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 March 31, 20192020

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 April 29, 2019, June 19, 2020, there were 140,644,033141,778,318 shares outstanding of the registrant’s common stock, par value $0.00001.



Explanatory Note:

As previously disclosed in the Current Report on Form 8-K filed by W&T Offshore, Inc. (the “Company”) on May 5, 2020, the Company expected that the filing of this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 (the “Quarterly Report”), originally due on May 11, 2020, would be delayed due to circumstances related to the outbreak of the coronavirus disease 2019 (“COVID-19”).

In particular, COVID-19 and related precautionary responses had caused the institution of work-from-home policies for our corporate offices which had limited our employees’ access to our facilities and disrupted our normal interactions and workflows among our accounting, financial and legal personnel and other staff and service providers involved in the completion of our quarterly review and preparation of the Quarterly Report. These restrictions had slowed the completion of our internal quarterly review, including evaluating the various impacts of COVID-19 on our financial statements, and our ability to prepare and complete the Quarterly Report in a timely manner.

The Company relied on Release No. 34-88465 issued by the Securities and Exchange Commission on March 25, 2020, pursuant to Section 36 of the Securities Exchange Act of 1934, as amended, to delay the filing of the Quarterly Report.


 

 


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 March 31, 20192020 and December 31, 20182019

1

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 20192020 and 20182019

2

Condensed Consolidated StatementStatements of Changes in Shareholders’ Deficit for the Three Months Ended March 31, 2020 and 2019 and 2018

3

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 20192020 and 20182019

4

Notes to Condensed Consolidated Financial Statements

5

Item 2.

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

21

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

31

33

Item 4.

Controls and Procedures

32

33

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

33

34

Item 1A.

Risk Factors

33

34
Item 5.Other Information35

Item 6.

Exhibits

34

36

SIGNATURE

35

37


 


PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

March 31,

 

 

December 31,

 

 

March 31,

  

December 31,

 

2019

 

 

2018

 

 

2020

  

2019

 

Assets

 

 

        

Current assets:

 

 

 

 

 

 

 

        

Cash and cash equivalents

$

86,116

 

 

$

33,293

 

 $47,574  $32,433 

Receivables:

 

 

 

 

 

 

 

        

Oil and natural gas sales

 

41,308

 

 

 

47,804

 

  35,413   57,367 

Joint interest, net

 

17,620

 

 

 

14,634

 

Joint interest and other, net

  12,277   19,400 

Income taxes

 

54,076

 

 

 

54,076

 

  1,861   1,861 

Total receivables

 

113,004

 

 

 

116,514

 

  49,551   78,628 

Prepaid expenses and other assets (Note 1)

 

34,127

 

 

 

76,406

 

  78,658   30,691 

Total current assets

 

233,247

 

 

 

226,213

 

  175,783   141,752 

 

 

 

 

 

 

 

        

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

 

514,765

 

 

 

515,421

 

  730,044   748,798 
        

Restricted deposits for asset retirement obligations

 

15,498

 

 

 

15,685

 

  15,574   15,806 

Deferred income taxes

  57,418   63,916 

Other assets (Note 1)

 

79,005

 

 

 

91,547

 

  30,084   33,447 

Total assets

$

842,515

 

 

$

848,866

 

 $1,008,903  $1,003,719 

Liabilities and Shareholders’ Deficit

 

 

 

 

 

 

 

        

Current liabilities:

 

 

 

 

 

 

 

        

Accounts payable

$

71,359

 

 

$

82,067

 

 $61,729  $102,344 

Undistributed oil and natural gas proceeds

 

22,014

 

 

 

28,995

 

  28,176   29,450 

Advances from joint interest partners

 

65,271

 

 

 

20,627

 

  18,285   5,279 

Asset retirement obligations

 

24,799

 

 

 

24,994

 

  2,803   21,991 

Accrued liabilities (Note 1)

 

35,197

 

 

 

29,611

 

  34,428   30,896 

Total current liabilities

 

218,640

 

 

 

186,294

 

  145,421   189,960 

 

 

 

 

 

 

 

        

Long-term debt (Note 2)

 

634,005

 

 

 

633,535

 

Long-term debt: (Note 2)

        

Principal

  677,525   730,000 

Carrying value adjustments

  (9,467)  (10,467)

Long term debt - carrying value

  668,058   719,533 
        

Asset retirement obligations, less current portion

 

289,363

 

 

 

285,143

 

  361,297   333,603 

Other liabilities (Note 1)

 

73,142

 

 

 

68,690

 

  16,464   9,988 

Commitments and contingencies (Note 10)

 

 

 

 

 

Commitments and contingencies

      

Shareholders’ deficit:

 

 

 

 

 

 

 

        

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

for both dates presented

 

 

 

 

 

      

Common stock, $0.00001 par value; 200,000 shares authorized;

143,513 issued and 140,644 outstanding for both dates presented

 

1

 

 

 

1

 

Common stock, $0.00001 par value; 200,000 shares authorized; 144,538 issued and 141,669 outstanding for both dates presented

  1   1 

Additional paid-in capital

 

545,627

 

 

 

545,705

 

  548,098   547,050 

Retained deficit

 

(894,096

)

 

 

(846,335

)

  (706,269)  (772,249)

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

 

(24,167

)

 

 

(24,167

)

  (24,167)  (24,167)

Total shareholders’ deficit

 

(372,635

)

 

 

(324,796

)

  (182,337)  (249,365)

Total liabilities and shareholders’ deficit

$

842,515

 

 

$

848,866

 

 $1,008,903  $1,003,719 

 

See Notes to Condensed Consolidated Financial Statements.Statements


1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

Three Months Ended

 

March 31,

 

 

Three Months Ended March 31,

 

2019

 

 

2018

 

 

2020

  

2019

 

Revenues:

 

 

 

 

 

 

 

        

Oil

$

86,703

 

 

$

97,306

 

 $84,650  $86,703 

NGLs

 

6,448

 

 

 

9,660

 

  6,452   6,448 

Natural gas

 

21,838

 

 

 

25,867

 

  29,300   21,838 

Other

 

1,091

 

 

 

1,380

 

  3,726   1,091 

Total revenues

 

116,080

 

 

 

134,213

 

  124,128   116,080 

Operating costs and expenses:

 

 

 

 

 

 

 

        

Lease operating expenses

 

43,456

 

 

 

36,843

 

  54,775   43,456 

Production taxes

 

416

 

 

 

455

 

  916   416 

Gathering and transportation

 

6,423

 

 

 

5,057

 

  5,449   6,423 

Depreciation, depletion, amortization and accretion

 

33,766

 

 

 

38,081

 

  39,126   33,766 

General and administrative expenses

 

14,109

 

 

 

15,038

 

  13,963   14,109 

Derivative loss

 

48,886

 

 

 

 

Derivative (gain) loss

  (61,912)  48,886 

Total costs and expenses

 

147,056

 

 

 

95,474

 

  52,317   147,056 

Operating (loss) income

 

(30,976

)

 

 

38,739

 

Operating income (loss)

  71,811   (30,976)

Interest expense, net

 

16,282

 

 

 

10,962

 

  17,110   16,282 

Gain on purchase of debt

  (18,501)   

Other expense, net

 

331

 

 

 

28

 

  723   331 

(Loss) income before income tax expense

 

(47,589

)

 

 

27,749

 

Income (loss) before income tax expense

  72,479   (47,589)

Income tax expense

 

172

 

 

 

109

 

  6,499   172 

Net (loss) income

$

(47,761

)

 

$

27,640

 

Basic and diluted (loss) earnings per common share

$

(0.34

)

 

$

0.19

 

Net income (loss)

 $65,980  $(47,761)

Basic and diluted earnings (loss) per common share

 $0.46  $(0.34)

 

See Notes to Condensed Consolidated Financial Statements.

