UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


Form 10-Q

 


 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to ________________

Commission File Number 1-32414


W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Texas

72-1121985

(State of incorporation)

(IRS Employer Identification Number)

   

Nine Greenway Plaza, Suite 300, Houston, Texas

77046-0908

(Address of principal executive offices)

(Zip Code)

(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.

 

Large accelerated filer ☐

 

Accelerated filer

Non-accelerated filer ☐

 

Smaller reporting company

   

Emerging growth company

 

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. ☐

 

Securities registered pursuant to section 12(b) of the Act:

         

Title of each class

 

Trading Symbol(s)

 

Name of each exchange on which registered

Common Stock, par value $0.00001

 

WTI

 

New York Stock Exchange

 

As of October 29, 2019, there were 140,690,393 shares outstanding of the registrant’s common stock, par value $0.00001.

 



 

 

 

 

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

 

   

Page

PART I –FINANCIAL INFORMATION

 
     

Item 1.

Financial Statements

1
 

Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018

1
 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018

2
 

Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended September 30, 2019 and 2018 

3
 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018

4
 

Notes to Condensed Consolidated Financial Statements

5

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

19

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

26

Item 4.

Controls and Procedures

26
   

PART II – OTHER INFORMATION

 

Item 1.

Legal Proceedings

27

Item 1A.

Risk Factors

27

Item 6.

Exhibits

27
   

SIGNATURE

28

 

 

 

 

PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Assets

               

Current assets:

               

Cash and cash equivalents

  $ 41,741     $ 33,293  

Receivables:

               

Oil and natural gas sales

    51,626       47,804  

Joint interest and other, net

    30,484       14,634  

Income taxes

    36,910       54,076  

Total receivables

    119,020       116,514  

Prepaid expenses and other assets (Note 1)

    40,221       76,406  

Total current assets

    200,982       226,213  
                 

Oil and natural gas properties and other, net - at cost (Note 1)

    720,951       515,421  

Restricted deposits for asset retirement obligations

    16,694       15,685  

Deferred income taxes

    55,579        

Other assets (Note 1)

    32,864       91,547  

Total assets

  $ 1,027,070     $ 848,866  

Liabilities and Shareholders’ Deficit

               

Current liabilities:

               

Accounts payable

  $ 105,922     $ 82,067  

Undistributed oil and natural gas proceeds

    25,550       28,995  

Advances from joint interest partners

    36,473       20,627  

Asset retirement obligations

    23,095       24,994  

Accrued liabilities (Note 1)

    37,254       29,611  

Total current liabilities

    228,294       186,294  
                 

Long-term debt

    718,949       633,535  

Asset retirement obligations, less current portion

    321,400       285,143  

Other liabilities (Note 1)

    16,267       68,690  

Commitments and contingencies

           

Shareholders’ deficit:

               

Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued for both dates presented

           

Common stock, $0.00001 par value; 200,000 shares authorized; 143,560 issued and 140,690 outstanding on September 30, 2019 and 143,513 issued and 140,644 outstanding on December 31, 2018

    1       1  

Additional paid-in capital

    548,134       545,705  

Retained deficit

    (781,808 )     (846,335 )

Treasury stock, at cost; 2,869 shares for both dates presented

    (24,167 )     (24,167 )

Total shareholders’ deficit

    (257,840 )     (324,796 )

Total liabilities and shareholders’ deficit

  $ 1,027,070     $ 848,866  

 

 

See Notes to Condensed Consolidated Financial Statements

 

 

1

Table of Contents

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

 

    Three Months Ended September 30,     Nine Months Ended September 30,  
   

2019

   

2018

   

2019

   

2018

 

Revenues:

                               

Oil

  $ 102,786     $ 119,482     $ 298,684     $ 333,406  

NGLs

    4,373       10,087       15,461       28,481  

Natural gas

    23,686       22,641       65,091       71,485  

Other

    1,376       1,249       3,766       3,912  

Total revenues

    132,221       153,459       383,002       437,284  

Operating costs and expenses:

                               

Lease operating expenses

    47,185       37,430       130,982       109,855  

Production taxes

    588       432       1,321       1,326  

Gathering and transportation

    5,955       5,779       19,446       15,764  

Depreciation, depletion, amortization and accretion

    38,841       36,969       110,680       114,807  

General and administrative expenses

    10,106       15,990       37,543       45,248  

Derivative (gain) loss

    (5,853 )     (288 )     41,228       5,931  

Total costs and expenses

    96,822       96,312       341,200       292,931  

Operating income

    35,399       57,147       41,802       144,353  

Interest expense, net

    14,445       10,727       42,934       33,475  

Other expense, net

    555       18       1,364       532  

Income (loss) before income tax (benefit) expense

    20,399       46,402       (2,496 )     110,346  

Income tax (benefit) expense

    (55,500 )     142       (67,023 )     363  

Net income

  $ 75,899     $ 46,260     $ 64,527     $ 109,983  

Basic and diluted earnings per common share

  $ 0.53     $ 0.32     $ 0.45     $ 0.76  

 

See Notes to Condensed Consolidated Financial Statements.

 

2

Table of Contents

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)

 

 

   

Common Stock Outstanding

   

Additional Paid-In

   

Retained

   

Treasury Stock

   

Total Shareholders’

 
   

Shares

   

Value

   

Capital

   

Deficit

   

Shares

   

Value

   

Deficit

 

Balances, June 30, 2019

    140,690     $ 1     $ 546,886     $ (857,707 )     2,869     $ (24,167 )   $ (334,987 )

Share-based compensation

                1,248                         1,248  

Net income

                      75,899                   75,899  

Balances, September 30, 2019

    140,690     $ 1     $ 548,134     $ (781,808 )     2,869     $ (24,167 )   $ (257,840 )

 

 

   

Common Stock Outstanding

   

Additional Paid-In

   

Retained

   

Treasury Stock

   

Total Shareholders’

 
   

Shares

   

Value

   

Capital

   

Deficit

   

Shares

   

Value

   

Deficit

 

Balances, June 30, 2018

    139,154     $ 1     $ 548,196     $ (1,031,439 )     2,869     $ (24,167 )   $ (507,409 )

Share-based compensation

                1,373                         1,373  

Net income

                      46,260                   46,260  

Balances, September 30, 2018

    139,154     $ 1     $ 549,569     $ (985,179 )     2,869     $ (24,167 )   $ (459,776 )

 

 

   

Common Stock Outstanding

   

Additional Paid-In

   

Retained

   

Treasury Stock

   

Total Shareholders’

 
   

Shares

   

Value

   

Capital

   

Deficit

   

Shares

   

Value

   

Deficit

 

Balances, December 31, 2018

    140,644     $ 1     $ 545,705     $ (846,335 )     2,869     $ (24,167 )   $ (324,796 )

Share-based compensation

                2,429                         2,429  

Stock Issued

    46                                      

Net income

                      64,527                   64,527  

Balances, September 30, 2019

    140,690     $ 1     $ 548,134     $ (781,808 )     2,869     $ (24,167 )   $ (257,840 )

 

 

   

Common Stock Outstanding

   

Additional Paid-In

   

Retained

   

Treasury Stock

   

Total Shareholders’

 
   

Shares

   

Value

   

Capital

   

Deficit

   

Shares

   

Value

   

Deficit

 

Balances, December 31, 2017

    139,091     $ 1     $ 545,820     $ (1,095,162 )     2,869     $ (24,167 )   $ (573,508 )

Share-based compensation

                3,808                         3,808  
Stock Issued     63                                      
RSUs surrendered for payroll taxes (1)                 (59 )                       (59 )

Net income

                      109,983                   109,983  

Balances, September 30, 2018

    139,154     $ 1     $ 549,569     $ (985,179 )     2,869     $ (24,167 )   $ (459,776 )

 

(1) RSUs defined in Note 9.

