Annual Statements Open main menu

W&T OFFSHORE INC - Quarter Report: 2020 September (Form 10-Q)

wti20190630_10q.htm
 

Table of Contents



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, 2020

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 November 2, 2020, there were 141,778,318 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, 2020 and December 31, 2019

1
 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2020 and 2019

2
 

Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended September 30, 2020 and 2019

3
 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2020 and 2019

4
 

Notes to Condensed Consolidated Financial Statements

5

Item 2.

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

24

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

39

Item 4.

Controls and Procedures

39
   

PART II – OTHER INFORMATION

 

Item 1.

Legal Proceedings

40

Item 1A.

Risk Factors

40

Item 6.

Exhibits

41
   

SIGNATURE

42

 

 

 

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,

 
  

2020

  

2019

 

Assets

        

Current assets:

        

Cash and cash equivalents

 $56,532  $32,433 

Receivables:

        

Oil and natural gas sales

  21,407   57,367 

Joint interest and other, net

  10,361   19,400 

Income taxes

     1,861 

Total receivables

  31,768   78,628 

Prepaid expenses and other assets (Note 1)

  23,607   30,691 

Total current assets

  111,907   141,752 
         

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

  694,304   748,798 
         

Restricted deposits for asset retirement obligations

  30,161   15,806 

Deferred income taxes

  87,470   63,916 

Other assets (Note 1)

  25,638   33,447 

Total assets

 $949,480  $1,003,719 

Liabilities and Shareholders’ Deficit

        

Current liabilities:

        

Accounts payable

 $36,790  $102,344 

Undistributed oil and natural gas proceeds

  20,250   29,450 

Advance from joint interest partner

  7,721   5,279 

Asset retirement obligations

  19,522   21,991 

Accrued liabilities (Note 1)

  44,460   30,896 

Total current liabilities

  128,743   189,960 
         

Long-term debt: (Note 2)

        

Principal

  632,460   730,000 

Carrying value adjustments

  (7,713)  (10,467)

Long term debt - carrying value

  624,747   719,533 
         

Asset retirement obligations, less current portion

  362,213   333,603 

Other liabilities (Note 1)

  33,263   9,988 

Commitments and contingencies

      

Shareholders’ deficit:

        

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

      

Common stock, $0.00001 par value; 200,000 shares authorized; 144,647 issued and 141,778 outstanding at September 30, 2020; 144,538 issued and 141,669 outstanding at December 31, 2019

  1   1 

Additional paid-in capital

  550,192   547,050 

Retained deficit

  (725,512)  (772,249)

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

  (24,167)  (24,167)

Total shareholders’ deficit

  (199,486)  (249,365)

Total liabilities and shareholders’ deficit

 $949,480  $1,003,719 

See Notes to Condensed Consolidated Financial Statements

 

 

 

 

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,

 
  

2020

  

2019

  

2020

  

2019

 

Revenues:

                

Oil

 $46,589  $102,786  $161,884  $298,684 

NGLs

  4,464   4,373   12,833   15,461 

Natural gas

  19,213   23,686   69,877   65,091 

Other

  2,251   1,376   7,292   3,766 

Total revenues

  72,517   132,221   251,886   383,002 

Operating costs and expenses:

                

Lease operating expenses

  36,437   47,185   119,525   130,982 

Production taxes

  1,266   588   3,325   1,321 

Gathering and transportation

  3,560   5,955   12,310   19,446 

Depreciation, depletion, amortization and accretion

  25,127   38,841   93,736   110,680 

General and administrative expenses

  14,476   10,106   34,067   37,543 

Derivative loss (gain)

  11,161   (5,853)  (35,337)  41,228 

Total costs and expenses

  92,027   96,822   227,626   341,200 

Operating (loss) income

  (19,510)  35,399   24,260   41,802 

Interest expense, net

  14,135   14,445   46,061   42,934 

Gain on purchase of debt

        (47,469)   

Other expense, net

  751   555   2,225   1,364 

(Loss) income before income tax benefit

  (34,396)  20,399   23,443   (2,496)

Income tax benefit

  (21,057)  (55,500)  (23,294)  (67,023)

Net (loss) income

 $(13,339) $75,899  $46,737  $64,527 

Basic and diluted (loss) earnings per common share

 $(0.09) $0.53  $0.33  $0.45 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

 

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, 2020

  141,669  $1  $549,117  $(712,173)  2,869  $(24,167) $(187,222)

Share-based compensation

        1,075            1,075 

Stock Issued

  109                   

Net loss

           (13,339)        (13,339)

Balances, September 30, 2020

  141,778  $1  $550,192  $(725,512)  2,869  $(24,167) $(199,486)

 

  

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, December 31, 2019

    141,669     $ 1     $ 547,050     $ (772,249 )     2,869     $ (24,167 )   $ (249,365 )

Share-based compensation

                3,142                         3,142  

Stock Issued

    109                                      

Net income

                      46,737                   46,737  

Balances, September 30, 2020

    141,778     $ 1     $ 550,192     $ (725,512 )     2,869     $ (24,167 )   $ (199,486 )

 

   

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 loss

                      64,527                   64,527  

Balances, September 30, 2019

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

See Notes to Condensed Consolidated Financial Statements

 

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

  

Nine Months Ended September 30,

 
  

2020

  

2019

 

Operating activities:

        

Net income

 $46,737  $64,527 

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

        

Depreciation, depletion, amortization and accretion

  93,736   110,680 

Amortization of debt items and other items

  5,251   3,914 

Share-based compensation

  3,142   2,429 

Derivative (gain) loss

  (35,337)  41,228 

Cash receipts on derivative settlements, net

  42,028   17,583 

Gain on purchase of debt

  (47,469)   

Deferred income taxes

  (23,407)  (55,764)

Changes in operating assets and liabilities:

        

Oil and natural gas receivables

  35,959   (3,822)

Joint interest receivables

  9,039   (15,850)

Prepaid expenses and other assets

  7,951   (14,211)

Income tax

  1,993   17,165 

Asset retirement obligation settlements

  (2,788)  (7,740)

Cash advance from JV partner

  2,442   15,847 

Accounts payable, accrued liabilities and other

  (24,539)  10,610 

Net cash provided by operating activities

  114,738   186,596 

Investing activities:

        

Investment in oil and natural gas properties and equipment

  (41,183)  (93,482)

Acquisition of property interest in oil and natural gas properties

  (456)  (167,718)

Purchases of furniture, fixtures and other

  (70)  (20)

Net cash used in investing activities

  (41,709)  (261,220)

Financing activities:

        

Borrowings on credit facility

  25,000   150,000 

Repayments on credit facility

  (50,000)  (66,000)

Purchase of Senior Second Lien Notes

  (23,930)   

Debt issuance costs and other

     (928)

Net cash (used in) provided by financing activities

  (48,930)  83,072 

Increase in cash and cash equivalents

  24,099   8,448 

Cash and cash equivalents, beginning of period

  32,433   33,293 

Cash and cash equivalents, end of period

 $56,532  $41,741 

See Notes to Condensed Consolidated Financial Statements.

 

 

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, 2019.

 

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

 

Recent Events.  The pandemic spread of the disease caused by a new strain of coronavirus (“COVID-19”) and other world events have significantly impacted the price of crude oil and the demand for crude oil beginning in March of 2020.  Additionally, average prices for natural gas liquids (“NGLs”) and natural gas decreased for the nine months ended September 30, 2020 compared to the prior year levels, all of which have impacted revenues for the three and nine months ended September 30, 2020.  While average crude oil prices have partially recovered during  June to September 2020 from recent historical lows in April 2020, the perceived risks and volatility have increased in 2020 to date compared to recent years.  Average natural gas prices for the three months ended September 30, 2020 have remained at levels similar to second quarter of 2020 levels.  The Company has taken measures to reduce operating costs and capital expenditures in response.  Management's assessment is the Company has adequate liquidity to meet the criteria of a going concern as defined under GAAP.  See Note 2, Long-Term Debt and Note 12, Subsequent Events, for additional information.  

 

Accounting Standard Updates effective January 1, 2020 

 

Credit Losses - In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 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. The amendment did not have a material impact on our financial statements and did not affect the opening balance of Retained Deficit.

 

Derivatives and Hedging - 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 earnings 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.  As we do not designate our commodity derivative instruments as qualifying hedging instruments, this amendment did not impact the presentation of the changes in fair values of our commodity derivative instruments on our financial statements.

 

 

 

 

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

 

 

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

 

Paycheck Protection Program (“PPP”).  On April 15, 2020, the Company received $8.4 million under the U.S. Small Business Administration (“SBA”) PPP.  We have elected an accounting policy to analogize International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance (“IAS 20”) and account for the PPP as a government grant.  Under IAS 20, a government grant is recognized when there is reasonable assurance that the Company has complied with the provisions of the grant.

 

The Company submitted an application to the SBA on August 20, 2020, requesting that the PPP funds received be applied to specific covered payroll and non-payroll costs. As of the date of this filing, we have not received any response from the SBA, including any communication regarding the SBA’s acceptance of our application.  Management believes the Company has met all the requirements under the PPP and will not be required to repay any portion of the grant. 

 

We have elected to follow the income approach under IAS 20 and recognize earnings as funds are applied to covered expenses and classify the application of funds as a reduction of the related expense in the Condensed Consolidated Statement of Operations.  As a result, we have reduced expenses during the nine months ended September 30, 2020 and classified expense reductions consistent with our PPP fund application request.  Within the Condensed Consolidated Statement of Operations, credits to Lease operating expenses of $2.3 million, General and administrative expenses of $4.2 million and reductions to Interest expense, net, of $1.9 million were recognized for the nine months ended September 30, 2020.  Should the SBA reject the Company's application on the utilization of the funds, the Company may be required to repay all or a portion of the funds received under the PPP under an amortization schedule through April 2022 with an annual interest rate of 1%.

