UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended September 30, 2018

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 October 31, 2018, there were 139,153,798 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)

 

See Notes to Condensed Consolidated Financial Statements.

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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’ 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 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. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 4.  

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, 2017.

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, proved reserves and future rate of growth.  The average realized prices of crude oil and NGLs improved during the nine months ended September 30, 2018 compared to the average realized prices in the nine months ended September 30, 2017.  

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”) which substantially changed our capital structure.  The Senior Second Lien Notes were issued at par and have a maturity date of November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “New Revolving Credit Agreement”) which provides us with a revolving bank credit facility with an initial borrowing base of $250.0 million (increasing from $150.0 million under our prior facility).  Letters of credit may be issued in amounts up to $30.0 million provided availability exists.  The New Revolving Credit Agreement matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  We refer to these transactions and the related repurchases and retirements, repayments and redemptions of all of our outstanding notes and term loans collectively as the “2018 Refinancing Transaction.”  See Note 12, Subsequent Events, for additional information.  

We believe we will have adequate available liquidity to fund our operations through November 2019, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or future Bureau of Ocean Energy Management (“BOEM”) bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

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

 

See our Annual Report on Form 10-K for the year ended December 31, 2017 concerning risks related to our business and events occurring during 2017 and other information and the Notes herein for additional information.  

Accounting Standard Updates Effective January 1, 2018:  

   Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018.  The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business.  In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business.          

Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us in the period ending March 31, 2018.  We reviewed our contracts using the five-step revenue recognition model, which did not identify any changes required as to the amount or timing of revenue recognition.  We adopted the new standard using the modified retrospective approach which did not result in any cumulative-effect adjustment on the date of adoption.  The implementation of ASU 2014-09 resulted in a change in our reporting in the Condensed Consolidated Statement of Operations so that we now report revenue streams separately for crude oil, NGLs, natural gas and other revenues in compliance with the new standard.     

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.

Reclassification.  Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows:  Within the Net Cash Provided by Operating Activities of the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items, of which did not change the total amount previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets or the Condensed Consolidated Statements of Operations.

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):

 

 

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

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):

 

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):

 

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

 

Recent Accounting Developments.  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months.  Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a financing or operating lease.  However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space, which is primarily in Houston, Texas, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases nor do we have any leases recorded on the Condensed Consolidated Balance Sheets.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

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

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

 

 

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

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)

Debt Issuance, Repayment of Long-Term Debt and the New Revolving Credit Agreement

As described in Note 12, Subsequent Events, on October 18, 2018, we issued the Senior Second Lien Notes and entered into the New Revolving Credit Agreement.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  

The following discussion and descriptions relate to our long-term debt as of September 30, 2018:  

Accounting for Certain Debt Instruments

We accounted for a transaction executed on September 7, 2016 as a Troubled Debt Restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the 9.00/ 10.75% Second Lien Payment-In-Kind (“PIK”) Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); the 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”) and the 11.00% 1.5 Lien Term Loan, due November 15, 2019 (the “1.5 Lien Term Loan”) (collectively, the “2016 Restructuring Transactions”) are measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the 2016 Restructuring Transactions in the Condensed Consolidated Statements of Operations for the periods presented.  Additionally, no interest expense related to the 2016 Restructuring Transactions will be recorded in the fourth quarter of 2018 as payments of interest on the 2016 Restructuring Transactions will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments.  Under ASC 470-60, payments related to the 2016 Restructuring Transactions are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.

The primary terms of our long-term debt are described below:    

Prior Credit Agreement.  The Fifth Amended and Restated Credit Agreement, (the “Prior Credit Agreement”) provided a revolving bank credit facility and would have expired by its term on November 8, 2018.  The primary items of the Prior Credit Agreement are as follows, with certain terms defined under the Prior Credit Agreement:

  As of September 30, 2018 and December 31, 2017, we did not have any borrowings outstanding under the Prior Credit Agreement and had $9.7 million and $0.3 million of letters of credit outstanding, respectively.  Available credit as of September 30, 2018 was $140.3 million.  As of September 30, 2018, we had on deposit $4.7 million with the lead bank in compliance with the terms of the Prior Credit Agreement, as letters of credit are considered borrowings and our unrestricted cash balance exceeded $35.0 million.  On October 18, 2018, the Prior Credit Agreement was replaced by the New Revolving Credit Agreement, as described in Note 12, Subsequent Events.  

 

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

1.5 Lien Term Loan.  In September 2016, we entered into the 1.5 Lien Term Loan with a maturity date of November 15, 2019.    Interest accrued at 11.00% per annum and is payable quarterly in cash.  The 1.5 Lien Term Loan was secured by a 1.5 priority lien on all of our assets pledged under the Prior Credit Agreement.  The lien securing the 1.5 Lien Term Loan was subordinated to the liens securing the Prior Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows as of September 30, 2018 have been included in the carrying value under ASC 470-60.  On October 18, 2018, the 1.5 Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.

Second Lien Term Loan.  In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which had an annual interest rate of 9.00%.  The Second Lien Term Loan was issued at a 1.0% discount to par with a maturity date of May 15, 2020 and has been recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs as of September 30, 2018.  Interest on the Second Lien Term Loan was payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan was 9.6%, which included amortization of debt issuance costs and discounts.  The Second Lien Term Loan was secured by a second-priority lien on all of our assets that are secured under the Prior Credit Agreement.  The Second Lien Term Loan was effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan (discussed above) and was effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).   On October 18, 2018, the Second Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.    

Second Lien PIK Toggle Notes.  In September 2016, we issued Second Lien PIK Toggle Notes with a maturity date of May 15, 2020.  Interest was payable on May 15 and November 15 of each year.  For the interest period from November 15, 2017 up to and including March 6, 2018, we had the option to pay all or a portion of interest in-kind at the rate of 10.75% per annum, which if so exercised, is added to the principal amount.  After March 6, 2018, interest was payable in cash at the rate of 9.00% per annum.  The Second Lien PIK Toggle Notes were secured by a second-priority lien on all of our assets that are pledged under the Prior Credit Agreement.  The Second Lien PIK Toggle Notes were effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan and were effectively pari passu with the Second Lien Term Loan.  On October 18, 2018, all of the outstanding Second Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.