 

See Notes to Condensed Consolidated Financial Statements

 

3

Table of Contents

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

   

Nine Months Ended

 
   

September 30,

 
   

2019

   

2018

 

Operating activities:

               

Net income

  $ 64,527     $ 109,983  

Adjustments to reconcile net income to net cash provided by operating activities:

               

Depreciation, depletion, amortization and accretion

    110,680       114,807  

Amortization of debt items and other items

    3,914       1,796  

Share-based compensation

    2,429       3,808  

Derivative loss

    41,228       5,931  

Cash receipts (payments) on derivative settlements, net

    17,583       (3,091 )
Income taxes     (55,764 )     363  

Changes in operating assets and liabilities:

               

Oil and natural gas receivables

    (3,822 )     (4,039 )

Joint interest receivables

    (15,850 )     3,261  

Prepaid expenses and other assets

    (14,211 )     (8,467 )

Income tax receivables

    17,165       (139 )

Asset retirement obligation settlements

    (7,740 )     (22,764 )

Cash advances from JV partners

    15,847       27,014  

Accounts payable, accrued liabilities and other

    10,610       66,389  

Net cash provided by operating activities

    186,596       294,852  

Investing activities:

               

Investment in oil and natural gas properties and equipment

    (93,482 )     (79,422 )

Acquisition of property interest

    (167,718 )     (16,782 )
Proceeds from sale of assets           50,474  
Purchases of furniture, fixtures and other     (20 )      

Net cash used in investing activities

    (261,220 )     (45,730 )

Financing activities:

               
Borrowings of long-term debt - revolving bank credit facility     150,000        
Repayments of long-term debt - revolving bank credit facility     (66,000 )      

Payment of interest on 1.5 Lien Term Loan

          (6,171 )
Payment of interest on 2nd Lien PIK Toggle Notes           (2,920 )

Debt issuance costs and other

    (928 )     (26 )

Net cash provided by (used in) financing activities

    83,072       (9,117 )

Increase in cash and cash equivalents

    8,448       240,005  

Cash and cash equivalents, beginning of period

    33,293       99,058  

Cash and cash equivalents, end of period

  $ 41,741     $ 339,063  

 

See Notes to Condensed Consolidated Financial Statements.

 

4

Table of Contents

 

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 the Company and its 100%-owned subsidiary, W & T Energy VI, LLC, and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 4.

 

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

 

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year.  These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

 

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

 

Leases.  In February 2016, Accounting Standards Update 2016-02, Leases (Topic 842) (“ASU 2016-02”) was issued requiring an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases.  The classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses.  ASU 2016-02 also requires certain quantitative and qualitative disclosures about leasing arrangements.  Leases acquired to explore for or extract oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of this standard’s update.  ASU 2016-02 was effective for us in the first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1,2019.  Consequently, upon transition, we recognized an ROU asset and a lease liability with no retained earnings impact.  See Note 8 for additional information.

 

 

 

5

 

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

 

 

 

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

 

Reclassifications.  Certain reclassifications have been made to the prior period financial statements to conform to the current presentation as follows: In the Condensed Consolidated Statements of Operations, interest income was reclassified from Other expense, net to Interest expense, net, which did not change Income (loss) before income tax (benefit) expense.  In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net cash provided by operating activities and Net cash used in investing activities sections, of which did not change the total amounts previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets.

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Derivative assets (1)

  $ 23,150     $ 60,687  

Unamortized bond/insurance premiums

    5,497       5,197  

Prepaid deposits related to royalties

    8,794       8,872  

Other

    2,780       1,650  

Prepaid expenses and other assets

  $ 40,221     $ 76,406  

 

 

 

(1)

Includes closed contracts which have not yet settled.

 

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):

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Oil and natural gas properties and equipment

  $ 8,471,973     $ 8,169,871  

Furniture, fixtures and other

    20,247       20,228  

Total property and equipment

    8,492,220       8,190,099  

Less accumulated depreciation, depletion and amortization

    7,771,269       7,674,678  

Oil and natural gas properties and other, net

  $ 720,951     $ 515,421  

 

 

6

 

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

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Appeal bond deposits

  $ 6,925     $ 6,925  

Unamortized debt issuance costs

    4,138       4,773  

Investment in White Cap, LLC

    2,885       2,586  

Unamortized brokerage fee for Monza

    4,131       2,277  

Proportional consolidation of Monza's other assets (Note 4)

    3,660       3,275  
Right-of Use (Note 8)     10,239        

Escrow deposit - Apache lawsuit (Note 12)

          49,500  

Derivative assets

          21,275  

Other

    886       936  

Total other assets (long-term)

  $ 32,864     $ 91,547  

 

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Accrued interest

  $ 25,414     $ 12,385  

Accrued salaries/payroll taxes/benefits

    2,267       2,320  

Incentive compensation plans

    3,667       10,817  

Litigation accruals

    3,673       3,673  
Lease liability (Note 8)     1,877        

Other

    356       416  

Total accrued liabilities

  $ 37,254     $ 29,611  

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Dispute related to royalty deductions

  $ 4,687     $ 4,687  

Dispute related to royalty-in-kind

    2,231       2,135  

Apache lawsuit (Note 12)

          49,500  

Uncertain tax positions including interest/penalties

          11,523  
Lease liability (Note 8)     7,883        

Other

    1,466       845  

Total other liabilities (long-term)

  $ 16,267     $ 68,690  

 

 

Recent Accounting Developments.

 

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (“ASU 2016-13”) and subsequently issued additional guidance on this topic.  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 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.  Our assessment is this amendment will not have a material impact 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”) and subsequently issued additional guidance on this topic.  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.

 

In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification, which revised Regulation S-X, Rule 3-04, Changes in Stockholders’ Equity and Noncontrolling Interests.  The new requirement for registrants is to include a reconciliation of changes in stockholders’ equity (deficit) in interim periods for each period that for which a statement of operations is required to be filed.  The new requirement became effective for us for the quarter ended March 31, 2019.

 

7

 

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

 

 

2.

Long-Term Debt

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Credit Agreement borrowings

  $ 105,000     $ 21,000  
                 

Senior Second Lien Notes:

               

Principal

    625,000       625,000  

Unamortized debt issuance costs

    (11,051 )     (12,465 )

Total Senior Second Lien Notes

    613,949       612,535  
                 

Total long-term debt

  $ 718,949     $ 633,535  

 

 

Credit Agreement

 

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

 

 

The borrowing base and lending commitment was $250.0 million as of the filing date of this Form 10-Q.

 

 

Letters of credit may be issued in amounts up to $30.0 million, provided availability under the Credit Agreement exists.  As of September 30, 2019 and December 31, 2018, we had $7.2 million and $9.6 million, respectively, of letters of credit issued and outstanding under the Credit Agreement.

 

 

The Leverage Ratio is limited to 3.25 to 1.00 for the quarter ending September 30, 2019; and 3.00 to 1.00 for the quarters ending December 31, 2019 and thereafter.  In the event of a Material Acquisition (which includes our August 2019 acquisition of the Mobile Bay properties described in Note 7), the Leverage Ratio limit is 3.50 to 1.00 for the two quarters following a Material Acquisition.

 

 

The Current Ratio must be maintained at greater than 1.00 to 1.00.

 

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on or before May 15 and November 14 each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company.  The borrowing base has not changed from the initial amount.  The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement.  The Credit Agreement’s security is collateralized by a first priority lien on properties constituting at least 85% of the total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement and certain personal property.  The annualized interest rate on borrowings outstanding for the nine months ended September 30, 2019 was 5.1%, which excludes debt issuance costs, commitment fees and other fees.

 

9.75% Senior Second Lien Notes Due 2023

 

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

 

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Senior Second Lien Notes contain covenants that limit or prohibit our ability and the ability of certain of our subsidiaries to: (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture.  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.

 

Covenants 

 

As of September 30, 2019, we were in compliance with all applicable covenants of the Credit Agreement and the Indenture.

 

Fair Value Measurements 

 

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

 

8

 

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

 

 

3.

Fair Value Measurements

 

Derivative Financial Instruments

 

We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our open derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices.  Our open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value.  See Note 6, Derivative Financial Instruments, for additional information on our derivative financial instruments.

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Assets:

               

Derivatives instruments - open contracts

  $ 21,965     $ 74,580  

 

Long-Term Debt

 

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

 

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

 

   

September 30, 2019

   

December 31, 2018

 
   

Carrying Value

   

Fair Value

   

Carrying Value

   

Fair Value

 

Liabilities:

                               

Credit Agreement

  $ 105,000     $ 105,000     $ 21,000     $ 21,000  

Senior Second Lien Notes

    613,949       610,225       612,535       546,875  

 

9

 

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

 

 

4.

Joint Venture Drilling Program

 

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

 

Monza is an entity separate from any other entity with its own separate creditors who will be entitled, upon its liquidation, to be satisfied out of Monza’s assets prior to any value in Monza becoming available to holders of its equity.  The assets of Monza are not available to pay creditors of the Company and its affiliates.