 

Credit Risk and Allowance for Credit Losses.  Our revenue has been concentrated in certain major oil and gas companies.  For the nine months ended September 30, 2020, and the year ended December 31, 2019, approximately 56% and 63%, respectively, of our revenue was from three major oil and gas companies and a substantial majority of our receivables were from sales with major oil and gas companies.  We also have receivables related to joint interest arrangements primarily with mid-size oil and gas companies with a substantial majority of the net receivable balance concentrated in less than ten companies.  A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected.  The loss methodology uses historical data, current market conditions and forecasts of future economic conditions.  Our maximum exposure at any time would be the receivable balance.  The receivables, Joint interest and other, net, reported on the Condensed Consolidated Balance Sheets are reduced for the allowance for credit losses.  The roll forward of the allowance for credit losses is as follows (in thousands): 

 

 

Allowance for credit losses, December 31, 2019

 $9,898 

Additional provisions

  288 

Uncollectible accounts written off

   

Allowance for credit losses, September 30, 2020

 $10,186 

 

 

6

 

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

 

 

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, 2020

  

December 31, 2019

 

Derivatives - current (1)

 $12,354  $7,266 

Unamortized insurance/bond premiums

  5,022   4,357 

Prepaid deposits related to royalties

  4,473   7,980 

Prepayment to vendors

  1,264   10,202 

Other

  494   886 

Prepaid expenses and other assets

 $23,607  $30,691 

 

 

(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, 2020

  

December 31, 2019

 

Oil and natural gas properties and equipment, at cost

 $8,554,349  $8,532,196 

Furniture, fixtures and other

  20,387   20,317 

Total property and equipment

  8,574,736   8,552,513 

Less: Accumulated depreciation, depletion and amortization

  7,880,432   7,803,715 

Oil and natural gas properties and other, net

 $694,304  $748,798 

 

 

 

 

 

 

 

 

 

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, 2020

  

December 31, 2019

 

Right-of-Use assets (Note 7)

 $12,343  $7,936 

Unamortized debt issuance costs

  2,386   3,798 

Investment in White Cap, LLC

  3,218   2,590 

Unamortized brokerage fee for Monza

  1,378   3,423 

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

  1,625   5,308 

Derivative assets

  3,692   2,653 

Appeal bond deposits

     6,925 

Other

  996   814 

Total other assets (long-term)

 $25,638  $33,447 

 

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

 

  

September 30, 2020

  

December 31, 2019

 

Accrued interest

 $25,421  $10,180 

Accrued salaries/payroll taxes/benefits

  3,543   2,377 

Incentive compensation plans

  1,333   9,794 

Litigation accruals

  3,673   3,673 

Lease liability (Note 7)

  1,779   2,716 

Derivatives - current

  7,921   1,785 

Other

  790   371 

Total accrued liabilities

 $44,460  $30,896 

 

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

 

 

  

September 30, 2020

  

December 31, 2019

 

Dispute related to royalty deductions

 $4,687  $4,687 

Dispute related to royalty-in-kind

  250   250 

Derivatives

  6,222    

Lease liability (Note 7)

  10,091   4,419 

Black Elk escrow and other

  12,013   632 

Total other liabilities (long-term)

 $33,263  $9,988 

 

Black Elk Escrow

 

                $13.9 million of cash was retained in an escrow account and recorded within Restricted Deposits for Asset Retirement Obligations on the Condensed Consolidated Balance Sheet as of September 30, 2020.  The funds were received by W&T as a restricted deposit to be used exclusively for payment of certain asset retirement obligations related to properties sold by W&T to Black Elk Energy Offshore Operations, LLC (“Black Elk”) in connection with the liquidation of Black Elk under Chapter 11 of the U.S. Bankruptcy Code.  $11.1 million was recorded in Other Liabilities as of September 30, 2020 (included in the above table) as our estimate of the additional asset retirement obligations to be funded from the restricted deposit account. 

 

 

 

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, 2020

  

December 31, 2019

 

Credit Agreement borrowings

 $80,000  $105,000 
         

Senior Second Lien Notes:

        

Principal

  552,460   625,000 

Unamortized debt issuance costs

  (7,713)  (10,467)

Total Senior Second Lien Notes

  544,747   614,533 
         

Total long-term debt

 $624,747  $719,533 

 

Credit Agreement

 

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which matures on October 18, 2022. 

 

On June 17, 2020, the lenders under the Credit Agreement completed their semi-annual borrowing base redetermination at $215.0 million and entered into the Third Amendment and Waiver (the “Third Amendment”) to the Credit Agreement.  Although the Company had not violated any covenants, the Third Amendment provides less stringent covenant requirements given the recent changes in the oil and gas markets.  The Third Amendment includes, among other things, the following changes to the Credit Agreement (terms used below are defined in the Credit Agreement,):

 

 

 

 

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

 

 

 

Increased the interest rate margin by 25 basis points.

 

 

Amended the financial covenants as follows:  

 

 

 

From the period ended June 30, 2020 through the period ended December 31, 2021 (the "Waiver Period"), the Company will not be required to comply with the Leverage Ratio covenant.

 

 

 

During the Waiver Period, the Company will be required to maintain a 2.00 to 1.00 ratio limit of first lien debt outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX for the trailing four quarters.

 

 

 

Increase the requirement to provide first priority liens on properties constituting at least 85% to 90% of total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement.

 

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base and the next scheduled redetermination is in the fall of 2020.  Additional redeterminations  may be requested at the discretion of either the lenders or the Company.  The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement. 

 

The Credit Agreement is collateralized by a first priority lien on properties constituting at least 90% 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, 2020 was 3.7%, which excludes debt issuance costs, commitment fees and other fees.

 

Letters of credit may be issued in amounts up to $30.0 million, provided sufficient availability under the Credit Agreement exists.  As of September 30, 2020 and December 31, 2019, we had $4.4 million and $5.8 million, respectively, of letters of credit issued and outstanding under the Credit Agreement.

 

 

 

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

 

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.

 

During the nine months ended September 30, 2020, we acquired $72.5 million in principal of our outstanding Senior Second Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million, which included a reduction of $1.1 million related to the write-off of unamortized debt issuance costs. 

 

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, 2020 and for all prior measurement periods, 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.

 

 

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, 2020

  

December 31, 2019

 

Assets:

        

Derivatives instruments - open contracts, current

 $7,809  $6,921 

Derivatives instruments - open contracts, long-term

  1,511   2,653 
         

Liabilities:

        

Derivatives instruments - open contracts, current

  7,734   1,785 

Derivatives instruments - open contracts, long-term

  6,222    

 

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, 2020

  

December 31, 2019

 
  

Carrying Value

  

Fair Value

  

Carrying Value

  

Fair Value

 

Liabilities:

                

Credit Agreement

 $80,000  $80,000  $105,000  $105,000 

Senior Second Lien Notes

  544,747   379,623   614,533   597,188 

 

 

 

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

 

 

4.

Joint Venture Drilling Program

 

In March 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 “Joint Venture Drilling Program”) in the Gulf of Mexico.  Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T's commitment to fund its retained interest in Monza projects held outside of Monza, are $361.4 million.  W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest.  The Joint Venture 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 retained working interest in the Monza 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 to this structure are approved by the Monza board. 

 

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.

 

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.

 

Through September 30, 2020, nine wells have been completed.  As of September 30, 2020, one additional well was drilled to target depth, but not completed as of this date.  W&T is the operator for seven of the nine wells completed through September 30, 2020.  

 

Through September 30, 2020, members of Monza made partner capital contributions, including our contributions of working interest in the drilling projects, to Monza totaling $289.3 million and received cash distributions totaling $67.7 million.  Our net contribution to Monza, reduced by distributions received, as of September 30, 2020 was $52.5 million.  W&T is obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for the Joint Venture 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, 2020, there have been no 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 of Monza.  As of September 30, 2020, in the Condensed Consolidated Balance Sheet, we recorded $11.6 million, net, in Oil and natural gas properties and other, net, $1.6 million in Other assets, $0.2 million in Asset Retirement Obligations ("ARO") and $1.6 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  As of December 31, 2019, in the Condensed Consolidated Balance Sheet, we recorded $16.1 million, net, in Oil and natural gas properties and other, net, $5.3 million in Other assets, $0.1 million in ARO and $2.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  Additionally, during the nine months ended September 30, 2020 and during the year ended December 31, 2019, we called on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of September 30, 2020 and December 31, 2019 were $7.7 million and $5.3 million, respectively, which are included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners.  For the nine months ended September 30, 2020, in the Condensed Consolidated Statement of Operations, we recorded $6.7 million in Total revenues and $8.9 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.  For the nine months ended September 30, 2019, in the Condensed Consolidated Statement of Operations, 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.

 

 

 

 

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

 

 

5.

Asset Retirement Obligations

 

Our 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, 2019

 $355,594 

Liabilities settled

  (2,788)

Accretion of discount

  17,019 

Liabilities incurred, including acquisitions

  4,355 

Revisions of estimated liabilities

  7,555 

Balances, September 30, 2020

  381,735 

Less current portion

  19,522 

Long-term

 $362,213 

 

 

 

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 current period changes in the fair value of derivative contracts are recognized 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.