Third Lien PIK Toggle Notes.  In September 2016, we issued Third Lien PIK Toggle Notes with a maturity date of June 15, 2021.  For the interest periods up to and including September 6, 2018, if we so elected, we had the option to pay all or a portion of interest in-kind at a rate of 10.00% per annum.  If so elected, such in-kind were added to the principal amount.  After September 6, 2018, interest was payable in cash at the rate of 8.50% per annum.  The Third Lien PIK Toggle Notes were secured by a third-priority lien on all of our assets that were secured under the Prior Credit Agreement.  The Third Lien PIK Toggle Notes were effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  On October 18, 2018, all of the outstanding Third Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Unsecured Senior Notes.  Our 8.500% Unsecured Senior Notes outstanding, which had an annual interest rate of 8.50% and maturity date of June 15, 2019, (the “Unsecured Senior Notes”), were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes was payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes was 8.4%, which included amortization of premiums and debt issuance costs.  On October 18, 2018, all of the outstanding Unsecured Senior Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Covenants.  We were in compliance with all applicable covenants for all of our debt instruments as of September 30, 2018.

For information about fair value measurements for our long-term debt, refer to Note 3, Fair Value Measurements.

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

3.  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 fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as only one entity has been the holder of the 1.5 Lien Term Loan.  The fair values of our Second Lien Term Loan, Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and Unsecured Senior Notes were based on quoted prices, although the market is not a very active market; therefore, the fair value is classified within Level 2.  

The following table presents the fair value of our long-term debt, all of which are classified as Level 2 within the valuation hierarchy (in thousands):

The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2, Long-Term Debt.  See Note 7, Derivative Financial Instruments, for the fair value of our open derivative contracts, which is classified as Level 2 in the reporting hierarchy and is reported in the Condensed Consolidated Balance Sheets using fair value.

4.  Drilling Program Joint Venture

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza Energy LLC, a Delaware limited liability company, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico over the next three years.  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.  The Monza board has approved the substitution of one of these identified undeveloped drilling projects, the Viosca Knoll 823 (“VK 823”) A-14 well, with the VK 823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well.  The interest in the VK823 A-14 well is in process of being reconveyed to W&T.  Since the initial closing, additional investors have joined as members of Monza and as of September 30, 2018, total commitments by all members, including W&T, are $361.4 million.  Monza has closed off funding from additional investors.  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.  For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well.  W&T will be the operator of each well in the JV Drilling Program unless there is already 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.  

At the inception of Monza, W&T received a net reimbursement of approximately $20 million for the capital expenditures incurred prior to the close date for projects in the JV Drilling Program.  W&T may be obligated to fund certain cost overruns, subject to certain exceptions, on JV Drilling Program wells above budgeted and contingency amounts.  As of September 30, 2018, members of Monza made partner capital contribution payments to Monza totaling $114.7 million.

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

Information on the structure and relationship follows:

Board Structure and Authority.  Under the Monza limited liability agreement, the business and affairs of Monza are managed by a board of five directors, which will consist of three directors selected by the third-party investors, Mr. Krohn, and an additional independent director will be selected by a majority of the third-party investors in Monza subject to consent by W&T.  The independent director and one of the directors to be selected by the investors have not yet been selected.  The day-to-day operations of Monza are being managed by W&T, under the direction of the Monza board, pursuant to a services agreement.  W&T has no control over the decisions of the Monza board.  W&T has veto rights for certain decisions, but does not have the ability to unilaterally make decisions for Monza, except for day-to-day decisions as permitted under the services agreement.  The Monza board is responsible for the management of Monza and for making decisions with respect to its interest in the 14 drilling projects, including approval of the budgets.    

Accounting Methodology and Carrying Amounts.  Our interest in Monza is considered to be a variable interest entity 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 interest in the Monza properties.  As of September 30, 2018, in the Condensed Consolidated Balance Sheet, we recorded $7.5 million, net, in oil and natural gas properties, $2.2 million in other assets and $2.6 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  For the nine months ended September 30, 2018, we recorded $2.2 million in revenue, $1.1 million in operating expense and $0.3 million, net, in other expense in connection with our proportional interest in Monza’s operations.

Maximum Exposure. Our contribution to Monza as of September 30, 2018 was $53.5 million, which consisted of cash and the conveyance of the Company’s working interest in the 14 projects.  We may also take responsibility for certain drilling and completion cost overruns, subject to certain limitations and certain exceptions, of which the total exposure cannot be estimated at this time.

5. Acquisitions and Divestitures  

  Heidelberg Field.  On April 5, 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and 904.  The gross purchase price was $31.1 million which was adjusted for certain closing items and an effective date of January 1, 2018.  Cash flows generated by the acquired interest between the effective date and the closing date reduced the net purchase price to $16.8 million.  We determined that the assets acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition.  In connection with this transaction, we were required to furnish a letter of credit of $9.4 million to a pipeline company as consignee.  We recognized asset retirement obligations (“ARO”) of $3.6 million as a component of the transaction.  In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.  

Permian Basin.  On September 28, 2018, we closed on the divestiture of all of our ownership in an overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.    

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

6.  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.  

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

 

 

7.  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.  Some of the derivative counterparties are also lenders or affiliates of lenders participating in our Prior 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.  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.

During the second quarter of 2018, we entered into crude oil derivative contracts which relate to a portion of our expected crude oil production from May 2018 to December 2018.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  During the first quarter of 2017, we entered into commodity contracts for crude oil and natural gas, all of which had expired as of December 31, 2017.

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

As of September 30, 2018, our open crude oil derivative contracts were as follows:  

 

The swap and two-way collars were “cost-less” contracts, in that no premiums were paid or received.  For the put option contract, the $2.1 million premium is being amortized over the life of the contract and recorded in Prepaid and other assets on the Condensed Consolidated Balance Sheet.  See Note 1, Basis of Presentation.

Our open and closed (not settled) commodity derivative contracts were recorded within the line Accrued liabilities on the Condensed Consolidated Balance Sheet summarized in the following table (in thousands):

 

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

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

 

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

 

Offsetting Commodity Derivatives

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 Prior Credit Agreement, that event may also trigger an acceleration of settlement of some 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.  As of September 30, 2018, there would have been no difference in the presentation of our commodity derivatives on a gross or net basis.

8.  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, 2017 and 2016, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees.  RSUs are a long-term compensation component and are granted to certain employees, 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 are both a short-term and long-term compensation component and are subject to satisfaction of certain predetermined performance criteria.

As of September 30, 2018, there were 13,342,827 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 may be issued net of withholding tax if an awardee elects to satisfy his or her tax liability 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, 2017 and 2016 grants, which are 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, 2017 and 2016 were determined using the Company’s closing price on the grant date.  We are also required to 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.  

 

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

A summary of activity related to RSUs during the nine months ended September 30, 2018 is as follows:

 

 

For the RSUs that vested during 2018, the aggregate fair value at the grant dates was $0.1 million and the aggregate fair value at the vesting date was $0.2 million.