 

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

 

As of September 30, 2019, members of Monza made partner capital contributions, including our initial contributions of working interest in the drilling projects, to Monza totaling $282.2 million, of which $125.5 million was contributed during the nine months ended September 30, 2019.  Our net contribution to Monza, reduced by distributions received, as of September 30, 2019 was $61.4 million.  W&T is obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for the JV Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

 

Consolidation and Carrying Amounts. Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation.  Through September 30, 2019, there have not been any events or changes that would cause a redetermination of the variable interest status.  We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interests in the Monza properties.  As of September 30, 2019, in the Condensed Consolidated Balance Sheet, we recorded $16.8 million, net, in Oil and natural gas properties and other, net, $3.7 million in Other assets and $3.6 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  As of December 31, 2018, in the Condensed Consolidated Balance Sheet, we recorded $8.8 million, net, in Oil and natural gas properties and other, net, $3.3 million in Other assets and $0.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  For the nine months ended September 30, 2019, we recorded $7.4 million in Total revenues and $4.6 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.  For the nine months ended September 30, 2018, we recorded $2.2 million in Total revenues, $1.1 million in Operating costs and expenses and $0.3 million, net, in Other (income) expense, net in connection with our proportional interest in Monza’s operations.

 

Additionally, during the nine months ended September 30, 2019, we called on Monza to provide, and received, $123.5 million to fund JV Drilling Program projects, of which $36.5 million is included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners as of September 30, 2019.

 

10

 

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

 

 

5.

Asset Retirement Obligations

 

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

 

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

 

Balances, December 31, 2018

  $ 310,137  

Liabilities settled

    (7,740 )

Accretion of discount

    14,086  
Liabilities assumed through purchase     21,619  

Liabilities incurred

    426  

Revisions of estimated liabilities

    5,967  

Balances, September 30, 2019

    344,495  

Less current portion

    23,095  

Long-term

  $ 321,400  

 

 

6.

Derivative Financial Instruments

 

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our crude oil and natural gas.  All of the present derivative counterparties are also lenders or affiliates of lenders participating in our Credit Agreement. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  We are not required to provide additional collateral to the derivative counterparties and we do not require collateral from our derivative counterparties.

 

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

 

During 2018, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected future production.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  The natural gas contracts were based on Henry Hub natural gas prices as quoted off the NYMEX and expired during the second quarter of 2019.  The open contracts as of September 30, 2019 are presented in the following tables:

 

Crude Oil: Swap, Priced off WTI (NYMEX)

 

Termination Period

  Notional Quantity (Bbls/day) (1)    

Notional Quantity (Bbls) (1)

   

Strike Price

 

May 2020

  1,500     366,000     $ 60.80  

May 2020

  5,000     1,220,000       61.00  

May 2020

  3,500     854,000       60.85  

 

 

(1)

Bbls = Barrels

 

Crude Oil: Calls - Bought, Priced off WTI (NYMEX)

 

Termination Period

  Notional Quantity (Bbls/day) (1)    

Notional Quantity (Bbls) (1)

   

Strike Price

 

May 2020

  10,000     2,440,000     $ 61.00  

 

 

(1)

Bbls = Barrels

 

 

11

 

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

 

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

 

   

September 30,

   

December 31,

 
   

2019

   

2018

 

Prepaid expenses and other assets

  $ 23,150     $ 60,687  

Other assets (non-current)

          21,275  

 

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

 

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

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

2019

   

2018

 

Derivative (gain) loss

  $ (5,853 )   $ (288 )   $ 41,228     $ 5,931  

 

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

 

   

Nine Months Ended September 30,

 
   

2019

   

2018

 

Cash receipts (payments) on derivative settlements, net

  $ 17,583     $ (3,091 )

 

 

7.

Oil and Gas Property Acquisitions and Divestiture

 

Mobile Bay Acquisition

 

On June 26, 2019, we entered into a purchase and sale agreement with ExxonMobil Corporation and certain of their subsidiaries (collectively "ExxonMobil") to acquire their interests in and operatorship of oil and gas producing properties in the eastern region of the Gulf of Mexico offshore Alabama and a related processing facility for $200.0 million.  On August 30, 2019, we closed on the purchase with ExxonMobil, and after taking into account customary closing adjustments and an effective date of January 1, 2019, cash consideration paid by us was $167.6 million, including a previously-funded $10.0 million deposit.  The transaction is referred to as the "Mobile Bay Acquisition".  The acquisition was funded from cash on hand and borrowings under the Credit Agreement, which was previously undrawn.  We also assumed the related ARO and certain other obligations associated with these assets.  The properties include working interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing properties owned and operated by us. 

 

We determined that the assets acquired did not meet the definition of a business under GAAP; therefore, the transaction was accounted for as an asset acquisition.  The recorded values were determined using the cash paid to the seller and expenses incurred related to the transaction.  Values for the liabilities assumed for ARO and certain other obligations were determined using the same methodology used to estimate other similar obligations of the Company.  The components of the cash paid to the seller at closing and the amounts recorded on the Condensed Consolidated Balance Sheet for the purchase price allocation and liabilities assumed are presented in the following tables (in thousands):

 

Cash paid to seller at close date:

       

Cash on hand

  $ 7,569  

Performance deposit previously funded

    10,000  

Cash funded by the Credit Agreement (increase in long-term debt)

    150,000  

Total - cash paid to seller

  $ 167,569  

 

    August 30, 2019 (Close Date)  

Oil and natural gas properties and other, net - at cost:

  $ 191,450  

Other assets

    4,838  
         

Current liabilities

    2,819  

Asset retirement obligations

    21,619  
Other liabilities     4,132  

 

12

 

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

 

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.  

 

Permian Basin

 

 On September 28, 2018, we closed on the divestiture of substantially all of our ownership in an overriding royalty interests in the Permian Basin.  The net proceeds received were $56.6 million, which was recorded as a reduction to our full-cost pool.

 

 

8.

Leases

 

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

 

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

 

 

not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option);

 

 

not reassess whether a contract contains a lease, lease classifications between operating and financing and accounting for initial direct costs related to leases;

 

 

not reassess certain land easements in existence prior to January 1, 2019;

 

 

use hindsight in determining the lease term and assessing impairment; and

 

 

not separate non-lease and lease components.

 

Based on the results of our implementation process, we identified one operating lease in existence at January 1, 2019 subject to ASU 2016-02, which is our real estate lease for office space in Houston, Texas that terminates in December 2022.  We identified no finance leases.  The implementation  of ASU 2016-02 resulted in establishing an ROU asset and lease liability of $5.0 million during the first quarter of 2019.  The adoption of the new standard did not impact our Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows or Condensed Consolidated Statements of Changes in Shareholders’ Deficit.  

 

During the nine months ended September 30, 2019, various pipeline rights-of-way contracts and a land lease were acquired, assumed, renewed or otherwise entered into, primarily in conjunction with the Mobile Bay Acquisition.  For these contracts, an ROU asset and a corresponding lease liability was calculated based on our assumptions of the term, inflation rates and incremental borrowing rates.  The term of each pipeline right-of-way contract is 10 years with various effective dates, and each has an option to renew for up to another ten years.  It is expected renewals beyond 10 years can be obtained as renewals were granted to the previous lessees.  The land lease has an option to renew every five years extending to 2085.  The expected term of the rights-of way and land leases was estimated to approximate the life of the related reserves.  

 

Minimum future lease payments were estimated assuming expected terms of the leases and estimated inflation escalations of payments for certain leases.  Undiscounted future minimum payments as of September 30, 2019 are as follows: 2019 - $0.8 million; 2020 - $1.9 million; 2021 - $1.9 million; 2022 - $2.0 million; 2023 - $0.5 million; and 2024 and beyond - $13.2 million.  During the nine months ended September 30, 2019 and 2018, expense recognized related to these leases was $2.0 million for each period.    

 

As of September 30, 2019, we recorded ROU assets and lease liabilities using a discount rate of 9.75% for the Houston office lease and 10.75% for the other leases.  The discount rate (or incremental borrowing rate) was determined using the interest rate of recently issued debt instruments that were issued at par and for a similar term as the term of our Houston office lease.  For the other lease contracts, a higher discount rate was used as the incremental borrowing rate due to longer expected termination dates.  The expected terms of the leases ranged between three and 20 years, with no early terminations assumed.