 

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 and the natural gas contracts are based off the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).  The open contracts as of September 30, 2020 are presented in the following tables:

 

Crude Oil: Open Swap Contracts, Priced off WTI (NYMEX)

 

Period

 

Notional Quantity (Bbls/day) (1)

  

Notional Quantity (Bbls) (1)

  

Weighted Strike Price

 

Jan 2021 - Dec 2021

  4,000   1,460,000  $42.06 
Jan 2022 - Feb 2022  3,000   177,000  $42.98 

 

 

Crude Oil: Open Call Contracts - Bought, Priced off WTI (NYMEX)

 

Period

 

Notional Quantity (Bbls/day) (1)

  

Notional Quantity
(Bbls) (1)

  

Strike Price

 

Oct 2020 - Dec 2020

  10,000   920,000  $67.50 

 

 

 

 

 

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

 

Crude Oil: Open Collar Contracts - Priced off WTI (NYMEX)

 

Period

 

Notional Quantity (Bbls/day) (1)

  

Notional Quantity
(Bbls) (1)

  

Put Option
Weighted Strike Price
(Bought)

  

Call Option
Weighted Strike Price
(Sold)

 

Oct 2020 - Dec 2020

  10,000   920,000  $45.00  $63.51 

Jan.2021 - Feb 2022

  2,056   750,422  $35.00  $50.00 

 

 

 

(1)

Bbls = Barrels

 

 

Natural Gas: Open Swap Contracts, Bought, Priced off Henry Hub (NYMEX)

 

Period

 

Notional Quantity (MMBtu/day) (2)

  

Notional Quantity (MMBtu) (2)

  

Strike Price

 

Nov 2020 - Dec 2020

  10,000   610,000  $2.03 
Nov 2020 - Dec 2020  15,000   915,000  $2.21 
Jan 2021 - Dec 2021  10,000   3,650,000  $2.62 
Jan 2022 - Jan 2022  20,000   620,000  $2.79 
Feb 2022 - Feb 2022  30,000   840,000  $2.79 

 

 

Natural Gas: Open Call Contracts, Bought, Priced off Henry Hub (NYMEX)

 

Period

 

Notional Quantity (MMBtu/day) (2)

  

Notional Quantity (MMBtu) (2)

  

Strike Price

 

Nov 2020 - Dec. 2022

  40,000   31,640,000  $3.00 

 

 

Natural Gas: Open Collar Contracts, Priced off Henry Hub (NYMEX)

 

Period

 

Notional Quantity (MMBtu/day) (2)

  

Notional Quantity (MMBtu) (2)

  

Put Option
Weighted Strike Price
(Bought)

  

Call Option
Weighted Strike Price
(Sold)

 

Nov 2020 - Dec 2020

  10,000   610,000  $1.75  $2.58 

Nov 2020 - Dec 2022

  40,000   31,640,000  $1.83  $3.00 

Jan 2021 - Dec 2021

  30,000   10,950,000  $2.18  $3.00 

Jan 2022 - Feb 2022

  30,000   1,770,000  $2.20  $4.50 

 

 

 

(2)

MMBtu = Million British Thermal Units

 

 

 

 

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,

 
  

2020

  

2019

 

Prepaid expenses and other assets

 $12,354  $7,266 

Other assets (long-term)

  3,692   2,653 

Accrued liabilities

  7,921   1,785 

Other liabilities (long-term)

  6,222    

 

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 material 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,

 
  

2020

  

2019

  

2020

  

2019

 

Derivative loss (gain)

 $11,161  $(5,853) $(35,337) $41,228 

 

 

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,

 
  

2020

  

2019

 

Cash receipts on derivative settlements, net

 $42,028  $17,583 

 

 

16

 

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

 

 

7.

Leases

 

Our contract arrangements accounted for under the applicable GAAP for lease contracts consist of office leases, a land lease and various pipeline right-of-way contracts.  For these contracts, a right-of-use ("ROU") asset and lease liability was established based on our assumptions of the term, inflation rates and incremental borrowing rates.  All of these lease contracts are operating leases.

 

During the nine months ended September 30, 2020, we terminated the existing office lease and executed a new lease on separate office space.  The remaining term of the current office lease extends to December 2020.  The term of the new office lease extends to February 2032.  When calculating the ROU asset and lease liability at the commencement of the new office lease, we have reduced future cash outflows by the lease incentive to be received.

 

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.   

 

We recorded ROU assets and lease liabilities using a discount rate of 9.75% for the office leases and 10.75% for the other leases due to their longer expected term. 

 

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

 

 

 

  

September 30, 2020

  

December 31, 2019

 

ROU assets

 $12,343  $7,936 
         

Lease liability:

        

Accrued liabilities

 $1,779  $2,716 

Other liabilities

  10,091   4,419 

Total lease liability

 $11,870  $7,135 

 

 

 

 

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

 

 

8.

Share-Based Compensation and Cash-Based Incentive Compensation

 

Awards to Employees. In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by our shareholders.  During 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, 2020, there were 10,874,043 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 and 2018 grants.  The 2019 and 2018 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, 2020 is as follows:

 

  

Restricted Stock Units

 
      

Weighted Average

 
      

Grant Date Fair

 
  

Units

  

Value Per Unit

 

Nonvested, December 31, 2019

  1,614,722  $5.73 

Forfeited

  (51,915)  6.10 

Nonvested, September 30, 2020

  1,562,807   5.71 

 

 

For the outstanding RSUs issued to the eligible employees as of September 30, 2020, vesting is expected to occur as follows (subject to forfeitures): 

 

  

Restricted Stock Units

 

2020

 

787,203

 

2021

 

775,604

 

Total

 

1,562,807

 

 

 

 

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 2020, 2019, 2018 and 2017.  During the second quarter of 2020, our shareholders approved increasing the shares available by 500,000 shares.  As of September 30, 2020, there were 473,244 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, 2020 is as follows:

 

  

Restricted Shares

 
      

Weighted Average

 
      

Grant Date Fair

 
  

Shares

  

Value Per Share

 

Nonvested, December 31, 2019

  123,180  $4.55 

Granted

  109,376   2.53 

Vested

  (78,428)  3.57 

Nonvested, September 30, 2020

  154,128  $3.61 

 

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2020, vesting is expected to occur as follows (subject to any forfeitures):

 

  

Restricted Shares

 

2021

 

138,676

 

2022

 

15,452

 

Total

 

154,128

 

 

Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  No share-based awards have been granted to date in 2020 under the Plan, and therefore, no share-based compensation expense for 2020 has been recorded.  The Compensation Committee has deferred its decision regarding the potential awarding of incentive compensation, including by the exercise of discretion.  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,

 
  

2020

  

2019

  

2020

  

2019

 

Share-based compensation expense from:

                

Restricted stock units (1)

 $927  $1,178  $2,854  $2,219 

Restricted Shares

  148   70   288   210 

Total

 $1,075  $1,248  $3,142  $2,429 

 

 

(1)

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

 

 

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

 

Unrecognized Share-Based Compensation.  As of September 30, 2020, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $1.9 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.

 

Cash-Based Incentive Compensation.  In addition to share-based compensation, short-term, cash-based incentive awards were granted under the Plan to substantially all eligible employees in 2019 and 2018.  The short-term, cash-based incentive awards, which are generally a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria.  In addition, these cash-based incentive awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (terms as defined in the awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based incentive award.  No cash-based incentive awards have been granted to date in 2020 under the Plan, and therefore, no cash-based incentive award compensation expense for 2020 has been recorded. The Compensation Committee has deferred its decision regarding the potential awarding of incentive compensation, including by the exercise of discretion.  During 2018, long-term, cash-based incentive awards were granted to certain employees subject to pre-defined performance criteria.  Expense is recognized over the service period once the business criteria, individual performance criteria and financial condition are met. 

 

 

For the 2019 cash-based awards, a portion of the business criteria and individual performance criteria were achieved.  The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized over the  January 2019 to February 2020 period (the service period of the award).  Payments were made in March 2020 and are subject to all the terms of the 2019 Annual Incentive Award Agreement.

 

 

In 2018, the Company, as part of its long-term incentive program, granted cash awards to certain employees that will vest over a three-year service period.  

 

 

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 service period of the award).  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.

 

 

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,

 
  

2020

  

2019

  

2020

  

2019

 

Share-based compensation included in:

                

General and administrative expenses

 $1,075  $1,248  $3,142  $2,429 

Cash-based incentive compensation included in:

                

Lease operating expense (1)

     672   849   951 

General and administrative expenses (1)

  154   1,679   3,944   5,017 

Total charged to operating income

 $1,229  $3,599  $7,935  $8,397 

 

 

(1)

Includes adjustments of accruals to actual payments.

 

 

 

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

 

 

9.

Income Taxes 

 

Tax Benefit and Tax Rate.  Income tax benefit for the three months and nine months ended September 30, 2020, was $21.1 million and $23.3 million, respectively.  Income tax benefit for the three and nine months ended September 30, 2019, was $55.5 million and $67.0 million, respectively.  For the three and nine months ended September 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) on March 27, 2020 and the issuance by the United States Treasury Department (Treasury) of final and proposed regulations under Internal Revenue Code (“IRC”) Section 163(j) on July 28, 2020 that provided additional guidance and clarification related to the business interest expense limitation.  Included in the income tax benefit for the three and nine months ended September 30, 2020 is $19.0 million and $27.5 million, respectively, related to changes in our interest expense limitation due to the enactment of the CARES Act and final and proposed regulations under IRC Section 163(j).  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 any of the periods presented.  