For the outstanding RSUs issued to the eligible employees as of September 30, 2018, vesting is expected to occur as follows (subject to any 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 September 30, 2018, 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.

A summary of activity related to Restricted Shares is as follows:

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

For the Restricted Shares that vested during 2018, the aggregate fair value at the grant dates was $0.3 million and the aggregate fair value at the vesting date was $0.7 million.

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2018, 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.  Share-based compensation was lower in the three and nine months ended September 30, 2018 compared to the prior year period due to timing of the grant date and changes in the 2018 program.  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 September 30, 2018, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $8.3 million and $0.4 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, 2017 and 2016.  For 2018, there are 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.  The 2018 long-term, cash-based awards will be eligible for payment on December 14, 2020 subject to participants meeting certain performance criteria.  The 2018 short-term, cash-based awards will be eligible for payment on or about March 15, 2019 subject to participants meeting certain eligibility criteria.  The cash-based awards for the 2018 short-term program, the 2017 program and the 2016 program include an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (as defined in the awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award as described below.  Expense for each program 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.

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

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

 

9.  Income Taxes  

Our income tax expense for the three and nine months ended September 30, 2018 was $0.1 million and $0.4 million, respectively.  Our income tax expense for the three months ended September 30, 2017 was $5.5 million and our income tax benefit for the nine months ended September 30, 2017 was $11.1 million.  Our effective tax rate was not meaningful for the periods presented.  Based on a full year forecast, we are not expecting any current income tax expense.  In addition, immaterial deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance.  The income tax expense for the three months ended September 30, 2017 relates to revisions under GAAP using the annualized effective tax rate method in computing income tax expense or benefit for interim periods and the income tax benefit for the nine months ended September 30, 2017 relates to net operating loss carryback claims made pursuant to Internal Revenue Code (“IRC”) Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.

During the nine months ended September 30, 2018, we did not receive any income tax refunds and made no income tax payments of significance.  During the nine months ended September 30, 2017 we received $11.9 million of income tax refunds and made $0.2 million of income tax payments.          

As of September 30, 2018, we recorded current income taxes receivable of $65.2 million.  As of December 31, 2017, the balance sheet reflected current income taxes receivable of $13.0 million and non-current income taxes receivable of $52.1 million.  The receivable primarily relates to a net operating loss claim carried back for 2017 and net operating loss claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims require a review by the Congressional Joint Committee on Taxation.

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

As of September 30, 2018 and December 31, 2017, our valuation allowance was $148.3 million and $171.5 million, respectively, related to federal and state deferred tax assets.  Net deferred tax assets were recorded related to NOLs 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.  Although our net deferred tax assets and the related valuation allowance reflect the provisions of the Tax Cuts and Jobs Act (“TCJA”), due to the timing and the complexity of the provisions of the TCJA, further adjustments may be required during 2018 in determination of the final effect in our financial statements.  

The tax years 2013 through 2017 remain open to examination by the tax jurisdictions to which we are subject.   

10.  Earnings Per Share

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

 

11.  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 (“MC”) 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, where oral argument is scheduled for December 4, 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.  

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 September 30, 2018 and December 31, 2017.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) as of September 30, 2018 and December 31, 2017.

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

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.  Because the IBLA still has not ruled on W&T’s request for reconsideration, the district court action has been suspended.  The court requires periodic reports concerning the status of the request for reconsideration pending before the IBLA.  Once the IBLA rules, the district court action will return to the court’s active docket.  

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 $2.1 million as of September 30, 2018.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals.        

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 nine months ended September 30, 2018 and 2017, we paid additional royalty payments of $0.6 million and $1.2 million, respectively.  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 nine months ended September 30, 2018 and 2017, 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 eight 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 the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.9 million.  We have accrued approximately $3.4 million as of September 30, 2018, 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.    

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

Surety Bond Collateral.  The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities.  We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion.  We did not receive any collateral demands from surety bond providers during the nine months ended September 30, 2018.

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.

12.  Subsequent Events

On October 18, 2018, we entered into a series of transactions to effect a refinancing of substantially all of our outstanding indebtedness.  On such date, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023, which are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”).  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 will be recorded at their carrying value consisting of principal and unamortized debt issuance costs.

   Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture).  In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date.

On and after November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.000% on November 1, 2022 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are guaranteed by Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  If we experience certain change of control events, we will be required to offer to repurchase the notes at 101.000% of the principal amount, plus accrued and unpaid interest, if any, to the repurchase date.

Certain entities controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the 2018 Refinancing Transaction.  The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes.  As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan liquidated as the loan was repaid in full.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the New Revolving 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.

Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement with a maturity date of October 18, 2022.  The primary items of the New Revolving Credit Agreement are as follows, with certain terms defined under the New Revolving Credit Agreement:

Availability under the New Revolving Credit Agreement 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 first redetermination will be in the spring of 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the New Revolving Credit Agreement.  The New Revolving 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.  

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

The New Revolving Credit Agreement contains various customary covenants for certain financial tests, as defined in the New Revolving Credit Agreement, and these tests are measured as of the end of each quarter, and for customary events of default.  The customary events of default include: (i) default in the payment of interest on the Senior Second Lien Notes when due, continued for 30 days; (ii) default in payment of the principal of or premium, if any, on the Senior Second Lien Notes when due; (iii) failure by the Company or any of its restricted subsidiaries, if any, to comply with certain covenants relating to merger and consolidation and offers to purchase Senior Second Lien Notes in connection with certain change of control transactions or asset sales; (iv) failure by the Company to comply for 60 days after notice with any of the other agreements in the Indenture; (v) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Company or any of its restricted subsidiaries (or the payment of which is guaranteed by the Company or any of its restricted subsidiaries) if that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period provided in such indebtedness (a “Payment Default”); or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other such indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $50.0 million or more; (vii) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company; (viii) failure by the Company, or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, to pay final judgments aggregating in excess of $50.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (ix) any Security Document (as defined in the Indenture) ceases for any reason to be enforceable with respect to any collateral having a fair market value of not more than $25.0 million, which failure is not cured within 45 days; (x) any second lien purported to be granted under any Security Document on collateral, individually or in the aggregate, having a fair market value in excess of $25.0 million, ceases to be an enforceable and perfected second-priority lien, which failure is not cured within 45 days; and (xi) except as permitted by the Indenture, any future subsidiary guarantee entered into by one of the Company’s subsidiaries shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its subsidiary guarantee of the Senior Second Lien Notes.

