employees in 2018 and 2017.  For 2018, there were two cash-based awards consisting of a long-term award and a short-term award.  All cash-based awards are performance-based awards consisting of predetermined performance criteria applied against the applicable performance period.  Expense for each award is recognized over the service period once the applicable financial condition is expected to be met, and the business criteria and individual performance criteria can be reasonably estimated for the applicable period.

A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands):

(1) Includes adjustments of accruals to actual payments.

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

8.  Income Taxes  

Our income tax expense for the three months ended March 31, 2019 and 2018 was $0.2 million and $0.1 million, respectively.  Our effective tax rate was not meaningful for the periods presented as we continue to record a full valuation allowance on net deferred tax assets.  

During the three months ended March 31, 2019 and 2018, we did not receive any income tax refunds or make any income tax payments of significance.

As of March 31, 2019 and December 31, 2018, our valuation allowance was $127.8 million and $117.8 million, respectively, related to net federal and state deferred tax assets.  Net deferred tax assets were 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.     

As of March 31, 2019 and December 31, 2018, we had current income taxes receivable of $54.1 million, which primarily relates to our net operating loss carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These carryback claims were made pursuant to IRC Section 172(f) (related to rules regarding “specified liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  The refund claims require a review by the Congressional Joint Committee on Taxation which we expect to receive in 2019.

The tax years 2013 through 2018 remain open to examination by the tax jurisdictions to which we are subject.   

9.  Earnings Per Share

The following table presents the calculation of basic and diluted (loss) earnings 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.  Contingencies  

Apache Lawsuit.   On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney’s fees and costs assessed in the judgment.  We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit and provided oral arguments in December 2018.    Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017.  Oral arguments occurred on December 4, 2018, but as the filing date of this Form 10-Q, a decision had not been rendered by the U.S. Court of Appeals for the Fifth Circuit.  

The deposit of $49.5 million with the registry of the court is recorded in Other assets (long-term) on the Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) on the Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018.

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we 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 our 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 Interior Board of Land Appeals (“IBLA”) under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties.  We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision.  On December 4, 2018, the IBLA denied our motion for reconsideration.  On February 4, 2019, we filed our first amended complaint.  

Royalties-In-Kind (“RIK”).  Under a program of the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program.  The MMS added to the RIK program our lease at the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed.  The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to become fixed for accounting purposes.  The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed.  We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor.  We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ruling on May 29, 2018.  We filed an appeal on July 24, 2018.  Part of the ruling was in favor of our position and part was in favor of MMS’ position.  Based solely on the District Court’s ruling, we recorded a liability reserve of $2.2 million and $2.1 million as of March 31, 2019 and December 31, 2018, respectively.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals and the government filed a cross-appeal.  Briefing and oral arguments, if held, are expected to be completed in 2019.        

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

Royalties – “Unbundling” Initiative.  The ONRR has publicly announced an “unbundling” initiative to revise 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.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas.  In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant.  We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases.  We have submitted revised calculations covering certain plants and time periods to the ONRR.  As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods.  For the three months ended March 31, 2019 and 2018, we paid $0.1 million and $0.1 million, respectively, of additional royalties and expect to pay more in the future.  We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment.  During the three months ended March 31, 2019 and 2018, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) at various offshore locations.  We currently have nine open civil penalties issued by the BSEE from INCs, which have not been settled as of the filing date of this Form 10-Q.  The INCs underlying these open civil penalties cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations on various dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.7 million.  As of March 31, 2019 and December 31, 2018, we have accrued approximately $3.4 million, which is our best estimate of the final settlements once all appeals have been exhausted.  Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.    

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.  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.

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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”). These forward-looking statements 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, 2018 and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission.  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.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and hold working interests in 48 offshore fields in federal and state waters (47 producing and one field capable of producing).  We currently have under lease approximately 720,000 gross acres (390,000 net acres) spanning across the Outer Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 515,000 gross acres on the conventional shelf and approximately 205,000 gross acres in the deepwater (water depths in excess of 500 feet).  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company and through our proportionately consolidated interests in Monza, as described in more detail in Financial Statements– Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.    

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the three months ended March 31, 2019 were comprised of 49.2% crude oil and condensate, 10.3% NGLs and 40.5% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past.  For the three months ended March 31, 2019, revenues from the sale of crude oil and NGLs made up 80.2% of our total revenues compared to 79.7% for the three months ended March 31, 2018.  For the three months ended March 31, 2019, our combined total production expressed in equivalent volumes was 9.8% lower than for the three months ended March 31, 2018, with natural gas having the largest decline.  For the three months ended March 31, 2019, our total revenues were 13.5% lower than the three months ended March 31, 2018 primarily due to lower production and lower realized prices for crude oil and NGLs.  See Results of Operations – Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018 in this Item 2 for additional information.