 

Valuation Allowance.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.     

 

As of September 30, 2020 and December 31, 2019, our valuation allowance was $24.7 million and $54.4 million, respectively, and relates primarily to state net operating losses and the disallowed interest limitation carryover.

 

Calculation of Interim Provision for Income Tax.  Historically, we have calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full year to income (loss) for the interim period.  In the third quarter of 2020, we concluded that we could not calculate a reliable estimate of our annual effective tax rate due to the range of potential impacts the global COVID-19 pandemic may have on our business and results of operations.  Accordingly, we computed the effective tax rate for the nine-month period ending September 30, 2020 using actual results.

 

Income Taxes Receivable, Refunds and Payments.  As of December 31, 2019, we had current income taxes receivable of $1.9 million, which was received during the nine months ended September 30, 2020.  The refund related primarily to a net operating loss (“NOL”) carryback claim for 2017 that was carried back to prior years.  During the nine months ended September 30, 2020, we did not make any income tax payments of significance.  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 the nine months ended  September 30, 2019, we did not make any income tax payments of significance.

 

The tax years 2017 through 2019 remain open to examination by the tax jurisdictions to which we are subject.

 

 

21

 

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

 

 

10.

Earnings Per Share

 

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

 

  

Three Months Ended September 30,

  

Nine Months Ended September 30,

 
  

2020

  

2019

  

2020

  

2019

 

Net (loss) income

 $(13,339) $75,899  $46,737  $64,527 

Less portion allocated to nonvested shares

     1,345   549   1,272 

Net (loss) income allocated to common shares

 $(13,339) $74,554  $46,188  $63,255 

Weighted average common shares outstanding

  141,624   140,567   141,589   140,520 
                 

Basic and diluted (loss) earnings per common share

 $(0.09) $0.53  $0.33  $0.45 
                 

Shares excluded due to being anti-dilutive (weighted-average)

  1,677          

 

 

11.

Contingencies

 

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 ultimately led to our posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the IBLA decision, of which the cash collateral held by the surety was subsequently returned during the first quarter of 2020.  We have continued to pursue our legal rights and, at present, the case is in front of the U.S. District Court for the Eastern District of Louisiana where parties have now filed their Motions for Summary Judgment, and the opposition and reply briefs will be completed by February 2, 2021.

 

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.  While the amounts paid for the nine months ended September 30, 2020 and 2019 were immaterial, we are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

 

 

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

 

Notices of Proposed Civil Penalty Assessment.  During the nine months ended September 30, 2020 and 2019, 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, 2020 and December 31, 2019, 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.  We are exploring the possibility of settling these civil penalties with the BSEE.

 

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

 

 

 

12.

Subsequent Events

 

COVID-19 Impacts on Economic Environment.  Subsequent to September 30, 2020, COVID-19 outbreaks levels have continued and, in some cases, increased in some areas of the United States.  The impacts of the COVID-19 pandemic on the economy combined with actions of certain foreign governments of oil producing countries have caused s significant decrease in global crude oil demand contributing to a substantial decrease in crude oil prices compared to the prior year and an increase in the volatility of the crude oil market.  Additionally, prices for NGLs and natural gas have been impacted, but to a lesser degree.  This economic environment has caused oil and gas operators to reduce their capital expenditure budgets, reduce activity and shut-in significant production.  The full impact of the COVID-19 pandemic and the volatility in crude oil prices continue to evolve as of the date of this Quarterly Report.  However, the scope and length of this economic downturn and the effect on future prices and demand of crude oil, NGLs and natural gas cannot be determined and we could be adversely affected in future periods.

 

In response to the market changes, we reduced our capital expenditure budget in 2020, experienced production shut-ins from non-operated oil and gas properties and shut-in a limited number of our operated oil and gas properties.  We are actively monitoring the impact on our results of operations, financial position, and liquidity and may need to make further changes in response to the market for oil, NGLs and natural gas.

 

Hurricanes Impact on our Production.  In the second and third quarters of 2020, the Gulf of Mexico experienced multiple hurricanes that required us to shut-in wells due to their impact.  In October 2020, we experienced additional hurricane activity which required shutting in most of our fields for several days.  We have since returned substantially all wells to production that were shut-in due to the hurricanes, as have operators of properties in which we have a non-operator interest.  One of our fields had planned downtime which was extended due to hurricane activity and had not returned to production as of the end of October 2020.  While no major structural damage was incurred, which has been assessed through October, increased costs for repairs are expected in the fourth quarter of 2020. 

 

 

 

 

 

 

 

 

 

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, 2019 and this Quarterly Report on Form 10-Q, Part II, Item 1A, Risk Factors, 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.  As of September 2020, we hold working interests in 50 offshore fields in federal and state waters (41 producing and nine fields capable of producing).  We currently have under lease approximately 772,000 gross acres (523,000 net acres) spanning across the OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 557,000 gross acres on the conventional shelf and approximately 215,000 gross acres in the deepwater.  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements and Supplementary Data – Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

 

Recent Events

 

Due to circumstances related to the outbreak of COVID-19, various measures have been taken by federal, state and local governments to reduce the rate of spread of COVID-19.  These measures and other factors have resulted in a decrease of general economic activity and a corresponding decrease in global and domestic energy demand impacting commodity pricing.  In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) have negatively impacted crude oil prices.  These rapid and unprecedented events have pushed crude oil storage near capacity and drove prices down significantly in the second quarter of 2020.  These events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing in 2020 compared to the prior year.  Through October 2020, COVID-19 outbreak levels have continued and, in some cases, increased in some areas of the United States.  Should these conditions continue in future periods, they could constrain our ability to store and move production to downstream markets, delay or curtail development activity or temporarily shut-in production, any or all of which could further reduce our cash flow.

 

In the second and third quarters of 2020, the Gulf of Mexico experienced multiple hurricanes that required us to shut-in wells due to their impact.  In October 2020, we experienced additional hurricane activity which required shutting in most of our fields for several days. We have since returned substantially all wells to production that were shut-in due to the hurricanes, as have operators of properties in which we have a non-operator interest.  One of our fields had planned downtime which was extended due to hurricane activity and had not returned to production as of the end of October 2020.  While no major structural damage was incurred, which has been assessed through October, increased costs for repairs estimated at $5 million are expected in the fourth quarter of 2020.  

 

During the fourth quarter of 2020, we will begin the consolidation of our two gas processing plants in Alabama.  We estimate future cost savings of approximately $5 million per year related to the plant consolidation efforts.

 

 

 

 

The Company has responded to COVID-19 events and current economic conditions as follows:

 

 

Our capital expenditure forecast for 2020 has been reduced significantly from our initial budget in response to the unprecedented decrease in crude oil prices experienced beginning in the first quarter of 2020.  Excluding acquisitions and plugging and abandonment expenditures, we are currently estimating capital expenditures to range from $15 million to $25 million for 2020 (excluding $28 million in working capital changes associated with capital expenditures incurred in 2019 but paid during the nine months ended September 30, 2020) and ARO spending to be in the range of $2 million to $4 million.  We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2020 plans and are unable to predict the duration or impact of COVID-19 and OPEC+ actions have on our business. 

 

 

During the second quarter of 2020, we shut-in production in selected oil-weighted properties operated by the Company and experienced production shut-ins at certain non-operated properties due to the decline in oil prices.  The majority of such non-operated production that was previously shut-in was restored during the third quarter of 2020.  The Company restored some of its operated production that was shut-in due to low oil prices and continues to monitor commodity prices to determine the appropriate time to return the remaining fields online.

 

 

We have taken proactive steps in our field operations and corporate offices to protect the health and safety of our employees and contractors.  At W&T’s corporate offices located in Houston, Texas, the Company mandated a work-from-home policy on March 23, 2020 and ensured that all employees had the ability to continue performing their work duties remotely.  In October 2020, we fully reopened our corporate office and implemented policies to protect our employees and contractors working in our offices.  At all our onshore offices and offshore facilities located in Louisiana, Alabama and Texas, the Company conducts daily temperature screenings and implemented procedures for distancing and hygiene at its onshore offices and field locations.  In our field operations, the Company instituted screening of all personnel prior to entry to heliports, shore-based facilities and Alabama gas treatment plants, which includes a questionnaire and temperature check.  We monitor national, state and local government directives and continually assess the adequacy of our health and safety protocols.

 

See the Liquidity and Capital Resources section in this Part II for a discussion of our liquidity and other aspects as a result of the decrease in commodity prices.   See Item 1A, Risk Factors, under Item II of this Form 10-Q. 

 

 

Oil and Natural Gas Production and Commodity Pricing

 

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, 2020 were comprised of 36.7% crude oil and condensate, 11.1% NGLs and 52.2% 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, 2020, revenues from the sale of crude oil and NGLs made up 69.4% of our total revenues compared to 82.0% for the nine months ended September 30, 2019.  For the nine months ended September 30, 2020, our combined total production expressed in equivalent volumes on a daily basis was 18.5% higher than for the nine months ended September 30, 2019, primarily due to the acquisition of the Mobile Bay properties described below.  For the nine months ended September 30, 2020, our total revenues were 34.2% lower than the nine months ended September 30, 2019 due to lower realized prices for crude oil, NGLs and natural gas and partially offset by higher volumes.  See Results of Operations – Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019 in this Item 2 for additional information. 

 

In August 2019, we completed the purchase of Exxon Mobil Corporation's (“Exxon”) 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 (the “Mobile Bay Properties”).  For the nine months ended September 30, 2020, the average net production of the Mobile Bay Properties was approximately 15,800 net Boe per day.  