 

13

 

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

 

Amounts related to leases recorded within our Condensed Consolidated Balance Sheet are as follows (in thousands):

 

   

September 30, 2019

 

ROU (net):

       

Other assets

  $ 10,239  
         

Lease liability:

       

Accrued liabilities

  $ 1,877  

Other liabilities

    7,883  

Total lease liability

  $ 9,760  
         

Lease incentives:

       

Other assets (contra-asset)

  $ (907 )

 

 During the nine months ended September 30, 2019, we incurred short-term lease costs related to drilling rigs of $13.3 million, net to our interest, of which the majority of such costs were recorded within Oil and natural gas properties, net, on the Condensed Consolidated Balance Sheet.  In exercising the practical expedient, we did not separate non-lease and lease components for these short-term leases.  

 

 

9.

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 2019, 2018 and 2017, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees.  RSUs are a long-term compensation component, and are subject to satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period based on the results achieved.  In addition to share-based awards, the Company may grant to its employees cash-based incentive awards under the Plan, which may be used as short-term and long-term compensation components of the awards, and are subject to satisfaction of certain predetermined performance criteria.

 

As of September 30, 2019, there were 11,852,592 shares of common stock available for issuance in satisfaction of awards under the Plan.  The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, which shares of common stock are issued net of withholding tax through the withholding of shares.  The Company has the option following vesting to settle RSUs in stock or cash, or a combination of stock and cash. The Company expects to settle RSUs that vest in the future using shares of common stock.

 

RSUs currently outstanding relate to the 2019, 2018 and 2017 grants.  The 2019 grants are subject to pre-determined performance criteria which will be measured using 2019 performance results.  The 2018 and 2017 grants were subject to predetermined performance criteria applied against the applicable performance period.  All the RSUs currently outstanding are 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 2019, 2018 and 2017 were determined using the Company’s closing price on the grant date. We also estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

 

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

 

A summary of activity related to RSUs during the nine months ended September 30, 2019 is as follows:

 

   

Restricted Stock Units

 
           

Weighted Average

 
           

Grant Date Fair

 
   

Units

   

Value Per Unit

 

Nonvested, December 31, 2018

    3,355,917     $ 3.90  
Granted     990,608       4.51  

Forfeited (1)

    (1,075,864 )     3.12  

Nonvested, September 30, 2019

    3,270,661       4.34  

 

 

(1)

Primarily related to former executives' forfeitures.

 

For the outstanding RSUs issued to the eligible employees as of September 30, 2019, vesting is expected to occur as follows (subject to forfeitures): 

 

   

Restricted Stock Units

 

2019

    1,485,510  

2020

    852,535  
2021     932,616  

Total

    3,270,661  

 

 

14

 

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

 

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 2019, 2018 and 2017.  As of September 30, 2019, there were 82,620 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 otherwise 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 during the nine months ended September 30, 2019 is as follows:

 

   

Restricted Shares

 
           

Weighted Average

 
           

Grant Date Fair

 
   

Shares

   

Value Per Share

 

Nonvested, December 31, 2018

    181,832     $ 3.08  

Granted

    46,360       6.04  

Vested

    (105,012 )     2.67  

Nonvested, September 30, 2019

    123,180       4.55  

 

For the Restricted Shares vested during the nine months ended September 30, 2019, the grant date value was $0.3 million and the vested date value, as determined on the vesting dates, was $0.5 million.

 

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2019, vesting is expected to occur as follows (subject to any forfeitures):

 

   

Restricted Shares

 

2020

    78,424  

2021

    29,300  

2022

    15,456  

Total

    123,180  

 

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

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

2019

   

2018

 

Share-based compensation expense from:

                               

Restricted stock units (1)

  $ 1,178     $ 1,303     $ 2,219     $ 3,598  

Restricted Shares

    70       70       210       210  

Total

  $ 1,248     $ 1,373     $ 2,429     $ 3,808  

 

 

(1)

For the nine months ended September 30, 2019, share-based compensation expense includes adjustments for former executives' forfeitures.

 

Unrecognized Share-Based Compensation.  As of September 30, 2019, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $5.9 million and $0.4 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2021 for RSUs and April 2022 for Restricted Shares.

 

15

 

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

 

Cash-Based Incentive Compensation.  In addition to share-based awards, cash-based awards were granted under the Plan to eligible employees in 2019, 2018 and 2017.  For 2018, there were two cash-based awards consisting of a long-term award and a short-term award.  All cash-based awards are performance-based awards consisting of predetermined performance criteria applied against the applicable performance period.  Expense for each award is recognized over the service period once the applicable financial condition is expected to be met, and the business criteria and individual performance criteria can be reasonably estimated for the applicable period.

 

  For the 2019 short-term, cash-based awards, incentive compensation expense was determined based on estimates of the Company achieving certain performance metrics for 2019 and is being recognized over the May 2019 to February 2020 period.  The 2019 short-term, cash-based awards will be eligible for payment during March 2020, subject to participants meeting certain employment-based criteria.

 

 

For the 2018 long-term, cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2018 and is being recognized over the September 2018 to November 2020 period.  The 2018 long-term, cash-based awards will be eligible for payment on December 14, 2020 subject to participants meeting certain employment-based criteria.

 

 

For the 2018 short-term, cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2018 combined with individual performance criteria for 2018 and was recognized over the January 2018 to February 2019 period.  The 2018 short-term, cash-based awards were paid during March 2019.

 
 

For the 2017 short-term, cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2017 combined with individual performance criteria for 2017 and was recognized over the January 2017 to February 2018 period.  The 2017 short term, cash-based awards were paid during March 2018.

 

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

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

2019

   

2018

 

Share-based compensation included in:

                               

General and administrative expenses

  $ 1,248     $ 1,373     $ 2,429     $ 3,808  

Cash-based incentive compensation included in:

                               

Lease operating expense (1)

    672       837       951       2,240  

General and administrative expenses (1)

    1,679       1,534       5,017       5,597  

Total charged to operating income

  $ 3,599     $ 3,744     $ 8,397     $ 11,645  

 

 

(1)

Includes adjustments of accruals to actual payments.

 

 

10.

Income Taxes

 

Tax Benefit and Tax Rate.  We recorded an income tax benefit of $55.5 million and $67.0 million for the three and nine months ended September 30, 2019, respectively.  During the three months ended September 30, 2019, we released a portion of the valuation allowance on our net deferred tax assets based on the Company’s quarterly assessment of the realizability of net deferred tax assets, resulting in an income tax benefit of $55.8 million.  During the nine months ended September 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the Internal Revenue Service ("IRS"), resulting in an income tax benefit of $11.5 million.  Our effective tax rate was not meaningful for the periods presented due to these changes.

 

Valuation Allowance.  Net deferred tax assets relate to net operating loss carryforwards, interest expense carryforwards and other temporary differences expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific federal and state tax jurisdictions in which those temporary differences 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 our deferred tax assets will not be realized.  At December 31, 2018, our valuation allowance was $117.8 million, which offset substantially all net deferred tax assets as of such date. 

 

Throughout 2019, the Company has been in a cumulative three year pre-tax income position and has been assessing the realizeability of our deferred tax assets.  During the quarter ended September 30, 2019, the Company’s assessment included consideration of the Company’s operating history and our forecasted taxable income using all available information.  Based on the assessment, we determined that the Company’s ability to maintain long-term profitability despite near-term changes in commodity prices and capital and operating costs demonstrated that a portion of the Company’s net deferred tax assets would more likely than not be realized.  We released $55.8 million of the valuation allowance, resulting in an income tax benefit in the quarter ended September 30, 2019.  As of September 30, 2019, the Company’s valuation allowance was $62.9 million.

 

16

 

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

 

Income Taxes Receivable.  As of September 30, 2019 and December 31, 2018, we had current income taxes receivable of $36.9 million and $54.1 million, respectively, related primarily to net operating loss carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These carryback claims were made pursuant to IRC Section 172(f) (related to rules regarding “specified liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  During the three and nine months ended September 30, 2019, we received $16.9 million in income tax refunds.  During the same periods, we recorded interest income of $0.5 million and $4.5 million related to these income tax claims, respectively.  During October 2019, we received $34.9 million in additional income tax refunds in addition to the $4.5 million in interest income and we expect to receive the remaining balance of claims of approximately $2.0 million in the first half of 2020. 

 

During the three and nine months ended September 30, 2018, we did not receive any income tax claims or make any income tax payments of significance.

 

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

 

 

11.

Earnings Per Share

 

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

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

2019

   

2018

 

Net income

  $ 75,899     $ 46,260     $ 64,527     $ 109,983  

Less portion allocated to nonvested shares

    1,345       1,860       1,272       4,489  

Net income allocated to common shares

  $ 74,554     $ 44,400     $ 63,255     $ 105,494  

Weighted average common shares outstanding

    140,567       138,972       140,520       138,917  
                                 

Basic and diluted earnings per common share

  $ 0.53     $ 0.32     $ 0.45     $ 0.76  

 

 

12.