After closing the 2018 Refinancing Transaction on October 18, 2018, we had $61.0 million borrowings outstanding, $9.7 million of letters of credit outstanding and our borrowing availability was $179.3 million under the New Revolving Credit Agreement.  We were in compliance with all applicable covenants of the New Revolving Credit Agreement and Senior Second Lien Notes after the 2018 Refinancing Transaction.

The funds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of the long-term debt instruments outstanding including accrued interest, tender offer premiums, redemption premiums and debt issuance costs.  The 2018 Refinancing Transaction is expected to result in a net gain of approximately $47.0 million that will be recorded in the consolidated statement of operations and approximately $17.9 million of additional capitalized debt issuance costs fees that will be recorded on the balance sheet during the fourth quarter of 2018.  As the 2018 Refinancing Transaction substantially changed our capital structure, the following table is provided to present the Condensed Consolidated Balance sheet on a pro forma basis as if the 2018 Refinancing Transaction occurred on September 30, 2018:

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

 

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

 

 

Pro Forma Adjustments:

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

13.  Supplemental Guarantor Information

On September 30, 2018, our payment obligations under the Prior Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (collectively, the “Existing Notes”) were fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including the Guarantor Subsidiaries.  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Subsequent to the 2018 Refinancing Transaction, the New Revolving Credit Agreement and the Senior Second Lien Notes are fully and unconditionally guaranteed by Guarantor Subsidiaries.  Under the indentures governing the Existing Notes and the Senior Second Lien Notes, the guarantees of the Guarantor Subsidiaries can be released under certain circumstances, including:  

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.  As a result of the JV Drilling Program, we recorded proportional consolidation adjustments, which are not considered a guarantor asset under our debt agreements and, accordingly, are reported as non-guarantor adjustments in the following tables.  Due to the methodology of recording the ceiling-test write down in prior periods, consolidating adjustments are required to present the consolidated results appropriately.  The 2018 Refinancing Transaction substantially changed our capital structure.  See Note 12, Subsequent Events, for additional information.  

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

Condensed Consolidating Balance Sheet as of September 30, 2018

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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, 2017

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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 September 30, 2018

 

 

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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 Nine Months Ended September 30, 2018

 

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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 September 30, 2017

 

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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 Nine Months Ended September 30, 2017

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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 Nine Months Ended September 30, 2018

 

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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 Nine Months Ended September 30, 2017

 

 

 

 

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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, 2017 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, 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 currently hold working interests in approximately 48 offshore producing fields in federal and state waters (45 producing and three fields capable of producing).  We currently have under lease approximately 650,000 gross acres, with approximately 440,000 gross acres on the shelf and approximately 210,000 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 the parent company, W&T Offshore, Inc., and our wholly-owned subsidiary, W & T Energy VI, LLC, and by Monza, which we proportionately consolidate in our condensed consolidated financial statements.  

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 nine months ended September 30, 2018 were comprised of 49.6% crude oil and condensate, 9.7% NGLs and 40.7% 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 of equivalent (“Boe”) for crude oil, NGLs and natural gas has differed significantly in the past.  For the nine months ended September 30, 2018, revenues from the sale of crude oil and NGLs made up 82.8% of our total revenues compared to 75.7% for the nine months ended September 30, 2017.  For the nine months ended September 30, 2018, our combined total production expressed in equivalent volumes was 9.1% lower than for the nine months ended September 30, 2017, with natural gas having the largest decline.  For the nine months ended September 30, 2018, our total revenues were 22.1% higher than the nine months ended September 30, 2017 due to significantly higher realized prices for crude oil and NGLs.  See Results of Operations – Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017 in this Item 2 for additional information.

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On October 18, 2018, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement, which provides a revolving bank credit facility and letter of credit facility with an increased initial lending commitment and borrowing base of $250.0 million that matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information, including the pro forma impact of the 2018 Refinancing Transaction on our Condensed Consolidated Balance Sheet as of September 30, 2018.

On September 28, 2018, we closed on the divestiture of our overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects in the Gulf of Mexico over the next three years.  We refer to these projects herein as the JV Drilling Program.  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.  The Monza board approved the substitution of one of these identified undeveloped drilling projects, the VK823 A-14 well, with the VK823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well.  The interest in the VK823 A-14 well is in process of being reconveyed to W&T.  Since the initial closing, additional investors have joined as members of Monza and total commitments by all members, including W&T, are $361.4 million.  Monza closed off funding from additional investors during June 2018.  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.  For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well.  See Financial Statements – Note 4 – JV Drilling Program under Part I, Item 1 of this Form 10-Q for additional information.

On April 5, 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and 904.  The gross purchase price was $31.1 million which was adjusted for certain closing items and an effective date of January 1, 2018.  Cash flows generated by the acquired interest between the effective date and the closing date reduced the net purchase price to $16.8 million.  We were required to furnish a letter of credit in the amount of $9.4 million to a pipeline company as consignee.  In addition, we recognized ARO of $3.6 million as a component of the transaction.  

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 nine months ended September 30, 2018, our average realized crude oil price was $66.52 per barrel.  This is an increase over our average realized crude oil price of $45.81 per barrel for the nine months ended September 30, 2017 and an increase over our average realized crude oil price of $48.13 per barrel for the year 2017.  In addition, our average realized prices of NGLs for the nine months ended September 30, 2018 were higher than average realized prices for the nine months ended September 30, 2017 and the year 2017.  

Selected issues and data points related to crude oil, NGLs and natural gas markets are described below.

As reported by the U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in September 2018 (“STEO”), the forecast for global liquid fuels inventories is being relatively stable for 2018 and 2019.  Crude oil prices for 2018 are expected to be above 2017 levels and crude oil prices for 2019 are expected to be relatively equal to 2018.  

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The EIA reported worldwide total crude oil and petroleum liquids inventories have decreased during the first three quarters of 2018 by 0.4 million barrels per day, which is less than 0.5 % of daily production.  In a previous EIA report issued in May 2018, both U.S. and the Organization for Economic Cooperation and Development (“OECD”) commercial crude oil and other liquids inventories were approximately at the same level as the five year average for these categories.  EIA forecasts commercial crude oil and other liquids inventory levels in the U.S. and the OECD to increase in 2019 by 7% and 3%, respectively.  

The EIA forecasts an increase in worldwide production in the fourth quarter of 2018 and in each of the quarters in 2019 to increase quarter over quarter.  Yearly worldwide production for 2018 and 2019 is expected to increase by 2.0% year over year.  The increase is due primarily to increases in production in the U.S., Canada and Brazil.  Consumption for 2018 and 2019 is estimated to increase by 1.5% on a year over year basis, with China, other Asian countries and the U.S. being the primary contributors to the increase in consumption.  