 

2

Table of Contents

 


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)

 

Common Stock

Outstanding

 

 

Additional

Paid-In

 

 

Retained

 

 

Treasury Stock

 

 

Total

Shareholders’

 

 

Common Stock Outstanding

  

Additional Paid-In

  

Retained

  

Treasury Stock

  

Total Shareholders’

 

Shares

 

 

Value

 

 

Capital

 

 

Deficit

 

 

Shares

 

 

Value

 

 

Deficit

 

 

Shares

  

Value

  

Capital

  

Deficit

  

Shares

  

Value

  

Deficit

 

Balances at December 31, 2018

 

140,644

 

 

$

1

 

 

$

545,705

 

 

$

(846,335

)

 

 

2,869

 

 

$

(24,167

)

 

$

(324,796

)

Balances, December 31, 2018

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

Share-based compensation

 

 

 

 

 

 

 

(78

)

 

 

 

 

 

 

 

 

 

 

 

(78

)

        (78)           (78)

Net loss

 

 

 

 

 

 

 

 

 

 

(47,761

)

 

 

 

 

 

 

 

 

(47,761

)

           (47,761)        (47,761)

Balances at March 31, 2019

 

140,644

 

 

$

1

 

 

$

545,627

 

 

$

(894,096

)

 

 

2,869

 

 

$

(24,167

)

 

$

(372,635

)

Balances, March 31, 2019

  140,644  $1  $545,627  $(894,096)  2,869  $(24,167) $(372,635)

 

 

 

Common Stock

Outstanding

 

 

Additional

Paid-In

 

 

Retained

 

 

Treasury Stock

 

 

Total

Shareholders’

 

 

Common Stock Outstanding

  

Additional Paid-In

  

Retained

  

Treasury Stock

  

Total Shareholders’

 

Shares

 

 

Value

 

 

Capital

 

 

Deficit

 

 

Shares

 

 

Value

 

 

Deficit

 

 

Shares

  

Value

  

Capital

  

Deficit

  

Shares

  

Value

  

Deficit

 

Balances at December 31, 2017

 

139,091

 

 

$

1

 

 

$

545,820

 

 

$

(1,095,162

)

 

 

2,869

 

 

$

(24,167

)

 

$

(573,508

)

Balances, December 31, 2019

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

Share-based compensation

 

 

 

 

 

 

 

1,219

 

 

 

 

 

 

 

 

 

 

 

 

1,219

 

        1,048            1,048 

Net income

 

 

 

 

 

 

 

 

 

 

27,640

 

 

 

 

 

 

 

 

 

27,640

 

           65,980         65,980 

Balances at March 31, 2018

 

139,091

 

 

$

1

 

 

$

547,039

 

 

$

(1,067,522

)

 

 

2,869

 

 

$

(24,167

)

 

$

(544,649

)

Balances, March 31, 2020

  141,669  $1  $548,098  $(706,269)  2,869  $(24,167) $(182,337)

 

See Notes to Condensed Consolidated Financial Statements

 

3

Table of Contents

 


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

Three Months Ended

 

March 31,

 

 

Three Months Ended March 31,

 

2019

 

 

2018

 

 

2020

  

2019

 

Operating activities:

 

 

 

 

 

 

 

        

Net (loss) income

$

(47,761

)

 

$

27,640

 

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 

 

 

 

 

 

 

Net income (loss)

 $65,980  $(47,761)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

        

Depreciation, depletion, amortization and accretion

 

33,766

 

 

 

38,081

 

  39,126   33,766 

Amortization of debt items and other items

 

1,152

 

 

 

466

 

  1,625   1,152 

Share-based compensation

 

(78

)

 

 

1,219

 

  1,048   (78)

Derivative loss

 

48,886

 

 

 

 

Derivative (gain) loss

  (61,912)  48,886 

Cash receipts on derivative settlements, net

 

11,948

 

 

 

 

  4,404   11,948 

Deferred income taxes

 

172

 

 

 

109

 

Gain on purchase of debt  (18,501)   

Deferred Income taxes

  6,499   172 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

        

Oil and natural gas receivables

 

6,496

 

 

 

501

 

  21,954   6,496 

Joint interest receivables

 

(2,986

)

 

 

1,919

 

  7,123   (2,986)

Prepaid expenses and other assets

 

(4,269

)

 

 

(6,391

)

  11,011   (4,269)

Asset retirement obligation settlements

 

(254

)

 

 

(7,022

)

  (249)  (254)

Cash advances from JV partners

 

44,644

 

 

 

19,147

 

  13,006   44,644 

Accounts payable, accrued liabilities and other

 

(6,871

)

 

 

(688

)

  (6,790)  (6,871)

Net cash provided by operating activities

 

84,845

 

 

 

74,981

 

  84,324   84,845 

Investing activities:

 

 

 

 

 

 

 

        

Investment in oil and natural gas properties and equipment

 

(31,581

)

 

 

(38,271

)

  (33,575)  (31,581)

Deposit for acquisition

 

 

 

 

(3,000

)

Acquisition of property interest

  (2,002)   

Purchases of furniture, fixtures and other

  (70)   

Net cash used in investing activities

 

(31,581

)

 

 

(41,271

)

  (35,647)  (31,581)

Financing activities:

 

 

 

 

 

 

 

        

Payment of interest on 1.5 Lien Term Loan

 

 

 

 

(2,057

)

Debt issuance costs

 

(441

)

 

 

 

Repayments on credit facility

  (25,000)   

Purchase of Senior Second Lien Notes

  (8,536)   

Debt issuance costs and other

     (441)

Net cash used in financing activities

 

(441

)

 

 

(2,057

)

  (33,536)  (441)

Increase in cash and cash equivalents

 

52,823

 

 

 

31,653

 

  15,141   52,823 

Cash and cash equivalents, beginning of period

 

33,293

 

 

 

99,058

 

  32,433   33,293 

Cash and cash equivalents, end of period

$

86,116

 

 

$

130,711

 

 $47,574  $86,116 

See Notes to Condensed Consolidated Financial Statements.

 

4

Table of Contents

 


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLID
ATEDCONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Basis of Presentation

1.

Basis of Presentation

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

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

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year.  These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.2019.

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.

Leases.

Recent Events.  The pandemic spread of the disease caused by a new strain of coronavirus (“COVID-19”) and other worldly events have significantly impacted the price of crude oil and the demand for crude oil beginning in March of 2020.  While crude oil prices have partially recovered in June 2020 from recent historical lows in April 2020, the perceived risks and volatility have increased in 2020 to date compared to recent years.  See Note 12, Subsequent Events, for additional information.  

Accounting Standard Updates effective January 1, 2020 

Credit Losses -  In FebruaryJune 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2016-02, Leases(“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 842326) (“ASU 2016-02”2016-13”) wasand subsequently issued requiringadditional 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 recognize a right-of-use (“ROU”) assetpresent 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 lease liabilitycosts of an entity’s hedging program.  Also, relative to current GAAP, this approach simplifies the financial statement reporting for all leases.  The classification of leasesqualifying hedging relationships.  As we do not designate our commodity derivative instruments as either a finance or operating lease determinesqualifying hedging instruments, this amendment did not impact the recognition, measurement and presentation of expenses.  ASU 2016-02 also requires certain quantitative and qualitative disclosures about leasing arrangements.  Leases acquired to explore for or extract oil or natural gas resources, including the right to explore for those natural resources and rights to use the landchanges in which those natural resources are contained, are not within the scopefair values of this standard’s update.