 

 

 

 

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, 2020, our average realized crude oil price was $37.17 per barrel.  This is a decrease from our average realized crude oil price of $61.00 per barrel, or 39.1%, for the nine months ended September 30, 2019.  Per the Energy Information Administration ("EIA"), crude oil prices using average WTI daily spot pricing decreased to $38.04 per barrel during the nine months ended September 30, 2020 compared to $57.04 during the nine months ended September 30, 2019 representing a decrease of 33.3%.  Crude oil prices have partially recovered from their April lows, with an average WTI spot price of $39.63 per barrel for the month of September 2020, and $39.51 per barrel for the first two weeks of October 2020, but still remain depressed compared to the same periods in 2019.

 

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 Poseidon, LLS and HLS to WTI for the nine months ended September 30, 2020 averaged ($0.21), $2.38, and $1.81 per barrel, respectively, and each differential has decreased in the range of $4.00 to $5.00 per barrel compared to the nine months ended September 30, 2019. 
 

Our average realized price of natural gas of $1.88 per Mcf for the nine months ended September 30, 2020 was  26.8 % lower than the average realized price of $2.57 per Mcf for the nine months ended September 30, 2019.  The average Henry Hub ("HH") daily natural gas spot price of $1.94 per Mcf for the nine months ended September 30, 2020 was 28.7% lower than the average HH natural gas price of $2.72 per Mcf for the nine months ended September 30, 2019. Per the EIA, this decrease was due to lower demand from the U.S. power sector and lower exports of liquefied natural gas.  Furthermore, working inventories of natural gas as of September 30, 2020 were 12% higher than the five-year average.

 
Our average realized price of NGLs for the nine months ended September 30, 2020 was  45.9% lower than the average realized price for the nine months ended September 30, 2019.  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, 2020 compared to the nine months ended September 30, 2019, average prices for domestic ethane decreased by 16% and average domestic propane prices decreased by 22% as measured using a price index for Mount Belvieu.  The average prices for other domestic NGLs components decreased 18% to 37% for the nine months ended September 30, 2020 compared to the same period in 2019.  Due to the acquisition of the Mobile Bay Properties, our volumes of NGLs have increased, but at lower realized prices than previously realized for our NGL volumes.  We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand. 

 

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as reported in their October 16, 2020 report was significantly lower than a year ago, decreasing to 282 rigs compared to 851 rigs a year ago.  The oil rig count decreased to 205 rigs compared to 713 rigs a year ago and the gas and miscellaneous rigs decreased to 77 rigs from 138 a year ago.  In the Gulf of Mexico, the number of working rigs was 14 rigs (all oil) compared to 21 (20 oil and one natural gas) a year ago.   

 

 

 

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,

 
   

2020

   

2019

   

Change

      %  

2020

   

2019

   

Change

      %
   

(In thousands, except percentages and per share data)

 

Financial:

                                                               

Revenues:

                                                               

Oil

  $ 46,589     $ 102,786     $ (56,197 )     (54.7 )%   $ 161,884     $ 298,684     $ (136,800 )     (45.8 )%

NGLs

    4,464       4,373       91       2.1 %     12,833       15,461       (2,628 )     (17.0 )%

Natural gas

    19,213       23,686       (4,473 )     (18.9 )%     69,877       65,091       4,786       7.4 %

Other

    2,251       1,376       875       63.6 %     7,292       3,766       3,526       93.6 %

Total revenues

    72,517       132,221       (59,704 )     (45.2 )%     251,886       383,002       (131,116 )     (34.2 )%

Operating costs and expenses:

                                                               

Lease operating expenses

    36,437       47,185       (10,748 )     (22.8 )%     119,525       130,982       (11,457 )     (8.7 )%

Production taxes

    1,266       588       678       115.3 %     3,325       1,321       2,004       151.7 %

Gathering and transportation

    3,560       5,955       (2,395 )     (40.2 )%     12,310       19,446       (7,136 )     (36.7 )%

Depreciation, depletion, amortization and accretion

    25,127       38,841       (13,714 )     (35.3 )%     93,736       110,680       (16,944 )     (15.3 )%

General and administrative expenses

    14,476       10,106       4,370       43.2 %     34,067       37,543       (3,476 )     (9.3 )%

Derivative loss (gain)

    11,161       (5,853 )     17,014       NM       (35,337 )     41,228       (76,565 )     NM  

Total costs and expenses

    92,027       96,822       (4,795 )     (5.0 )%     227,626       341,200       (113,574 )     (33.3 )%

Operating (loss) income

    (19,510 )     35,399       (54,909 )     NM       24,260       41,802       (17,542 )     (42.0 )%

Interest expense, net

    14,135       14,445       (310 )     (2.1 )%     46,061       42,934       3,127       7.3 %

Gain on purchase of debt

    -                   NM       (47,469 )           (47,469 )     NM  

Other expense, net

    751       555       196       35.3 %     2,225       1,364       861       63.1 %

(Loss) income before income tax benefit

    (34,396 )     20,399       (54,795 )     NM       23,443       (2,496 )     25,939       NM  

Income tax benefit

    (21,057 )     (55,500 )     34,443       NM       (23,294 )     (67,023 )     43,729       NM  
Net (loss) income   $ (13,339 )   $ 75,899     $ (89,238 )     NM     $ 46,737     $ 64,527     $ (17,790 )     (27.6 )%
Basic and diluted (loss) earnings per common share   $ (0.09 )   $ 0.53     $ (0.62 )     NM     $ 0.33     $ 0.45     $ (0.12 )     (26.7 )%

 

NM – not meaningful

 

 

 

 

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2020

   

2019

   

Change

      %  

2020

   

2019

   

Change

      %

Operating: (1)

                                                               

Net sales:

                                                               

Oil (MBbls)

    1,115       1,735       (620 )     (35.7 )%     4,356       4,896       (540 )     (11.0 )%

NGLs (MBbls)

    407       283       124       43.8 %     1,312       856       456       53.3 %

Natural gas (MMcf)

    9,897       10,606       (709 )     (6.7 )%     37,210       25,344       11,866       46.8 %

Total oil equivalent (MBoe)

    3,170       3,786       (616 )     (16.3 )%     11,869       9,976       1,893       19.0 %
                                                                 

Average daily equivalent sales (Boe/day)

    34,459       41,149       (6,690 )     (16.3 )%     43,317       36,543       6,774       18.5 %

Average realized sales prices:

                                                               

Oil ($/Bbl)

  $ 41.81     $ 59.24     $ (17.43 )     (29.4 )%   $ 37.17     $ 61.00     $ (23.83 )     (39.1 )%

NGLs ($/Bbl)

    10.99       15.45       (4.46 )     (28.9 )%     9.78       18.07       (8.29 )     (45.9 )%

Natural gas ($/Mcf)

    1.94       2.23       (0.29 )     (13.0 )%     1.88       2.57       (0.69 )     (26.8 )%

Oil equivalent ($/Boe)

    22.16       34.56       (12.40 )     (35.9 )%     20.61       38.01       (17.40 )     (45.8 )%
                                                                 

Average per Boe ($/Boe):

                                                               

Lease operating expenses

  $ 11.49     $ 12.46     $ (0.97 )     (7.8 )%   $ 10.07     $ 13.13     $ (3.06 )     (23.3 )%

Gathering and transportation

    1.12       1.57       (0.45 )     (28.7 )%     1.04       1.95       (0.91 )     (46.7 )%

Production costs

    12.61       14.03       (1.42 )     (10.1 )%     11.11       15.08       (3.97 )     (26.3 )%

Production taxes

    0.40       0.16       0.24       150.0 %     0.28       0.13       0.15       115.4 %

DD&A

    7.93       10.26       (2.33 )     (22.7 )%     7.90       11.09       (3.19 )     (28.8 )%

G&A expenses

    4.57       2.67       1.90       71.2 %     2.87       3.76       (0.89 )     (23.7 )%
    $ 25.51     $ 27.12     $ (1.61 )     (5.9 )%   $ 22.16     $ 30.06     $ (7.90 )     (26.3 )%

 

 

 

(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.

 

 

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

 

 

 

 

 

Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019

 

Due to the decrease and volatility in crude oil prices and to a lesser extent, decreases and volatility in natural gas and prices for NGLs, the results of the three months ended September 30, 2020 may not be indicative of future periods.  See “Liquidity and Capital Resources – Liquidity Overview” below for additional information.

 

Revenues.  Total revenues decreased $59.7 million, or 45.2%, to $72.5 million for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019.  Oil revenues decreased $56.2 million, or 54.7%, NGLs revenues increased $0.1 million, or 2.1%, natural gas revenues decreased $4.5 million, or 18.9%, and other revenues increased $0.9 million.  The decrease in oil revenues was attributable to a 29.4% decrease in the average realized sales price to $41.81 per barrel for the three months ended September 30, 2020 from $59.24 per barrel for the three months ended September 30, 2019 and a decrease in sales volumes of 35.7%.  The increase in NGLs revenues was attributable to an increase in sales volumes of 43.8%, and partially offset by a 28.9% decrease in the average realized sales price to $10.99 per barrel for the three months ended September 30, 2020 from $15.45 per barrel for the three months ended September 30, 2019.  The decrease in natural gas revenues was attributable to a 13.0% decrease in the average realized price to $1.94 per Mcf for the three months ended September 30, 2020 from $2.23 per Mcf for the three months ended September 30, 2019 and a decrease in sales volumes of 6.7%.  Overall, sales volumes decreased 16.3 % on a Boe/day basis primarily as a result of hurricane related downtime; natural production declines; and shutting in certain operated and non-operated fields.  Our estimate of deferred production for the three months ended September 30, 2020 was approximately 13,500 Boe per day as compared to 5,500 Boe per day for the three months ended September 30, 2019 due primarily to the increased hurricane activity.  These decreases were partially offset by higher net sales volumes during the third quarter of 2020 compared to the prior year period from several fields.  The largest increase came from the Mobile Bay field, which we acquired in August 2019 and had net sales volumes of 13,300 Boe per day during the three months ended September 30, 2020 compared to 6,100 Boe per day for the three months ended September 30, 2019.