According to EIA’s STEO, 2018 U.S. crude oil production (excluding other petroleum liquids) is expected to increase by 14% over 2017 and increase by 8% in 2019 over 2018 levels.  These production levels have pushed pipeline capacities to the maximum levels in the Permian Basin, which may limit short-term growth until pipeline capacity can be increased.  Net imports of crude oil in the U.S. are expected to decrease by 11% in 2018 compared to 2017 and further decrease by 9% in 2019 compared to 2018.  As noted below, the number of onshore rigs drilling for oil has increased from 2017 levels.  

Geopolitical events could greatly affect the prices for crude oil, natural gas and other petroleum products.  While these events are difficult to predict, countries like Venezuela, Nigeria, Libya, and many Middle East countries have had, and could continue to have, disruptions due to political and economic factors outside of production issues.  

The two primary benchmarks for our average realized crude oil sales prices are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $66.93 per barrel for the nine months ended September 30, 2018, up from $49.30 per barrel (35.8% higher) for the nine months ended September 30, 2017.  Brent crude oil prices averaged $72.17 per barrel for the nine months ended September 30, 2018, up from $51.75 per barrel (39.5% higher) for the nine months ended September 30, 2017.  The rising U.S. crude oil production puts upward price pressure on the Brent-to-WTI premium, which increased 114% to an average of $5.23 per barrel for the nine months ended September 30, 2018 compared to an average of $2.44 per barrel for the nine months ended September 30, 2017.  

For the nine months ended September 30, 2018, our average realized crude oil sales price was $66.52 per barrel compared to a WTI benchmark price of $66.93 per barrel.  Our average realized crude oil sales price differs from the benchmark crude prices 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.  For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Ship Shoal 349 field (“Mahogany”) normally receives a negative quality adjustment.  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 nine months ended September 30, 2018 improved on average by approximately $2.00 per barrel compared to the nine months ended September 30, 2017 for these types of crude oils.  

Despite the projection by the EIA that crude oil inventories will remain fairly level on an end-of-year comparison for 2018 to 2017, the EIA projects average crude oil prices for both WTI and Brent to increase by approximately $16.00 and $19.00 per barrel, respectively, for the year 2018 compared to 2017.  EIA’s forecast of crude oil prices for both WTI and Brent are expected to be relatively flat for the year 2019 compared to 2018.  EIA projects that worldwide demand is forecasted to increase approximately 1.5% year-over-year for both 2018 and 2019.  

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During the nine months ended September 30, 2018, our average realized NGLs sales price increased by 32.1% compared to the nine months ended September 30, 2017.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During the nine months ended September 30, 2018, average prices for domestic ethane increased by 21% and average domestic propane prices increased by 28% from the nine months ended September 30, 2017.  Average price changes for other domestic NGLs components increased 19% to 37% between the two periods.  We believe the increase in prices for NGLs is mostly a function of the change in crude oil prices and propane usage during the recent winter season.  Per EIA, production of ethane is expected to increase by 20% in 2018 compared to 2017 and increase by 12% in 2019 compared to 2018.  Propane production is expected to increase by 10% in 2018 compared to 2017 and by 9% in 2019 compared to 2018.  Ethane inventories decreased 11% as of September 2018 compared to September 2017.  Ethane usage is not impacted by weather, but primarily by demand from petrochemical plants.  Additional ethane steam crackers coming on line is impacting the usage of ethane, which is believed to positively impact the price.  Propane usage is affected by weather as it is used for house heating fuel in certain areas and for crop drying, along with other uses.  Propane inventory levels are 7% higher at the end of the third quarter of 2018 compared to the same period last year.  Heating degree days were 16% higher in the first half of 2018 compared to the same period last year.

During the nine months ended September 30, 2018, our average realized natural gas sales price decreased 2.4% compared to the nine months ended September 30, 2017.  According to data from EIA’s web site, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 3.6% lower in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  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.  Natural gas inventories at the end of the third quarter of 2018 were 17% lower than the prior year period and were 14% below the five-year average for the previous five years.  

Despite good demand for natural gas, the average price of natural gas continues to be weak from an overall economic standpoint as to making an adequate rate of return on wells that produce only natural gas.  The forward price curve that goes out several years shows natural gas prices below $3.00 per Mcf.  Accordingly, the market expects continued weakness in natural gas prices for a number of reasons, including (i) producers continuing 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 from time to time into the natural gas stream, which increases the natural gas supply.

EIA projects natural gas prices to be flat in 2018 compared to 2017 and to increase 4% in 2019 compared to 2018.  U.S. supply is projected to be lower than consumption in 2018 and 2019, resulting in inventory withdrawals.  EIA’s forecast of fuel used for electrical power generation has natural gas consumption increasing in 2018 to 34% from 32% in 2017, and further increasing in 2019 to 35%.  Electrical power generation from coal is forecast to decrease to 28% in 2018 from 30% in 2017.  Electrical power from renewable sources such as hydropower and wind is expected to be 17% in both 2018 and 2017.  

As of September 30, 2018, the number of working rigs drilling for oil and natural gas in the U.S. was higher than year ago levels for land based rigs (increase of 113 rigs, or 12%), but lower in offshore waters (decrease of two rigs or 10%).  According to Baker Hughes, the oil rig count at the end of September 2018, December 2017 and September 2017 was 863, 747 and 750, respectively.  The U.S. natural gas rig count at the end of September 2018, December 2017 and September 2017 was 189, 182 and 189, respectively.  In the Gulf of Mexico, the number of working rigs was 18 rigs (16 oil and two natural gas rigs) at the end of September 2018; 18 rigs (14 oil and four natural gas) at the end of December 2017; and 22 rigs (18 oil and four natural gas rigs) at the end of September 2017.

With the completion of the 2018 Refinancing Transaction, our capital structure and liquidity has improved substantially from the prior quarter.  Subsequent to the 2018 Refinancing Transaction, our liquidity was over $200 million, which consisted of cash on hand and availability on our New Revolving Credit Agreement.  See the Liquidity and Capital Resources section of this Item 2 for a discussion of our current liquidity position.  

Our current 2018 capital expenditure forecast for 2018 is approximately $95 million, which excludes the Heidelberg field transaction and excludes other potential acquisitions.  The forecast also incorporates our capital spending relating to the JV Drilling Program (net to our interest).  Our 2018 capital expenditure program includes participation in 10 wells, seven of which are included in the 2018 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.  