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

 

 

5


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

 

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

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

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

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

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

not separate nonlease and lease components.

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

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

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

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

 

 

March 31, 2019

 

ROU:

 

 

 

 

Prepaid expenses and other current assets:

 

$

1,095

 

Other assets

 

 

3,856

 

Total ROU

 

$

4,951

 

 

 

 

 

 

Lease liability:

 

 

 

 

Accrued liabilities

 

$

1,095

 

Other liabilities

 

 

3,856

 

Total lease liability

 

$

4,951

 

 

 

 

 

 

Lease incentives:

 

 

 

 

Prepaid expenses and other current assets (contra-asset)

 

$

(213

)

Other assets (contra-asset)

 

 

(795

)

Total lease incentives

 

$

(1,008

)

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

6


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

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

Reclassifications.  Certain reclassifications

Credit Risk and Allowance for Credit Losses.  Our revenue has been concentrated in certain major oil and gas companies.  For the year ended December 31, 2019 and for the three months ended March 31, 2020, approximately 63% and 57%, 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 been madereceivables related to joint interest arrangements primarily with mid-size oil and gas companies with a substantial majority of the prior period financial statementsnet receivable balance concentrated in less than ten companies.  A loss methodology is used to conformdevelop the allowance for credit losses on material receivables to estimate the net amount to be collected.  The loss methodology uses historical data, current presentation as follows:  Inmarket conditions and forecasts of future economic conditions.  Our maximum exposure at any time would be the Condensed Consolidated Statements of Operations,receivable balance.  The receivables, Joint interest income was reclassified from Other expense,and other, net to Interest expense, net, which did not change Net (loss) income before income tax expense.  In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net Cash Used in Investing Activities of which did not change the total amount previous reported.  The adjustments did not affectreported on the Condensed Consolidated Balance Sheets.Sheets are reduced for the allowance for credit losses.  The roll forward of the allowance for credit losses is as follows: 

Allowance for credit losses, December 31, 2019

 $9,898 

Additional provisions

  36 

Uncollectible accounts written off

   

Allowance for credit losses, March 31, 2020

 $9,934 

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):

 

March 31,

 

 

December 31,

 

 

March 31, 2020

  

December 31, 2019

 

2019

 

 

2018

 

Derivative assets (1)

$

16,959

 

 

$

60,687

 

Derivatives - current (1)

 $64,039  $7,266 

Unamortized bond/insurance premiums

 

4,944

 

 

 

5,197

 

  4,478   4,357 

Prepaid deposits related to royalties

 

8,871

 

 

 

8,872

 

  7,555   7,980 

Prepayment to vendors

  1,825   10,202 

Other

 

3,353

 

 

 

1,650

 

  761   886 

Prepaid expenses and other assets

$

34,127

 

 

$

76,406

 

 $78,658  $30,691 

 

(1)

Includes closed contracts which have not yet settled.

Oil and Natural Gas Properties and Other, Net at cost.  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):

 

March 31,

 

 

December 31,

 

 

March 31, 2020

  

December 31, 2019

 

2019

 

 

2018

 

Oil and natural gas properties and equipment

$

8,198,394

 

 

$

8,169,871

 

Oil and natural gas properties and equipment, at cost

 $8,546,778  $8,532,196 

Furniture, fixtures and other

 

20,228

 

 

 

20,228

 

  20,387   20,317 

Total property and equipment

 

8,218,622

 

 

 

8,190,099

 

  8,567,165   8,552,513 

Less accumulated depreciation, depletion and amortization

 

7,703,857

 

 

 

7,674,678

 

Less: Accumulated depreciation, depletion and amortization

  7,837,121   7,803,715 

Oil and natural gas properties and other, net

$

514,765

 

 

$

515,421

 

 $730,044  $748,798 

7

6

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

 

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

 

March 31,

 

 

December 31,

 

 

March 31, 2020

  

December 31, 2019

 

2019

 

 

2018

 

Escrow deposit - Apache lawsuit

$

49,500

 

 

$

49,500

 

Derivative assets

 

4,169

 

 

 

21,275

 

Appeal bond deposits

 

6,925

 

 

 

6,925

 

Right-of-Use assets (Note 7)

 $12,745  $7,936 

Unamortized debt issuance costs

 

4,511

 

 

 

4,773

 

  3,458   3,798 

Investment in White Cap, LLC

 

2,546

 

 

 

2,586

 

  2,917   2,590 

Unamortized brokerage fee for Monza

 

3,746

 

 

 

2,277

 

  2,881   3,423 

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

 

3,299

 

 

 

3,275

 

  4,222   5,308 

Derivative assets

  2,847   2,653 

Appeal bond deposits

     6,925 

Other

 

4,309

 

 

 

936

 

  1,014   814 

Total other assets (long-term)

$

79,005

 

 

$

91,547

 

 $30,084  $33,447 

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

 

March 31,

 

 

December 31,

 

2019

 

 

2018

 

 

March 31, 2020

  

December 31, 2019

 

Accrued interest

$

27,624

 

 

$

12,385

 

 $24,497  $10,180 

Accrued salaries/payroll taxes/benefits

 

2,425

 

 

 

2,320

 

  2,715   2,377 

Incentive compensation plans

 

 

 

 

10,817

 

  1,069   9,794 

Litigation accruals

 

3,673

 

 

 

3,673

 

  3,673   3,673 

Lease liability (Note 7)

  2,472   2,716 

Derivatives - current

     1,785 

Other

 

1,475

 

 

 

416

 

  2   371 

Total accrued liabilities

$

35,197

 

 

$

29,611

 

 $34,428  $30,896 

 

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

 

March 31,

 

 

December 31,

 

 

March 31, 2020

  

December 31, 2019

 

2019

 

 

2018

 

Apache lawsuit

$

49,500

 

 

$

49,500

 

Uncertain tax positions including interest/penalties

 

11,694

 

 

 

11,523

 

Dispute related to royalty deductions

 

4,687

 

 

 

4,687

 

 $4,687  $4,687 

Dispute related to royalty-in-kind

 

2,164

 

 

 

2,135

 

  250   250 
Derivatives  1,245    

Lease liability (Note 7)

  9,581   4,419 

Other

 

5,097

 

 

 

845

 

  701   632 

Total other liabilities (long-term)

$

73,142

 

 

$

68,690

 

 $16,464  $9,988 

 

Recent Accounting Developments. 

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

7

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8


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

 

2.

Long-Term Debt

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

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

2.  Long-Term Debt

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

March 31,

 

 

December 31,

 

 

March 31, 2020

  

December 31, 2019

 

Credit Agreement borrowings

 $80,000  $105,000 

2019

 

 

2018

 

        

Credit Agreement (1) borrowings

$

21,000

 

 

$

21,000

 

 

 

 

 

 

 

 

Senior Second Lien Notes: (1)

 

 

 

 

 

 

 

Senior Second Lien Notes:

        

Principal

 

625,000

 

 

 

625,000

 

  597,525   625,000 

Unamortized debt issuance costs

 

(11,995

)

 

 

(12,465

)

  (9,467)  (10,467)

Total Senior Second Lien Notes (1)

 

613,005

 

 

 

612,535

 

Total Senior Second Lien Notes

  588,058   614,533 

 

 

 

 

 

 

 

        

Total long-term debt

$

634,005

 

 

$

633,535

 

 $668,058  $719,533 

 

(1)

Defined below

9


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

 

Credit Agreement

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

TheAs of March 31, 2020, the borrowing base and lending commitment was $250.0 million as of the filing date of this Form 10-Q.million.