Contingencies

 

Apache Lawsuit.  On December 15, 2014, Apache filed a lawsuit against the Company, Apache Deepwater, L.L.C. vs. W&T Offshore, Inc., alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney’s fees and costs assessed in the judgment.  We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit and provided oral arguments in December 2018.  Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017.  On July 16, 2019, a panel of the U.S. Court of Appeals for the Fifth Circuit rendered its opinion that affirmed the trial court's judgment against the Company.  Requests for rehearing and rehearing en banc subsequently were denied. The deposit with the registry of the court was distributed during the third quarter of 2019 pursuant to an agreement with Apache, which does not hinder the Company's continuing right to seek United States Supreme Court review.  The Company intends to pursue vigorously all available legal recourse.  

 

As funds were distributed during the third quarter of 2019, no amounts were recorded on the Condensed Consolidated Balance Sheet as of September 30, 2019 related to this matter.  Interest income of $1.9 million was recorded in Interest expense, net on the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2019.  The deposit of $49.5 million made with the registry of the court was recorded in Other assets (long-term) and $49.5 million was recorded in Other liabilities (long-term) on the Condensed Consolidated Balance Sheet as of December 31, 2018. 

 

Appeal with the Office of Natural Resources Revenue (“ONRR”).  In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision.  On December 4, 2018, the IBLA denied our motion for reconsideration.  On February 4, 2019, we filed our first amended complaint, and the government has filed its Answer in the Administrative Record.  On July 9, 2019, we filed an Objection to the Administrative Record and Motion to Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the record.  Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log.  The government recently provided that privilege log and we are evaluating whether to move to compel production of any of the documents listed on the log.  After these issues concerning the record are resolved, the parties will file cross-motions for summary judgment.

 

17

 

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

 

Royalties-In-Kind (“RIK”).  Under a program of the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program. The MMS added to the RIK program our lease at the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed.  The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to become fixed for accounting purposes.  The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed. We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor.  We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ruling on May 29, 2018.  We filed an appeal on July 24, 2018. Part of the ruling was in favor of our position and part was in favor of MMS’ position.  Based solely on the District Court’s ruling, we recorded a liability reserve of $2.2 million and $2.1 million as of September 30, 2019 and December 31, 2018, respectively.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals and the government filed a cross-appeal.  Briefing has now been completed oral argument was held on October 9, 2019, and we are awaiting a final ruling from the Fifth Circuit.  Based on the briefs filed, W&T has asserted that the government has waived its claim for interest for the period prior to the MMS’s issuance of its order in 2010 requiring W&T to make a cash payment to resolve delivery imbalances (MMS quantified this interest amount as approximately $0.7 million); the government has not disputed W&T’s assertion on this issue.

 

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, 2019 and 2018, we paid $0.4 million and $0.6 million, respectively, of additional royalties and expect to pay more in the future.  We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

 

Notices of Proposed Civil Penalty Assessment.  During the nine months ended September 30, 2019 and 2018, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) at various offshore locations.  We currently have nine open civil penalties issued by the BSEE from INCs, which have not been settled as of the filing date of this Form 10-Q.  The INCs underlying these open civil penalties cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations on various dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.7 million.  As of September 30, 2019 and December 31, 2018, we have accrued approximately $3.5 million, which is our best estimate of the final settlements once all appeals have been exhausted.  Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

 

Other Claims.  We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business.  In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties.  In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold.  We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties.  Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

 

18

 

 

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

 

Forward-Looking Statements

 

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q.  The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”).  These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, 2018 and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend to update these forward-looking statements.  Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

 

Overview

 

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and hold working interests in 53 offshore fields in federal and state waters (52 producing and one field capable of producing).  As of September 30, 2019, we have under lease approximately 815,000 gross acres (535,000 net acres) spanning across the Outer Continental Shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 595,000 gross acres on the conventional shelf and approximately 220,000 gross acres in the deepwater (water depths in excess of 500 feet).  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company and through our proportionately consolidated interests in Monza, as described in more detail in Financial Statements– Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

 

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the nine months ended September 30, 2019 were comprised of 49.1% crude oil and condensate, 8.6% NGLs and 42.3% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past.  For the nine months ended September 30, 2019, revenues from the sale of crude oil and NGLs made up 82.0% of our total revenues compared to 82.8% for the nine months ended September 30, 2018.  For the nine months ended September 30, 2019, our combined total production expressed in equivalent volumes was 1.3% lower than for the nine months ended September 30, 2018, with NGLs having the largest decline.  For the nine months ended September 30, 2019, our total revenues were 12.4% lower than the nine months ended September 30, 2018 primarily due to lower realized prices for crude oil, NGLs and natural gas.  See Results of Operations – Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018 in this Item 2 for additional information.

 

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, 2019, our average realized crude oil price was $61.00 per barrel.  This is a decrease from our average realized crude oil price of $66.52 per barrel, or 8.3%, for the nine months ended September 30, 2018 and a decrease from our average realized crude oil price of $65.62 per barrel, or 7.0%, for the year 2018.  Our average realized prices of NGLs and natural gas for the nine months ended September 30, 2019 were lower than the average realized prices for the nine months ended September 30, 2018 by 37.5% and 11.4%, respectively.

 

Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors.  Crude oil quality adjustments can vary significantly by field.  All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 improved, with the increase ranging between $3.30 per barrel and $4.70 per barrel.

 

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  For the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, average prices for domestic ethane decreased by 22% and average domestic propane prices decreased by 39% as measured using a price index for Mount Belvieu.  The average prices for other domestic NGLs components decreased 24% to 39% for the nine months ended September 30, 2019 compared to the same period in 2018.  We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.

 

19

Table of Contents

 

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as of September 27, 2019 was lower than a year ago for land based rigs (a decrease of 194 rigs, or 19%), and higher in the Gulf of Mexico (an increase of four rigs or 20%).  The oil rig count as of September 27, 2019 and September 28, 2018 was 713 and 863, respectively.  The U.S. natural gas rig count as of September 27, 2019 and September 28, 2018 was 146 and 189, respectively.  In the Gulf of Mexico, the number of working rigs was 22 rigs (21 oil rigs and one natural gas rig) as of September 27, 2019 and 18 rigs (16 oil rigs and two natural gas rigs) as of September 28, 2018.  During the three months ended September 30, 2019, we had four rigs running, which represents approximately 18% of the active rigs in the Gulf of Mexico.

 

On August 30, 2019, we completed the previously announced purchase from ExxonMobil acquiring their interests in and operatorship of oil and gas producing properties in the eastern region of the Gulf of Mexico offshore Alabama and related onshore and offshore facilities and pipelines.  After taking into account customary closing adjustments and an effective date of January 1, 2019, cash consideration paid by us was $167.6 million cash, including a previously-funded $10.0 million deposit.  The acquisition was funded from cash on hand and borrowings of $150.0 million under the Credit Agreement, which were previously undrawn.  We also assumed the related ARO and certain other obligations associated with these assets.  As of the effective date of the acquisition, we estimated the properties had approximately 74 million Boe of net proved reserves, of which 99% were proved developed producing reserves and 22% of the proved net reserves are from liquids, based on October 15, 2018 NYMEX Henry Hub gas and NYMEX WTI oil prices.  These reserve estimates were not prepared in accordance with SEC rules and guidelines.  For the first quarter of 2019, the average production of the properties being acquired was approximately 19,800 net Boe per day.  The properties include  working interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing properties owned and operated by us.  With this purchase, we will become the largest operator in the area. 

 

Our capital expenditure forecast for 2019 excluding the above acquisition, other potential acquisitions and plugging and abandonment expenditures is estimated to be approximately $130 to $150 million composed of select shelf and deepwater projects most of which, assuming success, would be placed on production within a few months after completion.  The forecast incorporates our capital spending relating to the JV Drilling Program (net to our interest).  Our 2019 plans also include spending approximately $13 million for ARO.  We are currently developing and refining our plans for 2020.  Based upon current price and production expectations for 2019 and 2020, we believe that our cash flows from operating activities, cash on hand and borrowing availability under the Credit Agreement will be sufficient to fund our operations through year-end 2020; however, future cash flows are subject to a number of variables and additional capital expenditures may be required to more fully develop our properties.  We are also currently evaluating various acquisition opportunities, which, if successful, may increase our capital requirements in 2019 and beyond.  We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2019 and 2020 plans.  See our Annual Report on Form 10-K for the year ended December 31, 2018, for additional information.