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Our current focus is on making profitable investments with short payback time frames while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our obligations.  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, 2017, 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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Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues.  Total revenues increased $43.2 million, or 39.2%, to $153.5 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.  Oil revenues increased $41.4 million, or 53.1%, NGLs revenues increased $3.5 million, or 52.7%, natural gas revenues decreased $1.5 million, or 6.1%, and other revenues decreased $0.3 million.  The increase in oil revenues was attributable to a 51.5% increase in the average realized sales price to $69.57 per barrel for the three months ended September 30, 2018 from $45.92 per barrel for the three months ended September 30, 2017 and sales volumes increased 1.0%.  The increase in NGLs revenues was attributable to a 43.6% increase in the average realized sales price to $31.70 per barrel for the three months ended September 30, 2018 from $22.07 per barrel for the three months ended September 30, 2017 and sales volumes increased 6.4%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 0.2 billion cubic feet (“Bcf”), or 2.3% and a 4.0% decrease in the average realized price to $2.85 per Mcf for the three months ended September 30, 2018 from $2.97 per Mcf for the three months ended September 30, 2017.  Overall, production volumes increased 0.1% on a Boe basis.  The largest production increases for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 were from our newly acquired interest in the Heidelberg field and our Ship Shoal 300 field.  Offsetting were production decreases primarily due to natural production declines.  Production for the three months ended September 30, 2018 was also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,100 Boe per day.  During the three months ended September 30, 2017, deferred production was 6,100 Boe per day.

Revenues from oil and NGLs as a percent of our total revenues were 84.4% for the three months ended September 30, 2018 compared to 76.8% for the three months ended September 30, 2017.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 45.6% for the three months ended September 30, 2018 compared to 48.1% for the three months ended September 30, 2017.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers, and facilities maintenance, increased $2.3 million, or 6.5%, to $37.4 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017.  On a component basis, base lease operating expenses increased $0.5 million, insurance premiums increased $0.4 million, workover expenses increased $2.2 million, and facilities maintenance expense decreased $0.8 million.  Base lease operating expenses increased primarily due to the addition of the Heidelberg field, and lower product handling and operating charges to an outside party at our Mississippi Canyon 243 field (Matterhorn).  The insurance premium increase is primarily due to timing differences on our pro-rata share of insurance premiums related to the Thunder Hawk platform, which services the Mississippi Canyon 698 (Big Bend) and Mississippi Canyon 782 (Dantzler) fields.  The increase in workover expense was primarily due to a 2018 project at our Mahogany field.  The facility maintenance expense decrease was primarily attributable to work performed in 2017 at our Mississippi Canyon 243 field (Matterhorn), which was partially offset by projects with lower overall costs undertaken in 2018.  

Production taxes.  Production taxes increased $0.1 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017.  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.  

Gathering and transportation.  Gathering and transportation expenses increased $1.7 million to $5.8 million for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 primarily related to the Heidelberg field, where we are required to pay additional amounts if throughputs are below minimums quantities.  

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, increased to $11.01 per Boe for the three months ended September 30, 2018 from $10.88 per Boe for the three months ended September 30, 2017.  On a nominal basis, DD&A increased to $37.0 million (or 1.3%) for the three months ended September 30, 2018 from $36.5 million for the three months ended September 30, 2017.  DD&A on a nominal basis increased primarily due to revisions in future development costs.  Other factors affecting the DD&A rate are production, capital expenditures, sales of assets and changes in proved reserves volumes.    

General and administrative expenses (“G&A”).  G&A was $16.0 million for the three months ended September 30, 2018, increasing 2.3% from $15.6 million for the three months ended September 30, 2017.  The increase was primarily due to an accrual for an executive’s anticipated separation settlement, increases in medical claims and buyout of an office lease.  G&A on a per Boe basis was $4.76 per Boe for the three months ended September 30, 2018 compared to $4.66 per Boe for the three months ended September 30, 2017.

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Derivative (gain) loss. We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production. The three months ended September 30, 2018 reflects a $0.3 million derivative gain.  We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production. The three months ended September 30, 2017 reflects a $2.9 million derivative loss primarily for our crude oil derivative contracts.  

Interest expense.  Interest expense was $11.6 million for both three months periods ended September 30, 2018 and 2017.  See Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on our debt.   

Other (income) expense, net.  During the three months ended September 30, 2018, other income, net, was $0.9 million primarily due to interest income.  

Income tax expense. Our income tax expense for the three months ended September 30, 2018 and 2017 was $0.1 million and $5.5 million, respectively.  Based on a full year forecast, we are not expecting any current income tax expense. Immaterial deferred income tax expense was recorded for the three months ended September 30, 2018 due to dollar-for-dollar offsets by our valuation allowance.  The income tax expense for the three months ended September 30, 2017 relates to revisions under GAAP using the annualized effective tax rate method in computing income tax expense or benefit for interim periods.  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.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues.  Total revenues increased $79.3 million, or 22.1%, to $437.3 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.  Oil revenues increased $84.8 million, or 34.1%, NGLs revenues increased $6.1 million, or 27.1%, natural gas revenues decreased $11.6 million, or 14.0%, and other revenues increased $0.1 million.  The increase in oil revenues was attributable to a 45.2% increase in the average realized sales price to $66.52 per barrel for the nine months ended September 30, 2018 from $45.81 per barrel for the nine months ended September 30, 2017, partially offset by a decrease in sales volumes of 7.7%.  The increase in NGLs revenues was attributable to a 32.1% increase in the average realized sales price to $28.91 per barrel for the nine months ended September 30, 2018 from $21.88 per barrel for the nine months ended September 30, 2017, partially offset by a decrease in sales volumes of 3.8%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 3.4 Bcf, or 12.0% and a 2.4% decrease in the average realized price to $2.90 per Mcf for the nine months ended September 30, 2018 from $2.97 per Mcf for the nine months ended September 30, 2017.  Overall, production volumes decreased 9.1% on a Boe basis. The largest production increases for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 were from our newly acquired interest in the Heidelberg field and our Ship Shoal 300 field.  Revenue and production was adjusted for royalty relief on two of our deepwater fields related to their 2017 and 2016 production and realized prices which is recognized in the subsequent year.  This royalty relief impact to revenues during the nine months ended September 30, 2018 and 2017 was $1.0 million and $5.0 million, respectively.  Offsetting were production decreases primarily due to natural production declines.  Production for the nine months ended September 30, 2018 was also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,300 Boe per day.  During the nine months ended September 30, 2017, deferred production was 3,800 Boe per day.

Revenues from oil and liquids as a percent of our total revenues were 82.8% for the nine months ended September 30, 2018 compared to 75.7% for the nine months ended September 30, 2017.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 43.5% for the nine months ended September 30, 2018 compared to 47.8% for the nine months ended September 30, 2017.   