Letters of credit may be issued in amounts up to $30.0 million, provided sufficient availability under the Credit Agreement exists.  As of March 31, 2019,2020 and December 31, 2018,2019, we had $8.1$5.8 million and $9.6 million, respectively, of letters of credit issued and outstanding under the Credit Agreement.

The Leverage Ratio is limited to 3.50 to 1.00 forFor the period ended March 31, 2019; 3.25 to 1.00 for quarters ending June 30, 2019 and September 30, 2019; and 3.00 to 1.00 for quarters ending December 31, 2019 and thereafter.  In the event of a Material Acquisition,2020, the Leverage Ratio limit is 3.50must not exceed 3.00 to 1.00 for1.00.  

For the two quarters following a Material Acquisition.  

Theperiod ended March 31, 2020, the Current Ratio must be maintained at greater than 1.00 to 1.00.

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur onin or beforearound May 15 and November 14of each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company.  The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement.  See Note 12, Subsequent Events, for revisions to certain terms of the Credit Agreement, including the borrowing base, Leverage Ratio and collateral, resulting from the Spring 2020 semi-annual redetermination.

The Credit Agreement’s securityAgreement is collateralized by a first priority lien on substantially allproperties constituting at least 85% of our oil and natural gas propertiesthe 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 three months ended March 31, 20192020 was 5.1%4.5%, which which excludes debt issuance costs, commitment fees and other fees.

8

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%10.4%, whichwhich 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, beginningyear.

During the three months ended March 31, 2020, we acquired $27.5 million in principal of our outstanding Senior Second Lien Notes for $8.5 million and recorded a non-cash gain on May 1, 2019.purchase of debt of $18.5 million, which included a reduction of $0.4 million related to the write-off of unamortized debt issuance costs. The Company purchased additional Senior Second Lien Notes subsequent to March 31, 2020 (refer to Note 12, Subsequent Events).

 

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

10


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

Covenants 

Covenants 

As of March 31, 2019,2020 and for all prior measurement periods, we were in compliance with all applicable covenants of the Credit Agreement and Senior Second Lien Notes indenture.the Indenture.

Fair Value Measurements

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

3.  Fair Value Measurements  

9

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):

 

March 31,

 

 

December 31,

 

 

2019

 

 

2018

 

 

March 31, 2020

  

December 31, 2019

 

Assets:

 

 

 

 

 

 

 

 

        

Derivatives instruments - open contracts

 

$

20,275

 

 

$

74,580

 

Derivatives instruments - open contracts, current

 $54,358  $6,921 

Derivatives instruments - open contracts, long-term

  2,847   2,653 
        

Liabilities:

        

Derivatives instruments - open contracts, current

     1,785 
Derivatives instruments - open contracts, long-term  1,245    

Long-Term Debt

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

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

 

March 31, 2019

 

 

December 31, 2018

 

 

March 31, 2020

  

December 31, 2019

 

 

Carrying Value

 

 

Fair Value

 

 

Carrying Value

 

 

Fair Value

 

 

Carrying Value

  

Fair Value

  

Carrying Value

  

Fair Value

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

                

Credit Agreement

 

$

21,000

 

 

$

21,000

 

 

$

21,000

 

 

$

21,000

 

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

Senior Second Lien Notes

 

 

613,005

 

 

 

623,256

 

 

 

612,535

 

 

 

546,875

 

  588,058   136,421   614,533   597,188 

10

Table of Contents

 

11


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

4.

Joint Venture Drilling Program

 

4.  Joint Venture Drilling Program

OnIn March 12, 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with us in the exploration, drilling and development of up to 14 identifiedcertain drilling projects (the “JV“Joint Venture Drilling Program”) in the Gulf of Mexico.  The projects are expected to be completed during the years 2018 through 2020, but some projects may possibly extend into years beyond 2020.  W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest.  Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T,&T's commitment to fund its retained interest in Monza projects held outside of Monza, are $361.4 million.  Through March 31, 2020, nine wells have been completed.  As of March 31, 2020, one additional well was drilled to target depth, but not completed as of this date.  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 JVJoint 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 uponagreed-upon rates.  Any exceptions to this structure are approved by the Monza board.  W&T is or will be the operator for seven of each well in the JV Drilling Program unless there is a designated third-party operator.nine wells completed through March 31, 2020.  

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

 As

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 March 31, 2019,2020, members of Monza made partner capital contribution paymentscontributions, including our contributions of working interest in the drilling projects, to Monza totaling $184.9$289.3 million of which $70.2 million was contributed during the three months ended March 31, 2019.and received cash distributions totaling $45.9 million.  Our net contribution to Monza, reduced by distributions received, as of March 31, 20192020 was $58.9$57.1 million.  W&T may beis obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for the JVJoint Venture Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

Consolidation and Carrying Amounts.Amounts

Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation.  Through March 31, 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 and we utilize proportional consolidation to account for our interests in the Monza properties.of Monza.  As of March 31, 2019,2020, in the Condensed Consolidated Balance Sheet, we recorded $11.0$15.1 million, net, in Oil and natural gas properties and other, net,, $3.3 $4.2 million in Other assets, $0.1 million in ARO and $5.0$2.4 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  As of December 31, 2018,2019, in the Condensed Consolidated Balance Sheet, we recorded $8.8$16.1 million, net, in Oil and natural gas properties and other, net,, $3.3 $5.3 million in Other assets, $0.1 million in ARO and $0.7$2.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  Additionally, during the three months ended March 31, 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 March 31, 2020 and December 31, 2019 were $18.3 million and $5.3 million, respectively, which are included in the Consolidated Balance Sheet in Advances from joint interest partners.  For the three months ended March 31, 2019,2020, in the Consolidated Statement of Operations, we recorded $1.6$3.3 million in Total revenues and $0.9$3.1 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.  No revenues or expenses were recorded inFor the three months ended March 31, 20182019, in the Consolidated Statement of Operations, we recorded $1.6 million in Total revenues and, $0.9 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.

Additionally, during the three-months ended March 31, 2019, we received cash calls from Monza

11

12


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

 

5.

Asset Retirement Obligations

5.  Asset Retirement Obligations

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

 

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

 

Balance, December 31, 2018

$

310,137

 

Balances, December 31, 2019

 $355,594 

Liabilities settled

 

(254

)

  (249)

Accretion of discount

 

4,588

 

  5,716 

Liabilities incurred

 

44

 

Liabilities incurred, including acquisitions

  2,704 

Revisions of estimated liabilities

 

(353

)

  335 

Balance, March 31, 2019

 

314,162

 

Balances, March 31, 2020

  364,100 

Less current portion

 

24,799

 

  2,803 

Long-term

$

289,363

 

 $361,297 

 

6.