 

20

Table of Contents

 

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):

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

Change

    %    

2019

   

2018

   

Change

    %  
   

(In thousands, except percentages and per share data)

 

Financial:

                                                               

Revenues:

                                                               

Oil

  $ 102,786     $ 119,482     $ (16,696 )     (14.0 )%   $ 298,684     $ 333,406     $ (34,722 )     (10.4 )%

NGLs

    4,373       10,087       (5,714 )     (56.6 )%     15,461       28,481       (13,020 )     (45.7 )%

Natural gas

    23,686       22,641       1,045       4.6 %     65,091       71,485       (6,394 )     (8.9 )%

Other

    1,376       1,249       127       10.2 %     3,766       3,912       (146 )     (3.7 )%

Total revenues

    132,221       153,459       (21,238 )     (13.8 )%     383,002       437,284       (54,282 )     (12.4 )%

Operating costs and expenses:

                                                               

Lease operating expenses

    47,185       37,430       9,755       26.1 %     130,982       109,855       21,127       19.2 %

Production taxes

    588       432       156       36.1 %     1,321       1,326       (5 )     (0.4 )%

Gathering and transportation

    5,955       5,779       176       3.0 %     19,446       15,764       3,682       23.4 %

Depreciation, depletion, amortization and accretion

    38,841       36,969       1,872       5.1 %     110,680       114,807       (4,127 )     (3.6 )%

General and administrative expenses

    10,106       15,990       (5,884 )     (36.8 )%     37,543       45,248       (7,705 )     (17.0 )%

Derivative (gain) loss

    (5,853 )     (288 )     (5,565 )     NM       41,228       5,931       35,297       NM  

Total costs and expenses

    96,822       96,312       510       0.5 %     341,200       292,931       48,269       16.5 %

Operating income

    35,399       57,147       (21,748 )     (38.1 )%     41,802       144,353       (102,551 )     (71.0 )%

Interest expense, net

    14,445       10,727       3,718       34.7 %     42,934       33,475       9,459       28.3 %
Other expense, net     555       18       537       NM       1,364       532       832       NM  

Net income (loss) before income tax (benefit) expense

    20,399       46,402       (26,003 )     (56.0 )%     (2,496 )     110,346       (112,842 )     NM  

Income tax (benefit) expense

    (55,500 )     142       (55,642 )     NM       (67,023 )     363       (67,386 )     NM  

Net income

  $ 75,899     $ 46,260     $ 29,639       64.1 %   $ 64,527     $ 109,983     $ (45,456 )     (41.3 )%
Basic and diluted earnings per common share   $ 0.53     $ 0.32     $ 0.21       65.6 %   $ 0.45     $ 0.76     $ (0.31 )     (40.8 )%

 

NM – not meaningful

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2019

   

2018

   

Change

    % (2)    

2019

   

2018

   

Change

    % (2)  

Operating: (1)

                                                               

Net sales:

                                                               

Oil (MBbls)

    1,735       1,717       18       1.0 %     4,896       5,012       (116 )     (2.3 )%

NGLs (MBbls)

    283       318       (35 )     (11.0 )%     856       985       (129 )     (13.1 )%

Natural gas (MMcf)

    10,606       7,939       2,667       33.6 %     25,344       24,648       696       2.8 %

Total oil equivalent (MBoe)

    3,786       3,359       427       12.7 %     9,976       10,106       (130 )     (1.3 )%
                                                                 

Average daily equivalent sales (Boe/day)

    41,149       36,508       4,641       12.7 %     36,543       37,017       (474 )     (1.3 )%

Average realized sales prices:

                                                               

Oil ($/Bbl)

  $ 59.24     $ 69.57     $ (10.33 )     (14.8 )%   $ 61.00     $ 66.52     $ (5.52 )     (8.3 )%

NGLs ($/Bbl)

    15.45       31.70       (16.25 )     (51.3 )%     18.07       28.91       (10.84 )     (37.5 )%

Natural gas ($/Mcf)

    2.23       2.85       (0.62 )     (21.8 )%     2.57       2.90       (0.33 )     (11.4 )%

Oil equivalent ($/Boe)

    34.56       45.32       (10.76 )     (23.7 )%     38.01       42.88       (4.87 )     (11.4 )%
                                                                 

Average per Boe ($/Boe):

                                                               

Lease operating expenses

  $ 12.46     $ 11.14     $ 1.32       11.8 %   $ 13.13     $ 10.87     $ 2.26       20.8 %

Gathering and transportation

    1.57       1.72       (0.15 )     (8.7 )%     1.95       1.56       0.39       25.0 %

Production costs

    14.03       12.86       1.17       9.1 %     15.08       12.43       2.65       21.3 %

Production taxes

    0.16       0.13       0.03       23.1 %     0.13       0.13              

DD&A

    10.26       11.01       (0.75 )     (6.8 )%     11.09       11.36       (0.27 )     (2.4 )%

G&A expenses

    2.67       4.76       (2.09 )     (43.9 )%     3.76       4.48       (0.72 )     (16.1 )%
    $ 27.12     $ 28.76     $ (1.64 )     (5.7 )%   $ 30.06     $ 28.40     $ 1.66       5.8 %

 

 

(1)

The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

 

 

(2)

Variance percentages are calculated using rounded figures and may result in different figures for comparable data.

 

Volume measurements not previously defined:

   

MBbls — thousand barrels for crude oil, condensate or NGLs

 

Mcf — thousand cubic feet

MBoe — thousand barrels of oil equivalent

 

MMcf — million cubic feet

 

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Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

 

The Mobile Bay Acquisition will have an effect on our results of operations and these effects are not fully reflected in the following results of operations for the three months ended September 30, 2019 since the acquisition was not completed until the end of August 2019.

 

Revenues.  Total revenues decreased $21.2 million, or 13.8%, to $132.2 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018.  Oil revenues decreased $16.7 million, or 14.0%, NGLs revenues decreased $5.7 million, or 56.6%, natural gas revenues increased $1.0 million, or 4.6%, and other revenues increased $0.1 million.  The decrease in oil revenues was attributable to a 14.8% decrease in the average realized sales price to $59.24 per barrel for the three months ended September 30, 2019 from $69.57 per barrel for the three months ended September 30, 2018, partially offset by a 1.0% increase sales volumes.  The decrease in NGLs revenues was attributable to a 51.3% decrease in the average realized sales price to $15.45 per barrel for the three months ended September 30, 2019 from $31.70 per barrel for the three months ended September 30, 2018 and an 11.0% decrease in sales volumes.  The increase in natural gas revenues was attributable to a 33.6% increase in sales volumes, partially offset by a 21.8% decrease in the average realized price to $2.23 per Mcf for the three months ended September 30, 2019 from $2.85 per Mcf for the three months ended September 30, 2018.  Overall, production volumes increased 12.7% on a Boe basis.  The largest production increases for the three months ended September 30, 2019 compared to the three months ended September 30, 2018 were from the Mobile Bay Acquisition, Ship Shoal 349 (Mahogany) field, Fairway field and Viosca Knoll 734 field.  Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to weather and repair and maintenance issues at certain platforms and third-party pipelines.  Our estimate of deferred production for the three months ended September 30, 2019 was approximately 5,500 Boe per day as compared to 4,100 Boe per day for the three months ended September 30, 2018. 

 

Revenues from oil and NGLs as a percent of our total revenues were 81.0% for the three months ended September 30, 2019 compared to 84.4% for the three months ended September 30, 2018.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 26.1% for the three months ended September 30, 2019 compared to 45.6% for the three months ended September 30, 2018.  Revenues from the Mobile Bay Acquisition consist primarily of revenues from sales of natural gas and NGLs.

 

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $9.8 million, or 26.1%, to $47.2 million for the three months ended September 30, 2019 compared to the three months ended September 30, 2018.  On a component basis, base lease operating expenses increased $5.6 million, workover expenses increased $2.6 million and facilities maintenance expenses increased $1.6 million.  Base lease operating expenses increased primarily due to the Mobile Bay Acquisition, and to a lesser extent, increases in transportation and contract labor expenses at certain fields.  The increase in workover expense was primarily due to project expenses at our Mahogany field, which were partially offset by lower project expenses incurred at other fields.  The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Matterhorn field. 