 

Revenues from oil and NGLs as a percent of our total revenues were 70.4% for the three months ended September 30, 2020 compared to 81.0% for the three months ended September 30, 2019.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased slightly to 26.3% for the three months ended September 30, 2020 compared to 26.1% for the three months ended September 30, 2019.   

 

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, decreased $10.7 million, or 22.8%, to $36.4 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019.  On a component basis, base lease operating expenses decreased $3.5 million, workover expenses decreased $3.3 million, and facilities maintenance expense decreased $3.9 million.  Base lease operating expenses decreased primarily due to reduced expenses of $4.6 million from shutting in certain fields; other cost reductions measures of $2.6 million; and credits to expense due to prior period royalty adjustments of $1.2 million.  These decreases were partially offset by the acquisitions of the Mobile Bay Properties in August 2019 and the Garden Banks 783/784 ("Magnolia") field in December 2019, which contributed increases of $2.5 million and $2.2 million, respectively, of base lease operating expenses for the three months ended September 30, 2020 compared to the prior year period.  Lastly, we incurred $0.5 million in expenses related to hurricanes during the three months ended September 30, 2020 that we did not incur during the prior year period.  The decreases in workover expense and facility maintenance were due to fewer projects undertaken. 

 

Production taxes.  Production taxes increased $0.7 million to $1.3 million in the three months ended September 30, 2020 compared to the three months ended September 30, 2019 due to the acquisition of the Mobile Bay Properties, which has operations in state waters. 

 

Gathering and transportation.  Gathering and transportation expenses decreased $2.4 million to $3.6 million for the three months ended September 30, 2020 compared to the prior year period primarily due to lower transportation rates at certain fields and the shutting in of certain fields. 

 

Depreciation, depletion, amortization and accretion (“DD&A”).  DD&A, which includes accretion for ARO, decreased to $7.93 per Boe for the three months ended September 30, 2020 from $10.26 per Boe for the three months ended September 30, 2019.  On a nominal basis, DD&A decreased 35.3% to $25.1 million for the three months ended September 30, 2020 from $38.8 million for the three months ended September 30, 2019.  DD&A on a nominal basis decreased largely due to lower DD&A rate per Boe.  The rate per Boe decreased mostly as a result of increases in proved reserves from the acquisition of the Mobile Bay Properties.  Other factors affecting the DD&A rate are capital expenditures, production and revisions to proved reserves volumes.   

 

 

 

General and administrative expenses (“G&A”).  G&A was $14.5 million for the three months ended September 30, 2020, increasing 43.2% from $10.1 million for the three months ended September 30, 2019.  The increase was primarily due to decreased fees for overhead charged to partners (credits to expense) of $2.0 million, increased legal costs of $1.8 million, increased benefit costs of $0.9 million, and reclassification of certain adjustments related to the PPP of $0.7 million, which were partially offset by lower incentive compensation expenses of $1.5 million.  2020 incentive compensation awards have not been granted to date, and therefore, no incentive compensation expense for 2020 has been recorded.  The Compensation Committee has deferred its decision regarding the potential awarding of incentive compensation, including by the exercise of discretion.  G&A on a per Boe basis was $4.57 per Boe for the three months ended September 30, 2020 compared to $2.67 per Boe for the three months ended September 30, 2019.

 

Derivative loss (gain).  The three months ended September 30, 2020 reflects a $11.2 million derivative loss primarily due to increased crude oil prices during September 2020 compared to oil prices during June 2020, which decreased the estimated fair value of open crude oil contracts between the two measurement dates.  Partially offsetting this decrease were realized gains from oil collar contracts where the prevailing oil price was below the contract floor price.  The three months ended September 30, 2019 reflects a $5.9 million derivative gain, primarily due to decreased crude oil prices during September 2019 as compared to oil prices during June 2019, which increased the estimated fair value of open crude oil contracts between the two measurement dates.

 

Interest expense, net.  Interest expense, net, was $14.1 million and $14.4 million for the three months ended September 30, 2020 and 2019, respectively.  The decrease is primarily due to lower principal balances of the Senior Second Lien Notes and reductions to interest expense associated with the PPP of $0.7 million reclassified during the three months ended September 30, 2020; and partially offset by lower interest income.  During the three months ended September 30, 2019, we recorded interest income of $1.9 million due to distribution of funds related to a lawsuit with Apache Corporation ("Apache"). 

 

Income tax benefit.  Our income tax benefit was $21.1 million and $55.5 million for the three months ended September 30, 2020 and 2019, respectively.  For the three months ended September 30, 2020, our income tax benefit was impacted by adjustments recorded related to the enactment of the CARES Act on March 27, 2020 and the issuance by the Treasury of final and proposed regulations under IRC Section 163(j) on July 28, 2020 that provided additional guidance and clarification related to the business interest expense limitation.  During the three months ended September 30, 2019, we reversed a liability related to an uncertain tax position that was resolved and resulted in a net tax benefit for the three months ended September 30, 2019.  Our effective tax rate was not meaningful for the three months ended September 30, 2020 or 2019.  

  

As of September 30, 2020, our valuation allowance was $24.7 million.  We continually evaluate the need to maintain a valuation allowance on our deferred tax assets.  Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

 

 

 

 

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019

 

Due to the decrease and volatility in crude oil prices and to a lesser extent, decreases and volatility in natural gas and prices for NGLs, the results of the nine months ended September 30, 2020 may not be indicative of future periods.  See “Liquidity and Capital Resources – Liquidity Overview” below for additional information.

 

Revenues.  Total revenues decreased $131.1 million, or 34.2%, to $251.9 million for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019.  Oil revenues decreased $136.8 million, or 45.8%, NGLs revenues decreased $2.6 million, or 17.0%, natural gas revenues increased $4.8 million, or 7.4%, and other revenues increased $3.5 million, primarily due to prior period royalty adjustments recorded during the nine months ended September 30, 2020.  The decrease in oil revenues was attributable to a 39.1% decrease in the average realized sales price to $37.17 per barrel for the nine months ended September 30, 2020 from $61.00 per barrel for the nine months ended September 30, 2019, and by a decrease in sales volumes of 11.0%.  The decrease in NGLs revenues was attributable to a 45.9% decrease in the average realized sales price to $9.78 per barrel for the nine months ended September 30, 2020 from $18.07 per barrel for the nine months ended September 30, 2019, partially offset by an increase in sales volumes of 53.3%.  The increase in natural gas revenues was attributable to an increase in sales volumes of 46.8%, and partially offset by a 26.8% decrease in the average realized price to $1.88 per Mcf for the nine months ended September 30, 2020 from $2.57 per Mcf for the nine months ended September 30, 2019.  Overall, sales volumes increased 18.5% on a Boe/day basis.  The largest production increases for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was related to our August 2019 acquisition of the interests in the Mobile Bay Properties, which had net sales volumes of 15,800 Boe per day during the nine months ended September 30, 2020 compared to 2,300 Boe per day for the nine months ended September 30, 2019 and the acquisition of the Magnolia field assets in December 2019, with net sales volumes of 1,900 Boe per day during the nine months ended September 30, 2020.  These increases were partially offset by downtime due to hurricanes, production decreases primarily from natural production declines, and shutting in certain operated and non-operated fields.  Our estimate of deferred production for the nine months ended September 30, 2020 was approximately 7,100 Boe per day as compared to 5,900 Boe per day for the nine months ended September 30, 2019.    

 

Revenues from oil and NGLs as a percent of our total revenues were 69.4% for the nine months ended September 30, 2020 compared to 82.0% for the nine months ended September 30, 2019.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 26.3% for the nine months ended September 30, 2020 compared to 29.6% for the nine months ended September 30, 2019.   

 

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, decreased $11.5 million, or 8.7%, to $119.5 million in the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.  On a component basis, base lease operating expenses increased $4.5 million, workover expenses decreased $7.8 million, and facilities maintenance expense decreased $8.2 million.  Base lease operating expenses increased primarily due to the acquisitions of the Mobile Bay Properties in August 2019 and the Magnolia field in December 2019, which increased base lease operating expenses by $18.4 million and $7.5 million, respectively, for the nine months ended September 30, 2020 compared to the prior year period.  Partially offsetting the increases were reduced expenses of $10.1 million from shutting in certain fields ; other cost reduction measures of $2.7 million; credits to expense due to prior period royalty adjustments of $6.5 million; and credits to expense related to the PPP of $2.3 million.  The decreases in workover expense and facility maintenance were due to fewer projects undertaken.

 

Production taxes.  Production taxes increased $2.0 million to $3.3 million in the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 due to the acquisition of the Mobile Bay Properties, which has operations in state waters. 

 

Gathering and transportation.  Gathering and transportation expenses decreased $7.1 million to $12.3 million for the nine months ended September 30, 2020 from the prior year period primarily due to lower transportation rates at certain fields and the shutting in of certain fields. 