Derivative Financial Instruments

6.  Derivative Financial Instruments

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

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

During 2018, we

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 wereare based on West Texas Intermediate (“WTI”) crude oil prices asand the natural gas contracts are based off the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  The open contracts as of March 31, 20192020 are presented in the following tables:

 

Crude Oil:  Swap, Priced off WTI (NYMEX)

 

Termination Period

 

Notional Quantity (Bbls/day) (1)

 

 

Notional Quantity

(Bbls) (1)

 

 

Strike Price

 

May 2020

 

 

1,500

 

 

 

640,500

 

 

$

60.80

 

May 2020

 

 

5,000

 

 

 

2,135,000

 

 

 

61.00

 

May 2020

 

 

3,500

 

 

 

1,494,500

 

 

 

60.85

 

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

 Period

 

 Notional Quantity (Bbls/day) (1)

 

 Notional Quantity
(Bbls) (1)

 

 Weighted Average Strike Price

Apr 2020 - May 2020

 

10,000

 

610,000

 

$ 60.92

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

Period

 

 Notional Quantity (Bbls/day) (1)

 

 Notional Quantity
(Bbls) (1)

 

 Strike Price

Apr 2020 - May 2020

 

10,000

 

610,000

 

$ 61.00

       

June 2020 - Dec. 2020

 

10,000

 

2,140,000

 

$ 67.50

(1)

Bbls = Barrels

12

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

 

 

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

 

Termination Period

 

Notional Quantity (Bbls/day) (1)

 

 

Notional Quantity

(Bbls) (1)

 

 

Strike Price

 

May 2020

 

 

10,000

 

 

 

4,270,000

 

 

$

61.00

 

(1)

Bbls = Barrels

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)

June 2020 - Dec. 2020

 

10,000

 

2,140,000

 

$ 45.00

 

$ 63.51

 

Natural Gas:  Two-way collars, Priced off Henry Hub (NYMEX)

 

Termination Period

 

Notional Quantity (MMBtu/day) (1)

 

 

Notional Quantity (MMBtu) (1)

 

 

Put Option

Strike Price

(Bought)

 

 

Call Option

Strike Price

(Sold)

 

June 2019

 

 

50,000

 

 

 

3,050,000

 

 

$

2.49

 

 

$

3.975

 

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

Period

 

Notional Quantity (MMBtu/day) (2)

 

Notional Quantity (MMBtu) (2)

 

Put Option Strike Price (Bought)

 

Call Option Strike Price (Sold)

May 2020 - Dec. 2022

 

40,000

 

39,000,000

 

$ 1.83

 

$ 3.00

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

Period

 

Notional Quantity (MMBtu/day) (2)

 

Notional Quantity (MMBtu) (2)

 

Strike Price

May 2020 - Dec. 2022

 

40,000

 

39,000,000

 

$ 3.00

(1)(2)

MMBtu = Million British Thermal Units

 

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):

 

March 31,

 

 

December 31,

 

March 31,

 

December 31,

2019

 

 

2018

 

2020

 

2019

Prepaid expenses and other assets

$

16,959

 

 

$

60,687

 

$ 64,039

 

$ 7,266

Other assets (non-current)

 

4,169

 

 

 

21,275

 

Other assets (long-term)

2,847

 

2,653

Accrued liabilities 1,785
Other liabilities (long-term)1,245 

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

 

 

March 31,

 

 

2019

 

 

2018

 

Derivative loss

$

48,886

 

 

$

 

 

Three Months Ended March 31,

 

2020

 

2019

Derivative (gain) loss

$ (61,912)

 

$ 48,886

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

 

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):

 

Three Months Ended

 

 

March 31,

 

 

2019

 

 

2018

 

Cash receipts on derivative settlements, net

$

11,948

 

 

$

 

  

Three Months Ended March 31,

 
  

2020

  

2019

 

Cash receipts on derivative settlements, net

 $4,404  $11,948 

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. 

During the three months ended March 31, 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):

  

March 31, 2020

  

December 31, 2019

 

ROU assets

 $12,745  $7,936 
         

Lease liability:

        

Accrued liabilities

 $2,472  $2,716 

Other liabilities

  9,581   4,419 

Total lease liability

 $12,053  $7,135 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

8.

Share-Based Compensation and Cash-Based Incentive Compensation

 

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

Awards to Employees. In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by our shareholders.  During 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 weremay be used as a short-term and long-term compensation componentcomponents of the 2018 awards, and wereare subject to satisfaction of certain predetermined performance criteria.

As of March 31, 2019,2020, there were 11,852,59210,874,043 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 wereare 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 20172018 grants which were subject to predetermined performance criteria applied against the applicable performance period.  TheseAll the RSUs continue to becurrently 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 three months ended March 31, 20192020 is as follows:

 

 

Restricted Stock Units

 

 

 

 

 

 

Weighted Average

 

 

 

 

 

 

Grant Date Fair

 

 

Units

 

 

Value Per Unit

 

Nonvested, December 31, 2018

 

3,355,917

 

 

$

3.90

 

Forfeited (1)

 

(856,718

)

 

 

2.77

 

Nonvested, March 31, 2019

 

2,499,199

 

 

 

4.28

 

  

Restricted Stock Units

 
      

Weighted Average

 
      

Grant Date Fair

 
  

Units

  

Value Per Unit

 

Nonvested, December 31, 2019

  1,614,722   $5.73 

Forfeited

  (22,645)  6.37 

Nonvested, March 31, 2020

  1,592,077   5.72 

 

(1)

Primarily related to a former executive’s forfeitures.

 

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

For the outstanding RSUs issued to the eligible employees as of March 31, 2019,2020, vesting is expected to occur as follows (subject to forfeitures): 

 

Restricted Stock Units

 

 

Restricted Stock Units

 

2019

 

1,579,140

 

2020

 

920,059

 

  803,995 

2021

  788,082 

Total

 

2,499,199

 

  1,592,077 

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

Awards to Non-Employee Directors.  Under the W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, the “Director Compensation Plan”), shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during 2019, 2018 2017 and 2016.2017.  As of March 31, 2019,2020, there were 128,98082,620 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  During the second quarter of 2020, our shareholders approved increasing the shares available by 500,000 shares.  During the second quarter of 2020, 109,376 Restricted Shares were granted to non-employee directors.  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.

There was no activity related to Restricted Shares during the three months ended March 31, 2020.

For the outstanding Restricted Shares issued to the non-employee directors as of March 31, 2019,2020, vesting is expected to occur as follows (subject to any forfeitures):

Restricted Shares

 

 

Restricted Shares

 

2019

 

105,012

 

2020

 

62,972

 

  78,424 

2021

 

13,848

 

  29,300 

2022

  15,456 

Total

 

181,832

 

  123,180 

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

 

Three Months Ended

 

March 31,

 

 

Three Months Ended March 31,

 

2019

 

 

2018

 

 

2020

  

2019

 

Share-based compensation expense from:

 

 

 

 

 

 

 

        

Restricted stock units (1)

$

(148

)

 

$

1,149

 

 $978  $(148)

Restricted Shares

 

70

 

 

 

70

 

  70   70 

Total

$

(78

)

 

$

1,219

 

 $1,048  $(78)

(1)

For the three months ended March 31, 2019, period, the net credit is due toshare-based compensation expense includes adjustments for a former executive’sexecutive's' forfeitures.

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

 

Unrecognized Share-Based Compensation.As of March 31, 2019,2020, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $5.5$4.0 million and $0.3$0.4 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 20202021 for RSUs and April 20212022 for Restricted Shares.

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

Cash-Based Incentive Compensation.  In addition to share-based awards,compensation, short-term, cash-based awards were granted under the Plan to substantially all eligible employees in 20182019 and 2017.  For 2018, there were two2018.  The short-term, cash-based awards, consisting of a long-term award andwhich are generally a short-term award.  All cash-based awardscomponent of the Plan, are performance-based awards consisting of predeterminedone or more business criteria or individual performance criteria applied againstand a targeted level or levels of performance with respect to each of such criteria.  In addition, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (terms as defined in the applicable performance period.  Expenseawards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each awardcash-based award.  During 2018, long-term, cash awards were granted to certain employees subject to pre-defined performance criteria.  Expense is recognized over the service period once the applicablebusiness criteria, individual performance criteria and financial condition is expected to be met, andare met.

For the 2019 cash-based awards, a portion of the business criteria and individual performance criteria can be reasonably estimated forwere 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 applicableJanuary 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.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.