 

Gathering and transportation.  Gathering and transportation expenses increased $0.2 million to $6.0 million for the three months ended September 30, 2019 compared to the three months ended September 30, 2018 primarily related to the acquisition of the Mobile Bay Acquisition.

 

Depreciation, depletion, amortization and accretion (“DD&A”).  DD&A, which includes accretion for ARO, decreased to $10.26 per Boe for the three months ended September 30, 2019 from $11.01 per Boe for the three months ended September 30, 2018 primarily due to the Mobile Bay Acquisition, which the related incremental costs and related incremental reserves produced a lower rate per Boe than the historical full-cost pool rate per Boe.  On a nominal basis, DD&A increased to $38.8 million (or 5.1%) for the three months ended September 30, 2019 from $37.0 million for the three months ended September 30, 2018.  DD&A on a nominal basis increased primarily due to increased production.  Factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

 

General and administrative expenses (“G&A”).  G&A was $10.1 million for the three months ended September 30, 2019, decreasing 36.8% from $16.0 million for the three months ended September 30, 2018.  The decrease was primarily due to increased charges (credits) to counterparties related to joint interest arrangements and lower compensation expenses.  G&A on a per Boe basis was $2.67 per Boe for the three months ended September 30, 2019 compared to $4.76 per Boe for the three months ended September 30, 2018.

 

Derivative gain.  The three months ended September 30, 2019 reflects a $5.8 million derivative gain primarily due to decreased crude oil future pricing used to value our derivative contracts at September 30, 2019 as compared to June 30, 2019, which increased the estimated fair value of our open crude oil contracts between the two measurement dates.  For the three months ended September 30, 2018, we recorded a net gain of $0.3 million from derivative contracts.

 

Interest expense, net.  Interest expense, net, was $14.4 million and $10.7 million for the three months ended September 30, 2019 and 2018, respectively, which includes netting of interest income of $2.7 million and $0.9 million, respectively.  During the three months ended September 30, 2019, interest income of $1.9 million was recorded due to the distribution of funds related to the Apache lawsuit.  During the three months ended September 30, 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60, Troubled Debt Restructuring (“ASC 470-60”), which lowered reported interest expense for the three months ended September 30, 2018 and affects the comparability.

 

Income tax (benefit) expense.  Our income tax benefit for the three months ended September 30, 2019 was $55.5 million and our income tax expense for the three months ended September 30, 2018 was $0.1 million.  We partially reversed a valuation allowance related to our deferred tax assets resulting in a non-cash tax benefit for the three months ended September 30, 2019.  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.  Our effective tax rate using book pre-tax income was not meaningful for either period.  See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

 

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Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

 

The Mobile Bay Acquisition will have an effect on our results of operations and these effects are not fully reflected in the following results of operations for the nine months ended September 30, 2019 since the acquisition was not completed until the end of August 2019.

 

Revenues.  Total revenues decreased $54.3 million, or 12.4%, to $383.0 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018.  Oil revenues decreased $34.7 million, or 10.4%, NGLs revenues decreased $13.0 million, or 45.7%, natural gas revenues decreased $6.4 million, or 8.9%, and other revenues decreased $0.1 million.  The decrease in oil revenues was attributable to an 8.3% decrease in the average realized sales price to $61.00 per barrel for the nine months ended September 30, 2019 from $66.52 per barrel for the nine months ended September 30, 2018 and a 2.3% decrease in sales volumes.  The decrease in NGLs revenues was attributable to a 37.5% decrease in the average realized sales price to $18.07 per barrel for the nine months ended September 30, 2019 from $28.91 per barrel for the nine months ended September 30, 2018 and a 13.1% decrease in sales volumes.  The decrease in natural gas revenues was attributable to an 11.4% decrease in the average realized price to $2.57 per Mcf for the nine months ended September 30, 2019 from $2.90 per Mcf for the nine months ended September 30, 2018 and partially offset by a 2.8% increase in sales volumes.  Overall, production volumes decreased 1.3% on a Boe basis.  The largest production increases for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 were from the Mobile Bay Acquisition, Mahogany field, Ship Shoal 028 field and Fairway field.  Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to weather and repair and maintenance issues at certain platforms and pipelines.  Our estimate of deferred production for the nine months ended September 30, 2019 was approximately 5,900 Boe per day as compared to 4,300 Boe per day for the nine months ended September 30, 2018.  

 

Revenues from oil and NGLs as a percent of our total revenues were 82.0% for the nine months ended September 30, 2019 compared to 82.8% for the nine months ended September 30, 2018.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 29.6% for the nine months ended September 30, 2019 compared to 43.5% for the nine months ended September 30, 2018.  Revenues from the Mobile Bay Acquisition consist primarily of revenues from sales of natural gas and NGLs.

 

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $21.1 million, or 19.2%, to $131.0 million in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.  On a component basis, base lease operating expenses increased $8.9 million, facilities maintenance expense increased $7.9 million and workover expenses increased $4.3 million.  Base lease operating expenses increased primarily due to the Mobile Bay Acquisition and to the addition of the Heidelberg field, acquired in April 2018.  In addition, base lease operating expenses increased due to lower charges to joint interest partners at our Mississippi Canyon 243 ("Matterhorn") field, which are recorded as credits to expense.  The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Mahogany field.  The increase in workover expense was primarily due to 2019 projects at our Mahogany field. 

 

Gathering and transportation.  Gathering and transportation expenses increased $3.7 million, or 23.4%, to $19.4 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.  The increase was primarily related to rate changes from certain third-party pipelines which became effective during the nine months ended September 30, 2019.

 

Depreciation, depletion, amortization and accretion.  DD&A, which includes accretion for ARO, decreased to $11.09 per Boe for the nine months ended September 30, 2019 from $11.36 per Boe for the nine months ended September 30, 2018 primarily due to the Mobile Bay Acquisition, which the related incremental costs and related incremental reserves produced a lower rate per Boe than the previous full-cost pool rate per Boe.  On a nominal basis, DD&A decreased to $110.7 million (or 3.6%) for the nine months ended September 30, 2019 from $114.8 million for the nine months ended September 30, 2018.  DD&A on a nominal basis decreased primarily due to lower production.  Factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

 

General and administrative expenses.  G&A was $37.5 million for the nine months ended September 30, 2019, decreasing 17.0% from $45.2 million for the nine months ended September 30, 2018.  The decrease was largely due to increased charges (credits) to counterparties related to joint interest arrangements, lower compensation expenses and lower premiums paid for surety bonds.  G&A on a per Boe basis was $3.76 per Boe for the nine months ended September 30, 2019 compared to $4.48 per Boe for the nine months ended September 30, 2018.

 

Derivative loss.  The nine months ended September 30, 2019 reflects a $41.2 million derivative loss primarily related to increased crude oil future pricing used to value our derivative contracts at September 30, 2019 as compared to December 31, 2018, which decreased the estimated fair value of our open crude oil contracts between the two measurement dates.  For the nine months ended September 30, 2018, we recorded a net loss of $5.9 million from derivative contracts.

 

Interest expense, net.  Interest expense, net, was $42.9 million and $33.5 million for the nine months ended September 30, 2019 and 2018, respectively, which includes netting of interest income of $7.5 million and $1.6 million, respectively.  During the nine months ended September 30, 2019, we recorded interest income of $4.5 million related to income tax refunds and interest income of $1.9 million due to the distribution of funds related to the Apache lawsuit.  During the nine months ended September 30, 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under ASC 470-60, which lowered reported interest expense and affects the comparability.

 

Income tax (benefit) expense.  Our income tax benefit for the nine months ended September 30, 2019 was $67.0 million and our income tax expense for the nine months ended September 30, 2018 was $0.4 million.  During the nine months ended September 30, 2019, we partially reversed a valuation allowance related to our deferred tax assets and we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, resulting in a non-cash tax benefit.  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.  Our effective tax rate using book pre-tax income was not meaningful for either period.  See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.  

 

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Liquidity and Capital Resources

 

Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our AROs.  We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings and expect to continue to do so in the future.

 

Credit Agreement.  On October 18, 2018, we entered into the Credit Agreement, which matures on October 18, 2022.  As of September 30, 2019, we had $105.0 million borrowings outstanding under the Credit Agreement and $7.2 million of letters of credit issued under the Credit Agreement.  Availability under our Credit Agreement as of September 30, 2019 was $137.8 million.  

 

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, which was initially set at $250.0 million and has not changed.  The next redetermination is scheduled to be completed around November 15, 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our Credit Agreement.  The Credit Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.