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Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers, and facilities maintenance, increased $3.0 million, or 2.8%, to $109.9 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  On a component basis, base lease operating expenses increased $2.0 million, insurance premiums increased $1.7 million, workover expenses increased $0.3 million, and facilities maintenance expense decreased $1.0 million.  Base lease operating expenses increased primarily due the addition of the Heidelberg field; lower product handling and operating charges to an outside party at our Matterhorn field and higher incentive compensation expenses.  The insurance premium increase is primarily due to our insurance policies related to named windstorms, which had better coverage in 2018 compared to the 2017 period.  The facility maintenance expense decrease is primarily attributable to compressor overhauls and pipeline projects in 2017, which did not re-occur at the same expense level during 2018.  

Production taxes.  Production taxes were basically flat for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  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.  

Gathering and transportation.  Gathering and transportation expenses increased $0.1 million to $15.8 million for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 primarily related to the Heidelberg field, where we are required to pay additional amounts if throughputs are below minimums quantities defined in the contract and were partially offset by lower expenses from lower production volumes.  

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, increased to $11.36 per Boe for the nine months ended September 30, 2018 from $10.51 per Boe for the nine months ended September 30, 2017.  On a nominal basis, DD&A decreased to $114.8 million (1.7%) for the nine months ended September 30, 2018 from $116.8 million for the nine months ended September 30, 2017.  DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are capital expenditures, sales of assets, changes in future development costs on remaining reserves and an increase in proved reserves volumes.    

General and administrative expenses.  G&A was $45.2 million for the nine months ended September 30, 2018, essentially flat compared to the nine months ended September 30, 2017.  Decreases in lawsuit settlements were offset by an accrual for an executive’s anticipated separation settlement, increases in medical claims and buyout of an office lease.  G&A on a per Boe basis was $4.48 per Boe for the nine months ended September 30, 2018 compared to $4.08 per Boe for the nine months ended September 30, 2017.

Derivative (gain) loss. We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production. The nine months ended September 30, 2018 reflects a $5.9 million derivative loss.  We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production. The nine months ended September 30, 2017 reflects a $4.8 million derivative gain primarily for our crude oil derivative contracts.  

Interest expense.  Interest expense was $35.1 million and $34.3 million for the nine months ended September 30, 2018 and 2017, respectively.  The increase is primarily due to an interest accrual related to a royalty issue with the ONRR on production that dates back 10 to 15 years.  See Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on our debt.   

Gain on exchange of debt.  During the nine months ended September 30, 2017, an additional net gain of $7.8 million was recognized primarily as a result of paying interest in cash on the Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes versus paying the interest in kind.  The cash interest payments on Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes lowered the carrying value of the respective notes under ACS 470-60, resulting in the recognition of a non-cash gain.  The cash payments have a lower interest rate compared to the PIK option and this also reduced future interest and principal payments.  Partially offsetting were additional expenses related to the 2016 Restructuring Transactions for differences between estimated and actual expense.    

Other income (expense), net.  During the nine months ended September 30, 2018, other income, net, was $1.1 million primarily due to interest income.  During the nine months ended September 30, 2017, other expense, net, was $5.1 million and consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million.  See Financial Statements - Note 11– Contingencies under Part I, Item 1 of this Form 10-Q for additional information on the Apache lawsuit.  

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Income tax expense (benefit). Our income tax expense for the nine months ended September 30, 2018 was $0.4 million and our income tax benefit for the nine months ended September 30, 2017 was $11.1 million.  Based on a full year forecast, we are not expecting any current income tax expense.  Immaterial deferred income tax expense was recorded for the nine months ended September 30, 2018 due to dollar-for-dollar offsets by our valuation allowance.  The income tax benefit for the nine months ended September 30, 2017 relates to net operating loss carryback claims made pursuant to rules for “specified liability losses”.  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.  See Financial Statements – Note 9 –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 asset retirement obligations.  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.  

If commodity prices were to return to the weaker levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could have a significant adverse effect on our liquidity.  In addition, other events outside of our control could significantly affect our liquidity such as changes in regulations or the interpretation of existing regulations.  

On October 18, 2018, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement which provides a revolving bank credit facility and letter of credit facility with an increased initial borrowing base of $250.0 million and matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs. See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information, including the pro forma impact of the 2018 Refinancing Transaction on our Condensed Consolidated Balance Sheet as of September 30, 2018.

New Revolving Credit Agreement.  Subsequent to the issuance of the Senior Second Lien Notes and repayment of the existing notes and loans outstanding, we had $61.0 outstanding borrowings under the New Revolving Credit Agreement, $9.7 million of letters of credit outstanding and $179.3 million availability.  We will be subject to the normal re-determination of our borrowing base in the spring of 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our New Revolving Credit Agreement.  The New Revolving Credit Agreement’s security is collateralized by substantially all of our oil and natural gas properties and certain personal property.  The New Revolving 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 New Revolving Credit Agreement.  We were in compliance with all applicable covenants of the Prior Credit Agreement and other long-term debt instruments as of September 30, 2018 and after the 2018 Refinancing Transaction under the New Revolving Credit Agreement and the Senior Second Lien Notes.

BOEM Matters.  As of the filing date of this Form 10-Q, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to financial assurance obligations.  During April 2018, we posted an additional $10.6 million of bonds as requested by BOEM to account for decommissioning obligations that accrued on sole-liability properties during the Company’s period of leasing.  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 2018 as of the filing date of the Form 10-Q.

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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 nine months ended September 30, 2018 was $294.9 million compared to $130.3 million, or 126%, for the nine months ended September 30, 2017.  The change between periods is primarily due to higher realized prices for crude oil and NGLs, lower spending for ARO activities and working capital changes.  Our combined average realized sales price per Boe increased 34.7% in the nine months ended September 30, 2018, which caused total revenues to increase $109.0 million, partially offset by decreases of 9.1% in production volumes which caused revenues to decrease by $29.8 million.  

Other items affecting operating cash flows for the nine months ended September 30, 2018 were ARO settlements of $22.8 million, which decreased from $56.2 million in the prior period and cash advances from joint venture partners increased $27.0 million.  During the nine months ended September 30, 2017, we received insurance reimbursements of $31.7 million and made a deposit related to the Apache matter of $49.5 million.  Working capital items and advances from joint interest partners accounted for the balance of the change in net cash provided by operating activities.  