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

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

Three Months Ended

 

March 31,

 

 

Three Months Ended March 31,

 

2019

 

 

2018

 

 

2020

  

2019

 

Share-based compensation included in:

 

 

 

 

 

 

 

        

General and administrative expenses

$

(78

)

 

$

1,219

 

 $1,048  $(78)

Cash-based incentive compensation included in:

 

 

 

 

 

 

 

        

Lease operating expense (1)

 

(123

)

 

 

860

 

  849   (123)

General and administrative expenses (1)

 

2,095

 

 

 

2,672

 

  3,631   2,095 

Total charged to operating income

$

1,894

 

 

$

4,751

 

 $5,528  $1,894 

 

(1)

(1)

Includes adjustments of accruals to actual payments.

17

Table of accruals to actual payments.Contents

17


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

9.

Income Taxes 

 

8.  Tax Expense and Tax Rate. Income Taxes  

Our income tax expense for the three months ended March 31, 2020 and 2019 was $6.5 million and 2018 was $0.2 million, and $0.1 million, respectively.  OurFor the three months ended March 31, 2020, our effective tax rate was not meaningfulprimarily differed from the statutory Federal tax rate for adjustments recorded related to the periods presented as we continueenactment of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) on March 27, 2020.  The CARES Act modified certain income tax statutes, including changes related to record a full valuation allowance on net deferred tax assets.  

Duringthe business interest expense limitation under Code Section 163(j).  For the three months ended March 31, 2019, and 2018, we did not receive anyimmaterial deferred income tax refunds or make any incomeexpense was recorded due to dollar-for-dollar offsets by our valuation allowance.  Our effective tax payments of significance.

As ofrate was 9.0% for the three months ended March 31, 20192020 and Decemberwas not meaningful for the three months ended March 31, 2018, our valuation allowance was $127.8 million and $117.8 million, respectively, related to net federal and state deferred tax assets.  Net deferred2019.  

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

As of March 31, 20192020 and December 31, 2018,2019, our valuation allowance was $47.8 million and $54.4 million, respectively, and relates primarily to state net operating losses and the disallowed interest limitation carryover. 

Income Taxes Receivable.  As of March 31, 2020 and December 31, 2019, we had current income taxes receivable of $54.1$1.9 million, which relates primarily relates to oura net operating loss  (“NOL”) carryback claimsclaim for the years 2012, 2013 and 20142017 that werewas carried back to prior years. These carryback

During the three months ended March 31, 2020 and 2019, we did not receive any income tax claims were made pursuant to IRC Section 172(f) (related to rules regarding “specified liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  The refund claims require a review by the Congressional Joint Committee on Taxation which we expect to receive in 2019.or make any income tax payments of significance.

The tax years 20132016 through 20182019 remain open to examination by the tax jurisdictions to which we are subject.

9.  

10.

Earnings Per Share

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

Three Months Ended

 

 

Three Months Ended March 31,

 

March 31,

 

 

2020

  

2019

 

2019

 

 

2018

 

Net (loss) income

$

(47,761

)

 

$

27,640

 

Net income (loss)

 $65,980  $(47,761)

Less portion allocated to nonvested shares

 

 

 

 

1,145

 

  791    

Net (loss) income allocated to common shares

$

(47,761

)

 

$

26,495

 

Net income (loss) allocated to common shares

 $65,189  $(47,761)

Weighted average common shares outstanding

 

140,462

 

 

 

138,845

 

  141,546   140,462 

 

 

 

 

 

 

 

        

Basic and diluted (loss) earnings per common share

$

(0.34

)

 

$

0.19

 

Basic and diluted earnings (loss) per common share

 $0.46  $(0.34)

 

 

 

 

 

 

 

        

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

 

3,342

 

 

 

 

     3,342 

18

 

18


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

11.

Contingencies

 

10.  Contingencies  

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

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

Appeal with the Office of Natural Resources Revenue (“ONRR”).  In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance;disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”)IBLA under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the IBLA decision.decision, of which the cash collateral held by the surety was subsequently returned during the first quarter of 2020.  On December 4, 2018, the IBLA denied our motion for reconsideration.  On February 4, 2019, we filed our first amended complaint.  

Royalties-In-Kind (“RIK”).  Under a program ofcomplaint, and the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessorgovernment has filed its Answer in the Administrative Record.  On July 9, 2019, we filed an Objection to the ONRR), royalties must be paid “in-kind” rather thanAdministrative Record and Motion to Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the record.  Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log.  In an Order dated December 18, 2019, the court ordered the government to produce certain contracts subject to a protective order and to produce the remaining documents in value from federal leases in the program.  The MMS addeddispute to the RIK program our lease atcourt for in camera review.  Following in camera review, the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed.  The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to become fixed for accounting purposes.  The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed.  We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor.  We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ruling on May 29, 2018.  We filed an appeal on July 24, 2018.  Partgovernment’s assertion of the ruling was in favor of our position and part was in favor of MMS’ position.  Based solely on the District Court’s ruling, we recorded a liability reserve of $2.2 million and $2.1 million as of March 31, 2019 and December 31, 2018, respectively.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appealsprivilege, and the government filed a cross-appeal.  Briefing and oral arguments, if held,parties are expected toproceeding with drafting Cross-Motions for Summary Judgment, which will be completedthe basis for the court’s ruling.  We anticipate that briefing will be complete in 2019.        

19


W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
the Fall of 2020.

 

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.  ForWhile the amounts paid for the three months ended March 31, 2020 and 2019 and 2018,were immaterial, we paid $0.1 million and $0.1 million, respectively, of additional royalties and expect to pay more in the future.  We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment.  During the three months ended March 31, 20192020 and 2018,2019, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”("BSEE") related to Incidents of Noncompliance (“INCs”) at various offshore locations.  We currently have nine open civil penalties issued by the BSEE from INCs, which have not been settled as of the filing date of this Form 10-Q.  The INCs underlying these open civil penalties cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations on various dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.7 million.  As of March 31, 20192020 and December 31, 2018,2019, we have accrued approximately $3.4$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.

 

19

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

12.

Subsequent Events

COVID-19 Impacts on Economic Environment.On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of COVID-19 and the risks to the international community as the virus spread globally beyond its point of origin.  In March 2020, the WHO classified the COVID-19 as a pandemic based on the rapid increase in exposure globally.

The COVID-19 pandemic has significantly impacted the global crude oil supply-demand balance causing a substantial decrease in crude oil prices and increasing the volatility of the market.  Domestic natural gas prices have remained relatively stable and have experienced less volatility.  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 ultimate effect on the prices of crude oil and natural gas cannot be determined and we could be adversely affected in future periods.

We are actively monitoring the impact on our results of operations, financial position, and liquidity for the remainder of 2020.  In response to the market changes, we have reduced our capital expenditure budget for the remainder of 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

Purchase of Senior Second Lien Notes. During the second quarter of 2020, approximately $45.1 million of  Senior Second Lien Notes were purchased in the open market for approximately $15.4 million.

Paycheck Protection Program (PPP) On April 15, 2020, the Company received $8.4 million under the U.S. Small Business Administration (“SBA”) PPP.  The Company expects that it will not be required to repay any of the funds received; however, we can give no assurances on the outcome of the SBA’s decision on the matter.  Should the Company be required to repay all or a portion of the funds received under the PPP (the PPP “Loan”), the Loan would mature on April 10, 2025 and accrue interest at 1%.

Spring 2020 Borrowing Base Redetermination.  On June 17, 2020,the lenders under the Credit Agreement completed their semi-annual borrowing base redetermination 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:

The borrowing base under the Credit Agreement was reduced from $250.0 million to $215.0 million.