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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.  During the three months ended March 31, 2019, our average realized crude oil price was $58.66 per barrel.  This is a decrease from our average realized crude oil price of $62.52 per barrel for the three months ended March 31, 2018 and a decrease from our average realized crude oil price of $65.62 per barrel for the year 2018.  For the month of March 2019, the average realized price for crude oil increased from the amounts realized in January 2019 and February 2019 to $64.23 per barrel, which was above the average realized crude oil price for the three months ended March 31, 2018.  Our average realized prices of NGLs and natural gas for the three months ended March 31, 2019 were lower than the average realized prices for the three months ended March 31, 2018 by 24.2% and 1.0%, respectively.  

Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors.  Crude oil quality adjustments can vary significantly by field.  All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our crude 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.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 improved by approximately $3.00 per barrel for these types of crude oils.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During in the three months ended March 31, 2019 compared to the three months ended March 31, 2018, average prices for domestic ethane increased by 6% and average domestic propane prices decreased by 21% as measured using a price index for Mount Belvieu.  The average price for other domestic NGLs components ranged from decreases of 15% to 18% for the three months ended March 31, 2019 year-over-year.  We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.  

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as of the end of March 2019 was approximately the same level as year ago levels for land based rigs (an increase of four rigs, or less than 1%), and higher in the Gulf of Mexico (an increase of 11 rigs or 92%).  The oil rig count as of March 2019 and March 2018 was 816 and 797, respectively.  The U.S. natural gas rig count as of March 2019 and March 2018 was 190 and 194, respectively.  In the Gulf of Mexico, the number of working rigs was 23 rigs (18 oil rigs and five natural gas rigs) as of March 2019 and 12 rigs (all oil rigs) as of March 2018.  During the three months ended March 31, 2019, we had four rigs running, which represents approximately 20% of the active rigs in the Gulf of Mexico.  

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Our current capital expenditure forecast for 2019 is approximately $120.0 million composed of select shelf and deepwater projects that, assuming success, would be placed on production within a few months after completion.  The forecast also incorporates our capital spending relating to the JV Drilling Program (net to our interest).  Our 2019 plans also include spending $24.0 million for ARO.  Based upon current price and production expectations for 2019, we believe that our cash flows from operating activities and cash on hand will be sufficient to fund our operations through year-end 2019 and build available cash balances; however, future cash flows are subject to a number of variables and additional capital expenditures may be required to more fully develop our properties.  We are also currently evaluating various acquisition opportunities, which, if successful, may increase our capital requirements in 2019 and beyond.  We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2019 plans.  See our Annual Report on Form 10-K for the year ended December 31, 2018, 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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Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Revenues.  Total revenues decreased $18.1 million, or 13.5%, to $116.1 million for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018.  Oil revenues decreased $10.6 million, or 10.9%, NGLs revenues decreased $3.2 million, or 33.3%, natural gas revenues decreased $4.0 million, or 15.6%, and other revenues decreased $0.3 million.  The decrease in oil revenues was attributable to a 6.2% decrease in the average realized sales price to $58.66 per barrel for the three months ended March 31, 2019 from $62.52 per barrel for the three months ended March 31, 2018 and sales volumes decreased 5.1%.  The decrease in NGLs revenues was attributable to a 24.2% decrease in the average realized sales price to $20.88 per barrel for the three months ended March 31, 2019 from $27.54 per barrel for the three months ended March 31, 2018 and sales volumes decreased 12.0%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 1.2 billion cubic feet (“Bcf”), or 14.5% and a 1.0% decrease in the average realized price to $3.00 per Mcf for the three months ended March 31, 2019 from $3.03 per Mcf for the three months ended March 31, 2018.  Overall, production volumes decreased 9.8% on a Boe basis.  The largest production increases for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 were from our interest in the Heidelberg field, which was acquired in April 2018, and increases in production at our Ship Shoal 349 field (Mahogany).  Offsetting were production decreases primarily from increases in downtime, with the largest amounts related to planned maintenance, well servicing and rig movements at certain platforms and pipelines.  Our estimate of deferred production for the three months ended March 31, 2019 was approximately 7,200 Boe per day as compared to 4,200 Boe per day for the three months ended March 31, 2018, which comprises 83% of the production volume variance between the two periods.  In April 2019, a majority of the pipeline and facility maintenance was completed and improved well performance and continued ramp up of new wells enabled the mid-April production rate to increase to over 37,000 Boe/day.  