 

Depreciation, depletion, amortization and accretion.  DD&A, which includes accretion for ARO, decreased to $7.90 per Boe for the nine months ended September 30, 2020 from $11.09 per Boe for the nine months ended September 30, 2019.  On a nominal basis, DD&A decreased 15.3% to $93.7 million for the nine months ended September 30, 2020 from $110.7 million for the nine months ended September 30, 2019.  DD&A on a nominal basis decreased largely due to the lower rate per Boe.  The rate per BOE decreased mostly as a result of increases in proved reserves from the acquisition of the Mobile Bay Properties.  Other factors affecting the DD&A rate are capital expenditures, production and revisions to proved reserves volumes.   

 

 

 

General and administrative expenses.  G&A was $34.1 million for the nine months ended September 30, 2020, decreasing 9.3% from $37.5 million for the nine months ended September 30, 2019.  The decrease was primarily due to credits to expense related to the PPP of $4.2 million and lower incentive compensation expenses of $1.1 million, which were partially offset by decreased fees for overhead charged to partners (credits to expense) of $1.0 million and increased legal costs of $0.8 million.  2020 incentive compensation awards have not been granted to date, and therefore, no incentive compensation expense for 2020 has been recorded.  The Compensation Committee has deferred its decision regarding the potential awarding of incentive compensation, including by the exercise of discretion.  G&A on a per Boe basis was $2.87 per Boe for the nine months ended September 30, 2020 compared to $3.76 per Boe for the nine months ended September 30, 2019.

 

Derivative (gain) loss.  The nine months ended September 30, 2020 reflects a $35.3 million derivative gain primarily due to realized gains on oil swap and collar contracts where the prevailing prices were below the strike or floor price.  The nine months ended September 30, 2019 reflects a $41.2 million derivative loss, primarily due to increased crude oil prices during September 2019 as compared to oil prices during December 2018, which decreased the estimated fair value of open crude oil contracts between the two measurement dates.

 

Interest expense, net.  Interest expense, net, was $46.1 million and $42.9 million for the nine months ended September 30, 2020 and 2019, respectively.  The increase is primarily due to lower interest income between the two periods and partially offset by a lower principal balance of the Senior Second Lien Notes.  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 distribution of funds related to a lawsuit with Apache.  Partially offsetting were reductions to interest expense associated with the PPP of $1.9 million recorded during the nine months ended September 30, 2020.  

 

Gain on purchase of debt. A gain of $47.5 million was recorded related to the purchase of $72.5 million of principal of our outstanding Senior Second Lien Notes during the nine months ended September 30, 2020.

 

Income tax expense.  Our income tax benefit was $23.3 million and $67.0 million for the nine months ended September 30, 2020 and 2019, respectively.  For the nine months ended September 30, 2020, our income tax benefit was impacted by adjustments recorded related to the enactment of the CARES Act on March 27, 2020 and the issuance by the Treasury of final and proposed regulations under IRC Section 163(j) on July 28, 2020 that provided additional guidance and clarification related to the business interest expense limitation.  During the nine months ended September 30, 2019, we reversed a liability related to an uncertain tax position that was resolved and resulted in a net tax benefit for the nine months ended September 30, 2019.  Our effective tax rate was not meaningful for the nine months ended September 30, 2020 or 2019.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

 

 

 

Liquidity and Capital Resources

 

Liquidity Overview

 

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.
 

As COVID-19 and other world events impact crude oil prices, and to a lesser degree, natural gas prices, we are actively monitoring the impact on our results of operations, financial position, and liquidity.  As of September 30, 2020, we had $56.5 million cash on hand, availability of $130.6 million under the Credit Agreement and no maturities of long-term debt until 2022.  Nonetheless, the impact of unprecedented decline in oil prices during March and April of 2020 was severe and persistently low oil prices threaten the entire oil and gas industry, including the Company.  Oil prices began recovering starting in May 2020, but not to the levels experienced in 2019.  Natural gas prices have remained approximately at second quarter levels.  In reaction to these events, we moved quickly to preserve resources and protect the health of our employees and contractors.  Furthermore, we have taken certain actions to address the current economic environment as follows:

 

 

We have reduced our capital expenditure budget for the remainder of 2020.  Excluding acquisitions and plugging and abandonment expenditures, we are estimating capital expenditures to be approximately $15 million to $25 million for 2020 (excluding $28 million in working capital changes associated with capital expenditures incurred in 2019 but paid during the nine months ended September 30, 2020).  ARO (plugging and abandonment) spending is estimated to be between of $2 million to $4 million. 

 

 

Since December 31, 2019, we have reduced total long-term debt by $97.5 million, or 13%, resulting in annualized interest expense savings of approximately $8 million.

 

 

On June 17, 2020, we entered into the Third Amendment and Waiver to the Credit Agreement, which, among other things, waived the requirement to comply with the Leverage Ratio (as defined in the Credit Agreement) covenant and replaced it with a first lien leverage covenant of 2.00 to 1.00 through year-end 2021.  We expect these revised requirements will allow us to utilize the full availability under the Credit Agreement, if needed, during the Waiver Period.

 

While we currently expect our cash on hand, net cash provided by operating activities and our available sources of liquidity are sufficient to meet our cash requirements, the Company will continue to monitor the evolving situation. In the event of long-term market deterioration, the Company may need additional liquidity, which would require us to evaluate alternatives and take appropriate actions.

 

 

 

Sources and Uses of Cash 

 

Cash Flow and Working Capital.  Net cash provided by operating activities for the nine months ended September 30, 2020 and 2019 was $114.7 million and $186.6 million, respectively.  Production volumes increased by 18.5% measured on a Boe per day basis due to increases in natural gas and NGLs volumes and partially offset by decreases in oil volumes, which caused revenues to increase by $5.7 million.  Natural gas and NGLs had lower average realized sales prices per Boe as compared to oil.  Our combined average realized sales price per Boe decreased by 45.8% for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, which caused total revenues to decrease $140.4 million.  

 

Other items affecting operating cash flows were lower receivable balances, which increased operating cash flows by $45.0 million for the nine months ended September 30, 2020 compared to a decrease of $19.7 million for the nine months ended September 30, 2019; increased cash advance balances from joint venture partners, which increased operating cash flows by $2.4 million for the nine months ended September 30, 2020 compared to an increase of $15.8 million for the nine months ended September 30, 2019; higher cash derivative receipts, net, which increased operating cash flows by $42.0 million for the nine months ended September 30, 2020 compared to an increase of $17.6 million for the nine months ended September 30, 2019; and a return of collateral related to a bond of $6.9 million which occurred during the nine months ended September 30, 2020.  Other working capital items accounted for the changes 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.  Net cash used in investing activities for the nine months ended September 30, 2020 and 2019 was $41.7 million and $261.2 million, respectively.  Net cash used in investing activities for the nine months ended September 30, 2020 included $28.2 million in working capital changes associated with capital expenditures incurred in 2019 but paid during the nine months ended September 30, 2020.  Our capital expenditures on an occurrence basis for the nine months ended September 30, 2020 were split approximately 20% for investments in the deep waters of the Gulf of Mexico and approximately 80% for investments on the conventional shelf of the Gulf of Mexico.  $167.7 million of net cash used in investing activities for the nine months ended September 30, 2019 was related to the acquisition of the Mobile Bay Properties.

 

Net cash used in financing activities for the nine months ended September 30, 2020 was $ 48.9 million and net cash provided by financing activities was $83.1 million for the nine months ended September 30, 2019.  During the nine months ended September 30, 2020, the borrowings under the Credit Agreement were paid down by $25.0 million, net, and $23.9 million was used to purchase $72.5 million principal of Senior Second Lien Notes on the open market.  Net cash provided by financing activities for the nine months ended September 30, 2019 was primarily related to the acquisition of the Mobile Bay properties.

 

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 the nine months ended September 30, 2020, 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.  

 

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO as of September 30, 2020 and December 31, 2019 were $381.7 million and $355.6 million, respectively.  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, 2019 for additional information.

 

Income Taxes.  We do not expect to make any significant income tax payments during 2020 and we collected the income tax receivable of $1.9 million during the nine months ended September 30, 2020.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

 

 

 

 

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, 2020, we significantly reduced our 2020 capital expenditure budget in response to the uncertain commodity price outlook in light of the COVID-19 pandemic.  The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

 

 

   

Nine Months Ended September 30,

 
   

2020

   

2019

 

Exploration (1)

  $ 1,754     $ 15,262  

Development (1)

    9,187       77,273  

Magnolia and Mobile Bay acquisitions

    456       169,831  

Seismic and other

    2,013       13,528  

Investments in oil and gas property/equipment

  $ 13,410     $ 275,894  

 

 

 

(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,

 
   

2020

   

2019

 

Conventional shelf

  $ 8,611     $ 56,426  

Deepwater

    2,330       36,109  

Exploration and development capital expenditures

  $ 10,941     $ 92,535  

 

 

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheets and recorded on an incurred basis.  The capital expenditures reported within the Investing section of the Condensed Consolidated Statements of Cash Flows include adjustments to report payments related to capital expenditures.  Net cash used in investing activities for the nine months ended September 30, 2020 included $28.2 million in working capital changes associated with capital expenditures incurred in 2019 but paid during the nine months ended September 30, 2020. 

 

Our capital expenditures for the nine months ended September 30, 2020 were financed by cash flow from operations and cash on hand.