Increase the interest rate margin by 25 basis points.

Amend 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% of total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement to 90%.

 

 


20

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, 20182019 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.  We have grown through acquisitions, exploration and development and hold working interests in 48 offshore fields in federal and state waters (47 producing and one field capable of producing).  We currently have under lease approximately 720,000815,000 gross acres (390,000(550,000 net acres) spanning across the Outer Continental Shelf (“OCS”)OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 515,000595,000 gross acres on the conventional shelf and approximately 205,000220,000 gross acres in the deepwater (water depths in excess of 500 feet).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 interestsinterest in Monza, as described in more detail in Financial Statements–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 driven prices down significantly.  These events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing.  These conditions may continue to exist in future periods, 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.

21

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 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 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.  Additionally, primarily as a result of substantially lower oil prices, the borrowing base under the Credit Agreement was reduced from $250.0 million to $215.0 million.

We have shut-in production in selected oil-weighted properties operated by the Company and have received notice of production shut-ins at certain non-operated properties.  Production at our Ship Shoal 349 field (Mahogany) and our key natural gas fields including Mobile Bay were not affected.

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, the Company mandated a work-from-home policy on March 23, 2020 and assured that all employees had the ability to continue performing their work duties remotely.  W&T recently reopened its corporate office and has implemented actions to protect its employees working in its offices.  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.  The Company conducts daily temperature screenings at all offshore facilities and implemented procedures for distancing and hygiene at its field locations. 

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, cashcash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the three months ended March 31, 20192020 were comprised of 49.2%37.5% crude oil and condensate, 10.3%10.2% NGLs and 40.5%52.3% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past.  For the three months ended March 31, 2019,2020, revenues from the sale of crude oil and NGLs made up 80.2%73.4% of our total revenues compared to 79.7%80.2% for the three months ended March 31, 2018.2019.  For the three months ended March 31, 2019,2020, our combined total production expressed in equivalent volumes was 9.8% lower62.4% higher than for the three months ended March 31, 2018, with natural gas having2019, primarily due to the largest decline.acquisition of the Mobile Bay properties described below.  For the three months ended March 31, 2019,2020, our total revenues were 13.5% lower6.9% higher than the three months ended March 31, 2018 primarily2019 due to lower productionthe higher volumes and partially offset by lower realized prices for crude oil, NGLs and NGLs.natural gas.  See Results of Operations –Three Months Ended March 31, 20192020 Compared to the Three Months Ended March 31, 20182019 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”).  After taking into account customary closing adjustments and an effective date of January 1, 2019, cash consideration was $169.8 million, of which substantially all was paid by us at closing.  We also assumed the related asset retirement obligations (“ARO”) and certain other obligations associated with these assets.  The acquisition was funded from cash on hand and borrowings of $150.0 million under the Credit Agreement (defined below), which were previously undrawn.  As of December 31, 2019, the Mobile Bay Properties had approximately 76.6 MMBoe of net proved reserves, of which 99% were proved developed producing reserves consisting primarily of natural gas and NGLs with 20% of the proved net reserves from liquids on an MMBoe basis, based on SEC pricing methodology.  For the three months ended March 31, 2020, the average production of the Mobile Bay Properties was approximately 18,500 net Boe per day.  The properties include working interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing properties owned and operated by us.  With this purchase, we became the largest operator in the area. 


22

Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  During the three months ended March 31, 2019,2020, our average realized crude oil price was $58.66$46.33 per barrel.  This is a decrease from our average realized crude oil price of $62.52$58.66 per barrel, or 21.0%, for the three months ended March 31, 20182019.  Crude oil prices using West Texas Intermediate ("WTI") pricing decreased significantly in April with spot prices being negative at some times and a decrease from our average realized crude oil price of $65.62averaging $16.55 per barrel for the year 2018.  ForApril 2020.  Crude oil prices have partially recovered and averaged $28.56 per barrel for May 2020 and ending the month of March 2019, the average realized price for crude oil increased from the amounts realized in January 2019 and February 2019 to $64.23at levels above $35.00 per barrel, which was above the average realized crude oil price for the three months ended March 31, 2018.  barrel. 
Our average realized prices of NGLs and natural gas for the three months ended March 31, 20192020 were lower than the average realized prices for the three months ended March 31, 20182019 by 24.2%37.6% and 1.0%36.3%, respectively. 

Our average realized crude oil sales price of $46.33 per barrel differs from the WTI benchmark average crude price of $45.34 per barrel primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors.  Crude oil quality adjustments can vary significantly by field.  All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the three months ended March 31, 20192020 compared to the three months ended March 31, 2018 improved by2019 decreased approximately $3.00 to $4.00 per barrel and averaged $0.07, $3.73, and $3.30 per barrel, respectively, for these three types of crude oils.

oil for the three months ended March 31, 2020.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During inFor the three months ended March 31, 20192020 compared to the three months ended March 31, 2018,2019, average prices for domestic ethane increaseddecreased by 6%55% and average domestic propane prices decreased by 21%44% as measured using a price index for Mount Belvieu.  The average priceprices for other domestic NGLs components ranged from decreases of 15%decreased 19% to 18%29% for the three months ended March 31, 2019 year-over-year.2020 compared to the same period in 2019.  We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand. 

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as of the end of March 2019reported in their May 29, 2020 report was approximately the same level assignificantly lower than a year ago, levels for land baseddecreasing to 301 rigs (an increase of fourcompared to 984 rigs or less than 1%), and higher in the Gulf of Mexico (an increase of 11 rigs or 92%).a year ago.  The oil rig count as of March 2019decreased to 222 rigs compared to 800 rigs a year ago and March 2018 was 816the gas and 797, respectively.  The U.S. natural gas rig count as of March 2019 and March 2018 was 190 and 194, respectively.miscellaneous rigs decreased to 79 rigs from 184 a year ago.  In the Gulf of Mexico, the number of working rigs was 23 rigs (18 oil rigs and five natural gas rigs) as of March 2019 and 12 rigs (all oil) compared to 23 (20 oil rigs) asand three natural gas) a year ago.   

23

 

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

 

 

March 31,

 

 

2019

 

 

2018

 

 

Change

 

 

%

 

 

(In thousands, except percentages and per share data)

 

Financial:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

$

86,703

 

 

$

97,306

 

 

$

(10,603

)

 

 

(10.9

)%

NGLs

 

6,448

 

 

 

9,660

 

 

 

(3,212

)

 

 

(33.3

)%

Natural gas

 

21,838

 

 

 

25,867

 

 

 

(4,029

)

 

 

(15.6

)%

Other

 

1,091

 

 

 

1,380

 

 

 

(289

)

 

 

(20.9

)%

Total revenues

 

116,080

 

 

 

134,213

 

 

 

(18,133

)

 

 

(13.5

)%

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

43,456

 

 

 

36,843

 

 

 

6,613

 

 

 

17.9

%

Production taxes

 

416

 

 

 

455

 

 

 

(39

)

 

 

(8.6

)%

Gathering and transportation

 

6,423

 

 

 

5,057

 

 

 

1,366

 

 

 

27.0

%

Depreciation, depletion, amortization and accretion

 

33,766

 

 

 

38,081

 

 

 

(4,315

)

 

 

(11.3

)%

General and administrative expenses

 

14,109

 

 

 

15,038

 

 

 

(929

)

 

 

(6.2

)%

Derivative loss

 

48,886

 

 

 

 

 

 

48,886

 

 

NM

 

Total costs and expenses

 

147,056

 

 