Revenues from oil and NGLs as a percent of our total revenues were 80.2% for the three months ended March 31, 2019 compared to 79.7% for the three months ended March 31, 2018.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 35.6% for the three months ended March 31, 2019 compared to 44.0% for the three months ended March 31, 2018.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $6.6 million, or 17.9%, to $43.5 million in the three months ended March 31, 2019 compared to the three months ended March 31, 2018.  On a component basis, base lease operating expenses increased $1.4 million, workover expenses increased $2.3 million, and facilities maintenance expense increased $2.9 million.  Base lease operating expenses increased primarily due to the addition of the Heidelberg field interest, acquired in April 2018, and had base lease operating expenses of $1.7 million for the three months ended March 31, 2019.  The increase in workover expense was primarily due to 2019 projects at our Mahogany field.  The facility maintenance expense increase was primarily attributable to work performed in 2019 at our Mahogany field combined with multiple other fields.  

Gathering and transportation.  Gathering and transportation expenses increased $1.4 million to $6.4 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 primarily related to the East Cameron 321 field due to a change in our customer where transportation costs were separately billed and recorded as such beginning in the second half of 2018, and are offset by higher realized prices recorded for crude oil.  In addition, expenses increased due to the Heidelberg field.  

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, decreased to $11.25 per Boe for the three months ended March 31, 2019 from $11.44 per Boe for the three months ended March 31, 2018.  On a nominal basis, DD&A decreased to $33.8 million (or 11.3%) for the three months ended March 31, 2019 from $38.1 million for the three months ended March 31, 2018.  DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are production, capital expenditures, sales of assets and changes in proved reserves volumes.    

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General and administrative expenses (“G&A”).  G&A was $14.1 million for the three months ended March 31, 2019, decreasing 6.2% from $15.0 million for the three months ended March 31, 2018.  The decrease was primarily due to a decrease in incentive compensation.  G&A on a per Boe basis was $4.70 per Boe for the three months ended March 31, 2019 compared to $4.52 per Boe for the three months ended March 31, 2018.

Derivative loss. The three months ended March 31, 2019 reflects a $48.9 million derivative loss primarily due to increased crude oil prices during March 2019 as compared to oil prices during December 2018, which decreased the estimated fair value of open crude oil contracts between the two measurement dates.  For the three months ended March 31, 2018, we did not have any gains or losses from derivative contracts.  

Interest expense, net.  Interest expense, net, was $16.3 million and $11.0 million for the three months ended March 31, 2019 and 2018, respectively.  During 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60, Troubled Debt Restructuring (“ASC 470-60”), which lowered reported interest expense for the three months ended March 31, 2018 and affects the comparability.  

Income tax expense. Our income tax expense for the three months ended March 31, 2019 and 2018 was $0.2 million and $0.1 million, respectively.  Immaterial deferred income tax expense was recorded for the three months ended March 31, 2019 due to dollar-for-dollar offsets by our valuation allowance.  Our effective tax rate using book pre-tax income was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.  As of March 31, 2019, our valuation allowance was $127.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets.  Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs.  See Financial Statements – Note 8 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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 AROs.  We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings and expect to continue to do so in the future.  

Credit Agreement.  On October 18, 2018, we entered into the Credit Agreement, which matures on October 18, 2022.  As of March 31, 2019, we had $21.0 million borrowings outstanding under the Credit Agreement and $8.1 million of letters of credit issued under the Credit Agreement.  During the three months ended March 31, 2019, we did not have any additional borrowings or repayments under the Credit Agreement.  Availability under our Credit Agreement as of March 31, 2019 was $220.9 million.  

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, with the next redetermination to be completed by May 15, 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our Credit Agreement.  The Credit Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.

We currently have six lenders under our Credit Agreement, with commitments ranging from $25.0 million to $62.5 million for the current borrowing base.  While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.  See Financial Statements – Note 2 –Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.   

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Senior Second Lien Notes.  As of March 31, 2019, we had outstanding $625.0 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023.  The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  See Financial Statements – Note 2 –Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.   

Debt Covenants.  The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes.  We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of March 31, 2019.

BOEM Matters.  As of the filing date of this Form 10-Q, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations.  We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.  

Surety Bond Collateral.  Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially 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.  No additional demands were made to us by sureties during 2019 as of the filing date of this Form 10-Q.

The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.  

Cash Flow and Working Capital.  Net cash provided by operating activities for the three months ended March 31, 2019 and 2018 was $84.8 million and $75.0 million, respectively.  Our combined average realized sales price per Boe decreased 4.0% for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, which caused total revenues to decrease $8.0 million.  Production volumes decreased by 9.8% primarily from increases in downtime, which caused revenues to decrease by $9.8 million.  In addition, operating expenses impacting operating cash flows increased by $8.3 million primarily for workover and facility projects.  

Other items affecting operating cash flows was an increase of $44.6 million for the three months ended March 31, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to $19.1 million for the three months ended March 31, 2018.  ARO settlements were $0.3 million for the three months ended March 31, 2019, which decreased from $7.0 million for the three months ended March 31, 2018.  During the three months ended March 31, 2019, cash derivative receipts, net, were $11.9 million primarily due to derivative oil contracts.  Working capital items accounted for the balance of the change in net cash provided by operating activities.  