 

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

 

Senior Second Lien Notes.  As of September 30, 2019, we had outstanding $625.0 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023.  The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements – Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

 

Debt Covenants.  The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes.  We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of September 30, 2019.

 

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

 

Surety Bond Collateral.  Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.  No additional demands were made to us by sureties during 2019 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

 

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, 2019 and 2018 was $186.6 million and $294.9 million, respectively.  Our combined average realized sales price per Boe decreased by 11.4% for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, which caused total revenues to decrease $44.7 million.  Production volumes decreased by 1.3% measured on a BOE basis primarily from increases in downtime, which caused revenues to decrease by $9.4 million.  In addition, operating expenses impacting operating cash flows increased by $18.5 million primarily for base lease operating expense, workover projects and facility projects.

 

Other items affecting operating cash flows were an increase of $15.8 million for the nine months ended September 30, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to an increase of $27.0 million for the nine months ended September 30, 2018; ARO settlements were $15.0 million lower between the two periods; cash derivative receipts, net, increased $20.7 million between the two periods primarily due to derivative oil contracts; and a tax refund of $16.9 million was received during the nine months ended September 30, 2019.  Working capital items accounted for the balance of the change in net cash provided by operating activities.

 

Net cash used in investing activities primarily represents our acquisition of and investments in oil and gas properties and equipment partially offset by sales of such assets.  Net cash used in investing activities for the nine months ended September 30, 2019 and 2018 was $261.2 million and $45.7 million, respectively.  Our capital expenditures for the nine months ended September 30, 2019 were split approximately 40% for investments in the deep waters of the Gulf of Mexico and approximately 60% for investments on the conventional shelf of the Gulf of Mexico.  During the nine months ended September 30, 2019, the cash expenditure for the Mobile Bay Acquisition was $167.7 million, which is described in the Overview section of this Item.  During the nine months ended September 30, 2018, the purchase of the interest in the Heidelberg field was consummated for $16.8 million and the sale of our overriding royalty interests in the Permian Basin fields resulted in net proceeds of $50.5 million. 

 

Net cash provided by financing activities for the nine months ended September 30, 2019 was $83.1 million.  The net cash provided for the nine months ended September 30, 2019 included borrowings of $150.0 million under the Credit Agreement that were made to fund a portion of the Mobile Bay Acquisition, and repayments of $66.0 million were made reducing the borrowings outstanding under the Credit Agreement.  Net cash used by financing activities for the nine months ended September 30, 2018 was $9.1 million primarily for interest payments on certain debt 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.  During 2018, we entered into derivative contracts for crude oil and natural gas for a portion of our future production.  See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  

 

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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, 2019.  Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

 

Our general and excess liability policies are effective for one year beginning May 1, 2019 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

 

Although we were able to renew our general and excess liability policies effective on May 1, 2019, and our Energy Package effective on June 1, 2019, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims.  We do not carry business interruption insurance.

 

Capital Expenditures.  The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  During the 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 for exploration, development and other leasehold costs (in thousands):

 

   

Nine Months Ended September 30,

 
   

2019

   

2018

 

Exploration (1)

  $ 15,262     $ 27,406  

Development (1)

    77,273       41,071  
Mobile Bay Acquisition     169,831        

Heidelberg field

          16,782  

Reimbursement from Monza for 2017 expenditures

          (14,075 )

Seismic and other

    13,528       4,759  

Investments in oil and gas property/equipment

  $ 275,894     $ 75,943  

 

 

(1)

Reported geographically in the subsequent table.

 

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

 

   

Nine Months Ended September 30,

 
   

2019

   

2018

 

Conventional shelf

  $ 56,426     $ 49,965  

Deepwater

    36,109       18,512  

Exploration and development capital expenditures

  $ 92,535     $ 68,477  

 

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

 

Our capital expenditures for the nine months ended September 30, 2019 were financed by cash flow from operations, cash on hand and borrowings under the Credit Agreement.

 

During the nine months ended September 30, 2019, we completed the Viosca Knoll 823 ("Virgo") A-13 well, which began producing during March 2019, the South Timbalier 320 A-3 well, which began producing in July 2019, and the Mississippi Canyon 800 ("Gladden") SS-2 well, which began producing in September.  All of these wells are in the JV Drilling Program.  We did not drill any dry holes during the nine months ended September 30, 2019.  During the nine months ended September 30, 2018, we completed three wells. 

 

Exploration/Development Activities. As of October 15, 2019, we had completed the Ship Shoal 028 #41 well and were in completion operations on the East Cameron 321 B-8 ST well.  Both of these wells are in the JV Drilling Program.  In addition, we were performing completion operations on the Mahogany A-6 ST1 well, which is not in the JV Drilling Program.

 

Offshore Lease Awards.  During the nine months ended September 30, 2019, we were successful in acquiring leases on 15 blocks (eight deepwater and seven shallow water) from the Gulf of Mexico Lease Sale 252 held by the BOEM on March 20, 2019, and these leases have been officially assigned to us.  These 15 blocks cover approximately 73,500 acres and we paid approximately $3.5 million for all of the awarded leases combined, which reflects a 100% working interest in the acreage.  In addition, our bids were accepted on two shallow water blocks, Ship Shoal 332 and 367, in the Gulf of Mexico Lease Sale 253 held by the BOEM on August 21, 2019.  The two blocks cover approximately 10,300 acres and we paid approximately $0.3 million for the leases, which reflect a 100% working interest in the acreage, and we expect to be awarded the leases by the BOEM once certain administrative matters are executed. 

 

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Capital Expenditure Forecast.  Our 2019 capital expenditure forecast is estimated to be approximately $130 to $150 million, which excludes the Mobile Bay Acquisition described in the Overview section of this Item and excludes any additional potential acquisitions and plugging and abandonment.  The forecast incorporates the shared investments in certain wells included in the JV Drilling Program.  We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.

 

Income Taxes.  During October 2019, we received tax refunds of $34.9 million and accrued interest of $4.5 million, which substantially settled the refund claims and related interest income.  We do not expect to make any significant income tax payments during 2019.  See Financial Statements – Note 10 –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 as of September 30, 2019 and December 31, 2018 were $344.5 million and $310.1 million, respectively.  The Mobile Bay Acquisition increased ARO by $21.6 million, of which all was classified as long term.  Our plans include spending approximately $13.0 million in 2019 for ARO compared to $28.6 million spent on ARO in 2018.  As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates.  See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information.

 

Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt and Note 5 – Asset Retirement Obligations under Part I, Item 1 of this Form 10-Q.  As of September 30, 2019, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $4.7 million.  Except for scheduled utilization, other contractual obligations as of September 30, 2019 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018.

 

Critical Accounting Policies

 

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2018. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1 of this Form 10-Q for additional information.

 

Recent Accounting Pronouncements

 

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

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

Information about market risks for the nine months ended September 30, 2019 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2018.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2018.

 

Commodity Price Risk.  Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely.  Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and could have impacts on our business in the future.  During 2018, we entered into derivative crude oil contracts related to a portion of our estimated future production.  We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments.  Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements. See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

 

Interest Rate Risk.  As of September 30, 2019, we had $105.0 million borrowings outstanding under our Credit Agreement and were subject to the variable London Interbank Offered Rate and the Applicable Margin.  We did not have any derivative instruments related to interest rates.

 

 

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, 2019, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

 

During the quarter ended September 30, 2019, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

26

Table of Contents

 

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings

 

See Financial Statements – Note 12 – Contingencies under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.

 

Item 1A. Risk Factors

 

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

 

The potential effects of crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

 

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018.

 

Item 6. Exhibits

 

Exhibit
Number

 

Description

     

3.1

 

Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

     

3.2

 

Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

     

3.3

 

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))

     

3.4

 

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc., dated as of September 6, 2016. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed September 6, 2016 (File No. 001-32414))

     

3.5

 

Second Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed March 22, 2019 (File No. 001-32414))

     
10.1   Purchase and Sale Agreement, dated as of January 1, 2019, between Exxon Mobil Corporation, Mobil Oil Exploration & Producing Southeast Inc., XH, LLC, Exxon Mobile Bay Limited Partnership, ExxonMobil U.S. Properties Inc. and W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed August 1, 2019 (File No. 001-32414)
     
10.2 *†   Form of Executive Annual Incentive Award Agreement for Fiscal Year 2019.
     
10.3 *†   Form of 2019 Executive Long Term Incentive Plan Agreement.
     

31.1*

 

Section 302 Certification of Chief Executive Officer.

     

31.2*

 

Section 302 Certification of Chief Financial Officer.