 

 Drilling Activity

 

During the nine months ended September 30, 2020, we drilled the East Cameron 349 B-1 well (Cota) to target depth.  We expect initial production to commence in the first half of 2021, subject to completion of certain infrastructure and the level of commodity prices.  The Cota well is in the Joint Venture Drilling Program.  We did not drill any dry holes during the nine months ended September 30, 2020. 

 

 Offshore Lease Awards 

 

During the nine months ended September 30, 2020, we were awarded two blocks in the Gulf of Mexico Lease Sale 254 held by the BOEM on March 18, 2020; one deepwater block, Garden Bank 782, and one shallow water block, Eugene Island Area South Addition block 345.  The two blocks cover a total of approximately 10,760 acres (gross) and we paid $0.7 million combined for 100% working interest in both blocks.  Upon being awarded the Eugene Island South Addition block 345, W&T assigned 50% working interest to a third party pursuant to an Area Mutual Interest Agreement. 

 

 

 

Debt

 

Credit Agreement.  As of September 30, 2020, borrowings outstanding under the Credit Agreement were $80.0 million and letters of credit issued under the Credit Agreement were $4.4 million.  Availability under our Credit Agreement as of September 30, 2020 was $130.6 million.  The Credit Agreement matures on October 18, 2022.

 

On June 17, 2020, the lenders under the Credit Agreement completed their semi-annual borrowing base redetermination at $215.0 million and entered into the Third Amendment and Waiver (the “Third Amendment”) to the Credit Agreement.  Although the Company had not violated any covenants, the Third Amendment provides less stringent covenant requirements given the recent changes in the oil and gas markets.  The Third Amendment includes the following changes, among other things, to the Credit Agreement:

 

 

Increased the interest rate margin by 25 basis points.

 

 

Amended the financial covenants as follows:  

 

 

 

During the Waiver Period, the Company will not be required to comply with the Leverage Ratio covenant.

 

 

 

During the Waiver Period, the Company will be required to maintain a 2.00 to 1.00 ratio limit of first lien debt outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX for the trailing four quarters.

 

 

 

Increase the requirement to provide first priority liens on properties constituting at least 85% to 90% of total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement.

 

The next redetermination will occur in the fall of 2020.  Generally, we must be in compliance with the covenants in our Credit Agreement in order to access borrowings under the Credit Agreement.

 

We currently have six lenders under our Credit Agreement.  While we do not anticipate any difficulties in obtaining funding from any of these lenders as of the date of the filing of this Quarterly Report, 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, 2020, we had outstanding $552.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023.  During the nine months ended September 30, 2020, we purchased $72.5 million in principal of our outstanding Senior Second Lien Notes in the open market for $23.9 million.  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, 2020.  See Financial Statements – Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

 

PPP.  On April 15, 2020, the Company received $8.4 million under the PPP.  During the eligible period, the Company incurred eligible expenses in excess of the amount received.  The PPP funds are structured as a loan, but management of the Company believes the Company has met all the requirements under the PPP to apply for forgiveness of such loan, and management's assessment is it is probable the Company will not be required to repay any of the funds received.  Accordingly, no debt was recorded on the Condensed Consolidated Balance Sheet as of September 30, 2020.  Should the SBA reject the Company's application of the PPP funds being applied to specific covered payroll and non-payroll costs, the Company may be required to repay all or a portion of the funds received under the PPP under an amortization schedule through April 2022 with an annual interest rate of 1%.

 

 

 

Uncertainties

 

Bureau of Ocean Energy Management (“BOEM”) Matters.  In order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases.   As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, BOEM issued the NTL 2016-N01 (the “2016 NTL”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, right-of-ways (“ROWs”) and right of use easements (“RUEs”). The 2016 NTL became effective in September 2016, but BOEM subsequently postponed any implementation of the the 2016 NTL and this extension for implementation currently remains in effect. 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.

 

On October 16, 2020, the BOEM and the BSEE jointly published a proposed rule to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees and RUE and ROW grant holders conducting operations on the federal OCS.  In particular, the proposed rule would:  (i) clarify the sequence for BSEE’s selection of predecessors who have accrued decommissioning obligations and are ordered to perform those obligations when the current lessee or grant holder fails to do so, which sequence is generally in reverse chronological order through the chain-of-title, although BSEE would reserve the right to deviate from this sequence in cases where previously ordered parties fail to pursue specified decommissioning activities, if an emergency condition is declared, or if such an order unreasonably delays decommissioning; (ii) seek to limit the circumstances under which BOEM would require supplemental bonding, with increased focus on a lessee’s, as well as potentially a co-lessee’s or predecessor lessee’s, credit rating rather than relying primarily on a current lessee’s net worth in determining whether additional supplemental bonding is necessary; (iii) relax certain third party guarantee requirements allowed by BOEM in lieu of lessee bonding; (iv) require the posting of bonds in an amount that BSEE determines would be adequate before that party may appeal a decommissioning order; and (v) clarify that all RUE grant holders are jointly and severally liable for BSEE decommissioning obligations associated with RUE-related facilities. Comments on this proposed rule are due to BOEM (as to the BOEM portions of the proposed rule) and BSEE (as to the BSEE portions of the proposed rule) on or before December 15, 2020. We remain in active discussions with industry peers with regard to this proposed rule. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder, as a result of the 2016 NTL, to the extent implemented, as well as to the provisions of any final rule published by BOEM and/or BSEE following the close of the comment period for the October 16, 2020 proposed rule, applicable to our or any of our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

 

Surety Bond Collateral.  Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have historically 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.  These sureties have also returned the posted collateral to us.  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 2020 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.

 

 

 

 

 

Insurance Coverage

 

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, 2020.  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, 2020 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, 2020, and our Energy Package effective on June 1, 2020, 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.

 

Contractual Obligations

 

Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt, Note 5 – Asset Retirement Obligations and Note 12, Subsequent Events under Part I, Item 1 of this Form 10-Q.  As of September 30, 2020, there were no drilling rig commitments.  Except for scheduled utilization, other contractual obligations as of September 30, 2020 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, 2019.

 

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, 2019. 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 the types of market risks for the nine months ended September 30, 2020 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, 2019.  However, the declines in crude oil and natural gas prices have caused, and could continue to cause significant financial impacts to us.  See the Liquidity section in Item II above for a discussion on the possible effects.  In addition, 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, 2019.

 

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 sustained current prices would have significant impacts on our business in the future.  During the nine months ended September 30, 2020, we entered into derivative crude oil and natural gas 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, 2020, we had $80.0 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, 2020, 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, 2020, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings

 

See Financial Statements – Note 11 – Contingencies under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.

 

Item 1A. Risk Factors

 

The COVID-19 pandemic has affected, and may continue to materially adversely affect, our industry, business, financial condition or results of operations.

 

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. The COVID-19 outbreak and the responsive actions to limit the spread of the virus have significantly reduced global economic activity, resulting in a decline in the demand for oil, natural gas, and other commodities. These economic consequences have been a primary cause of the significant supply-and-demand imbalance for oil. The current supply-and-demand imbalance and significantly lower oil pricing may continue to affect us, constraining our ability to store and move production to downstream markets, or affecting future decisions to delay or curtail development activity or temporarily shut-in production which could further reduce cash flow.

 

The extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on the nature, spread and duration of the disease, the responsive actions to contain its spread or address its effects, its effect on the demand for oil and natural gas, the timing and severity of the related consequences on commodity prices and the economy more generally, including any recession resulting from the pandemic, among other things.  Any extended period of depressed commodity prices or general economic disruption as a result of the pandemic would adversely affect our business, financial conditions and results of operations.  In addition, the COVID-19 pandemic has heightened the other risks and uncertainties set forth in the “Risk Factors” section of our Annual Report on Form 10-K for the year 2019.

 

We will likely incur greater costs to bring production associated with our shut-in wells back online, and are unable to predict the production levels of such wells once brought back online.

 

The significant supply/demand balance for oil materially decreased global crude oil prices in the first half of 2020 and generated a surplus of oil.  This significant surplus created a saturation of storage and crude storage constraints, which led us to shut-in production in some of our oil-weighted properties due to the lack of availability and capacity of processing, gathering, storing and transportation systems.  While many of the shut-in fields have been brought back online, some are still shut-in and we will likely incur some costs to bring the associated production back online.  Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings.  If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in.  Such factors could adversely affect our financial condition and results of operations.

 

Investors should carefully consider these risk factors together with all of the other information included in this document, in our Annual Report on Form 10-K for the year 2019, and in our other public filings, press releases and discussions with our management.

 

 

 

 

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

 

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))

     

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))

     

31.1*

 

Section 302 Certification of Chief Executive Officer.

     

31.2*

 

Section 302 Certification of Chief Financial Officer.

     

32.1*

 

Section 906 Certification of Chief Executive Officer and Chief Financial Officer.

     

101.INS*

 

Inline XBRL Instance Document.

     

101.SCH*

 

Inline XBRL Schema Document.

     

101.CAL*

 

Inline XBRL Calculation Linkbase Document.

     

101.DEF*

 

Inline XBRL Definition Linkbase Document.

     

101.LAB*

 

Inline XBRL Label Linkbase Document.

     

101.PRE*

 

Inline XBRL Presentation Linkbase Document.

     
104*   Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

 

 

*

Filed or furnished herewith.

 

 


 

 

SIGNATURE

 

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 5, 2020.

 

W&T OFFSHORE, INC.

 

By:

/s/  Janet Yang

  Janet Yang
 

Executive Vice President and Chief Financial Officer

(Principal Financial Officer), duly authorized to sign on behalf of the registrant

 

 

 

42