Net cash used in investing activities for the three months ended March 31, 2019 and 2018 was $31.6 million and $41.3 million, respectively, which represents our investments in oil and gas properties and equipment.  The majority of our capital expenditures for the three months ended March 31, 2019 were for investments in the deep waters of the Gulf of Mexico and, to a lesser extent, on the conventional shelf of the Gulf of Mexico.  There were no material acquisitions or asset sales in the three months ended March 31, 2019 and a deposit of $3.0 million was made during the three months ended March 31, 2018 related to the Heidelberg acquisition consummated in April 2018.  

Net cash used by financing activities for the three months ended March 31, 2019 and 2018, respectively was $0.4 million and $2.1 million, respectively. The net cash used for the three months ended March 31, 2018 was for interest payments on certain debt reported as financing activities under ASC 470-60.  

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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.  During 2018, we entered into derivative contracts for crude oil and natural gas for a portion of our future production.  See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  

  Insurance Coverage.  We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) 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.  With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $30.0 million.  Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.  The operational and named windstorm coverages are effective for one year beginning June 1, 2018.  Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, 2019 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 and we have insurance coverage of such amount.  

Although we were able to renew our general and excess liability policies effective on May 1, 2019, and we expect to renew our Energy Package effective on June 1, 2019, 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.  We do not carry business interruption insurance.

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 crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  During the three months ended March 31, 2018, we received reimbursement of capital expenditures from Monza for projects in the JV Drilling Program, some of which had incurred costs during 2017.  These reimbursements related to 2017 are reported in a separate line in the table below.  The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

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The following table presents our exploration and development capital expenditures geographically in the Gulf of Mexico (in thousands):

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets.  The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments to report payments related to capital expenditures.  

Our capital expenditures for the three months ended March 31, 2019 were financed by cash flow from operations and cash on hand.  

During the three months ended March 31, 2019, we completed one of two target zones for the Virgo A-13 well, which began producing during March 2019.  The other target zone for the Virgo A-13 well was completed in April 2019.  The Virgo A-13 well is in the JV Drilling Program.  During the three months ended March 31, 2018, we completed two wells.  We did not drill any dry holes in either period presented.  

Exploration/Development Activities.  As of April 15, 2019, we were drilling on the South Timbalier 320 A-3 and the Mississippi Canyon 800 SS2 wells, both of which are in the JV Drilling Program.

Offshore Lease Awards.  During the three months ended March 31, 2019, we were the apparent high bidder on 15 blocks (eight deepwater and seven shallow water) in the Gulf of Mexico Lease Sale 252 held by the BOEM on March 20, 2019.  These 15 blocks cover approximately 73,500 acres and, if awarded, we will pay approximately $3.5 million for all of the awarded leases combined, which reflects a 100% working interest in the acreage.  As of the filing date of this Form 10-Q, we have received official notice of being awarded one of the leases and we expect to receive official notice related to the other leases within 90 days of the lease sale date.

Capital Expenditure Budget.  Our current 2019 capital expenditure forecast is approximately $120 million, which excludes potential acquisitions.  The forecast incorporates the shared investments in certain wells included in the JV Drilling Program.  We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.  

Income Taxes.  As of March 31, 2019, we had current income taxes receivable of $54.1 million.  For 2019, we do not expect to make any significant income tax payments.  See Financial Statements – Note 8 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO at March 31, 2019 and December 31, 2018 were $314.2 million and $310.1 million, respectively.  Our plans include spending $24.0 million in 2019 for ARO compared to $28.6 million spent on ARO in 2018.  As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates.  See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information.    

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Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt and Note 5 – Asset Retirement Obligations, and under Part I, Item 1 of this Form 10-Q.  As of March 31, 2019, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $9.2 million, which was approximately the same as the amount as of December 31, 2018.  Except for scheduled utilization, other contractual obligations as of March 31, 2019 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018.

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, 2018.  See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1 of this Form 10-Q for additional information.  

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 three months ended March 31, 2019 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, 2018.  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, 2018.  

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely.  Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and could have impacts on our business in the future.  During 2018, we entered into derivative crude oil contracts related to a portion of our estimated future production.  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 crude oil and natural gas prices, but they also may limit future income from favorable price movements.  See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.    

Interest Rate Risk.  As of March 31, 2019, we had $21.0 million borrowings outstanding under our Credit Agreement and were subject to the variable London Interbank Offered Rate and the Applicable Margin.  We did not have any derivative instruments related to interest rates.    

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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 Chief Executive Officer (“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, 2019, 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, 2019, 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 Financial Statements – Note 10 – Contingencies, under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.  

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, 2018, 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 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, 2018 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, 2018.

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Item 6.  Exhibits

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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 2, 2019.

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