Net cash used in investing activities during the nine months ended September 30, 2018 and 2017 was $45.7 million and $74.3 million, respectively, which represents our investments in oil and gas properties and equipment.  Investments in oil and natural gas properties on an accrual basis in the nine months ended September 30, 2018 were $59.2 million compared to $79.1 million for the nine months ended September 30, 2017.  The majority of our capital expenditures for the nine months ended September 30, 2018 related to investments on the conventional shelf in the Gulf of Mexico and, to a lesser extent, in the deep waters of the Gulf of Mexico.  Adjustments from working capital changes associated with investing activities was a net cash decrease of $20.3 million in the nine months ended September 30, 2018 compared to net cash increase of $5.7 million in the nine months ended September 30, 2017.  These amounts represent timing differences between when the work was performed and the payments are made.  The net purchase price for the acquisition of the Heidelberg field was $16.8 million, which was acquired during the nine months ended September 30, 2018 and there were no similar investments in the prior year period.  The sale of our overriding royalty interests in the Permian Basis fields resulted in net proceeds of $50.5 million and there were no asset sales in the prior year period.

Net cash used by financing activities for the nine months ended September 30, 2018 and 2017 was $9.1 million and $20.1 million, respectively. The net cash used for the nine months ended September 30, 2018 and 2017 was primarily attributable to the interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes, which are reported as financing activities under ASC 470-60.    

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 New Revolving Credit Agreement.  During the second quarter of 2018, we entered into derivative contracts for crude oil which relate to volumes of 11,000 barrels per day through December 2018.  See Financial Statements – Note 7 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  Under the New Revolving Credit Agreement, by December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  See Financial Statements – Note 12 – Subsequent Events 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.

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Our general and excess liability policies are effective for one year beginning May 1, 2018 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, 2018, and our Energy Package effective on June 1, 2018, 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 nine months ended September 30, 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 on an accrual basis for exploration, development and other leasehold costs:  

The following table presents our exploration and development capital expenditures on an accrual basis geographically in the Gulf of Mexico:

Our capital expenditures for the nine months ended September 30, 2018 were financed by cash flow from operations and cash on hand.  

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During the nine months ended September 30, 2018, we completed the A-17 well at Mahogany, which began producing during March 2018, the Viosca Knoll 823 (“Virgo”) A-10 ST well, which began production during April 2018, the Mahogany A-5 ST 2 well, which began producing in July 2018, and the Virgo A-12 well, which began producing in September.  The Virgo A-10 ST well, the Mahogany A-5 ST2 well, and the Virgo A-12 well are in the JV Drilling Program.  During the nine months ended September 30, 2017, we completed three wells.  We did not drill any dry holes in either period.  

Exploration/Development Activities.  As of October 31, 2018, we were drilling on the Virgo A-13 well and were in the completion phase for the South Timbalier 311 A-2 well.  The Main Pass 286 #1 well has been cased and is waiting for development sanction.  These three wells are in the JV Drilling Program.  In addition, we are completing the A-19 well at Mahogany, which is not in the JV Drilling Program.

Offshore Lease Awards.  During the nine months ended September 30, 2018, we were successful in obtaining nine new leases in the Central and Eastern Gulf of Mexico.  The new leases are primarily located near or offsetting our existing properties and were acquired in total for less than $1.0 million, net to our interest.  Subsequently in October 2018, we received preliminary notice of being successful in obtaining eight additional leases, which were acquired in total for $1.0 million, net to our interest.  We expect to receive official notice related to these eight leases within the next 90 days.

Acquisitions.  In April 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and 904.  After effective date and closing adjustments, the net purchase price was $16.8 million.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

Divestitures.  Periodically, we sell properties as part of the management of our property portfolio.  In September 2018, we closed on the divestiture of our overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

Capital Expenditure Budget.  Our current 2018 capital expenditure forecast is approximately $95 million, which excludes the Heidelberg field transaction and excludes other potential acquisitions.  The forecast incorporates the shared investments in certain wells included in the JV Drilling Program.  Our 2018 capital expenditure program includes participation in 10 wells, seven of which are 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 September 30, 2018, we have current income tax receivables of $65.2 million.  The current income tax receivables include an estimated net operating loss claim for 2017 of $13.1 million; $11.1 million of the refund is expected to be received during 2018 with the remainder expected thereafter.  The other component of current income tax receivables relates to our net operating loss claims totaling $52.1 million for the years 2012, 2013 and 2014 that were carried back to prior years and are expected to be received during the first half of 2019.  These receivables relate to claims under rules for “specified liability losses” made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  For 2018, we do not expect to make any significant income tax payments.  See Financial Statements – Note 9 –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 September 30, 2018 and December 31, 2017 were $313.2 million and $300.4 million, respectively.  Our plans include spending $30.6 million in 2018 for ARO compared to $72.4 million spent on ARO in 2017.  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, 2017 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 6 – Asset Retirement Obligations, and under Part I, Item 1 of this Form 10-Q. As of September 30, 2018, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $5.7 million which was the same amount as of December 31, 2017.  In conjunction with the purchase of the Heidelberg field interest, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.  Except for scheduled utilization, other contractual obligations as of September 30, 2018 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, 2017.

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, 2017.  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 nine months ended September 30, 2018 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, 2017.  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, 2017.  

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 the second quarter of 2018, we entered into derivative crude oil contracts related to a portion of our estimated production for the remainder of 2018.  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 7 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  Under the New Revolving Credit Agreement, by December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.    

Interest Rate Risk.  As of September 30, 2018, we had no borrowings outstanding under our Prior Credit Agreement.  The Prior Credit Agreement had a variable interest rate, which is primarily impacted by the London Interbank Offered Rate and the margin, which ranged from 3.00% to 4.00% depending on the amount of utilization.  As of September 30, 2018, we did not have any derivative instruments related to interest rates.  As of October 18, 2018, we had $61.0 million borrowings outstanding under the New Revolving Credit Agreement.  As of October 31, 2018, we had $61.0 million of borrowings outstanding on the New Revolving Credit Agreement subject to the variable London Interbank Offered Rate and the Applicable Margin and 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 September 30, 2018, 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 September 30, 2018, 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.  

 

 

PART II – OTHER INFORMATION

 

Item 1.  Legal Proceedings

See Financial Statements – Note 11 – Contingencies, under Part I Item 1 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, 2017, 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, 2017 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, 2017.

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Item 5.  Other Information  

Certain entities controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the 2018 Refinancing Transaction.  The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes.  On October 31, 2018, the Audit Committee of the Company waived any application of the insider trading policy in the Company’s Code of Business Conduct and Ethics to these transactions as being unnecessary in light of the full disclosures made in connection with the offering of the Senior Second Lien Notes as part of the 2018 Refinancing Transaction.  As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan liquidated as the loan was repaid in full.

 

 

 

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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 November 1, 2018.

 

 

 

 

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