 

95,474

 

 

 

51,582

 

 

 

54.0

%

Operating (loss) income

 

(30,976

)

 

 

38,739

 

 

 

(69,715

)

 

NM

 

Interest expense, net

 

16,282

 

 

 

10,962

 

 

 

5,320

 

 

 

48.5

%

Other expense, net

 

331

 

 

 

28

 

 

 

303

 

 

NM

 

(Loss) income before income tax expense

 

(47,589

)

 

 

27,749

 

 

 

(75,338

)

 

NM

 

Income tax expense

 

172

 

 

 

109

 

 

 

63

 

 

 

57.8

%

Net (loss) income

$

(47,761

)

 

$

27,640

 

 

$

(75,401

)

 

NM

 

 

Basic and diluted (loss) earnings per common share

$

(0.34

)

 

$

0.19

 

 

$

(0.53

)

 

NM

 

  

Three Months Ended March 31,

 
  

2020

  

2019

  

Change

   %
  

(In thousands, except percentages and per share data)

 

Financial:

                

Revenues:

                

Oil

 $84,650  $86,703  $(2,053)  (2.4)%

NGLs

  6,452   6,448   4   0.1%

Natural gas

  29,300   21,838   7,462   34.2%

Other

  3,726   1,091   2,635   241.5%

Total revenues

  124,128   116,080   8,048   6.9%

Operating costs and expenses:

                

Lease operating expenses

  54,775   43,456   11,319   26.0%

Production taxes

  916   416   500   120.2%

Gathering and transportation

  5,449   6,423   (974)  (15.2)%

Depreciation, depletion, amortization and accretion

  39,126   33,766   5,360   15.9%

General and administrative expenses

  13,963   14,109   (146)  (1.0)%

Derivative (gain) loss

  (61,912)  48,886   (110,798)  NM 

Total costs and expenses

  52,317   147,056   (94,739)  (64.4)%
Operating income (loss)  71,811   (30,976)  102,787   NM 

Interest expense, net

  17,110   16,282   828   5.1%
Gain on purchase of debt  (18,501)     (18,501)  NM 

Other expense, net

  723   331   392   118.4%

Income (loss) before income tax expense

  72,479   (47,589)  120,068   NM 

Income tax expense

  6,499   172   6,327   NM 
Net income (loss) $65,980  $(47,761) $113,741   NM 
Basic and diluted earnings (loss) per common share $0.46  $(0.34) $0.80   NM 

 

NM – not meaningful

 

 

Three Months Ended

 

 

March 31,

 

 

2019

 

 

2018

 

 

Change

 

 

% (2)

 

Operating: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,478

 

 

 

1,557

 

 

 

(79

)

 

 

(5.1

)%

NGLs (MBbls)

 

309

 

 

 

351

 

 

 

(42

)

 

 

(12.0

)%

Natural gas (MMcf)

 

7,288

 

 

 

8,523

 

 

 

(1,235

)

 

 

(14.5

)%

Total oil equivalent (MBoe)

 

3,001

 

 

 

3,328

 

 

 

(327

)

 

 

(9.8

)%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily equivalent sales (Boe/day)

 

33,349

 

 

 

36,976

 

 

 

(3,627

)

 

 

(9.8

)%

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

58.66

 

 

$

62.52

 

 

$

(3.86

)

 

 

(6.2

)%

NGLs ($/Bbl)

 

20.88

 

 

 

27.54

 

 

 

(6.66

)

 

 

(24.2

)%

Natural gas ($/Mcf)

 

3.00

 

 

 

3.03

 

 

 

(0.03

)

 

 

(1.0

)%

Oil equivalent ($/Boe)

 

38.31

 

 

 

39.92

 

 

 

(1.61

)

 

 

(4.0

)%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average per Boe ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

$

14.48

 

 

$

11.07

 

 

$

3.41

 

 

 

30.8

%

Gathering and transportation

 

2.14

 

 

 

1.52

 

 

 

0.62

 

 

 

40.8

%

Production costs

 

16.62

 

 

 

12.59

 

 

 

4.03

 

 

 

32.0

%

Production taxes

 

0.14

 

 

 

0.14

 

 

 

 

 

 

 

DD&A

 

11.25

 

 

 

11.44

 

 

 

(0.19

)

 

 

(1.7

)%

G&A  expenses

 

4.70

 

 

 

4.52

 

 

 

0.18

 

 

 

4.0

%

 

$

32.71

 

 

$

28.69

 

 

$

4.02

 

 

 

14.0

%

 

  

Three Months Ended March 31,

 
  

2020

  

2019

  

Change

   %

Operating: (1)

                

Net sales:

                

Oil (MBbls)

  1,827   1,478   349   23.6%

NGLs (MBbls)

  495   309   186   60.2%

Natural gas (MMcf)

  15,307   7,288   8,019   110.0%

Total oil equivalent (MBoe)

  4,873   3,001   1,872   62.4%
                 

Average daily equivalent sales (Boe/day)

  53,553   33,349   20,204   60.6%

Average realized sales prices:

                

Oil ($/Bbl)

 $46.33  $58.66  $(12.33)  (21.0)%

NGLs ($/Bbl)

  13.03   20.88   (7.85)  (37.6)%

Natural gas ($/Mcf)

  1.91   3.00   (1.09)  (36.3)%

Oil equivalent ($/Boe)

  24.71   38.31   (13.60)  (35.5)%
                 

Average per Boe ($/Boe):

                
Lease operating expenses $11.24  $14.48  $(3.24)  (22.4)%
Gathering and transportation  1.12   2.14   (1.02)  (47.7)%
Production costs  12.36   16.62   (4.26)  (25.6)%
Production taxes  0.19   0.14   0.05   35.7%
DD&A  8.03   11.25   (3.22)  (28.6)%
G&A expenses  2.87   4.70   (1.83)  (38.9)%
  $23.45  $32.71  $(9.26)  (28.3)%

(1)

The conversion to Boebarrels 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.  

rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

 

(2)

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

Volume measurements not previously defined:

MBbls — thousand barrels for crude oil, condensate or NGLs

 

Mcf — thousand cubic feet

MBoe — thousand barrels of oil equivalent

 

MMcf — million cubic feet

Three Months Ended March 31, 20192020 Compared to the Three Months Ended March 31, 20182019

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 March 31, 2020 may not be indicative of future periods.  See “Liquidity and Capital Resources – Liquidity Overview” below for additional information.

Revenues.  Total revenues decreased $18.1increased $8.0 million, or 13.5%6.9%, to $116.1$124.1 million for the three months ended March 31, 20192020 as compared to the three months ended March 31, 2018.2019.  Oil revenues decreased $10.6$2.1 million, or 10.9%2.4%, NGLs revenues decreased $3.2 million, or 33.3%,were basically flat, natural gas revenues decreased $4.0increased $7.5 million, or 15.6%34.2%, and other revenues decreased $0.3 million.increased $2.6 million due to prior period royalty adjustments received during the three months ended March 31, 2020.  The decrease in oil revenues was attributable to a 6.2%21.0% decrease in the average realized sales price to $46.33 per barrel for the three months ended March 31, 2019 from $58.66 per barrel for the three months ended March 31, 2019, from $62.52partially offset by an increase in sales volumes of 23.6%.  NGLs sales volumes increased by 60.2% and were offset by a 37.6% decrease in the average realized sales price to $13.03 per barrel for the three months ended March 31, 2018 and sales volumes decreased 5.1%.  The decrease in NGLs revenues was attributable to a 24.2% decrease in the average realized sales price to2020 from $20.88 per barrel for the three months ended March 31, 2019 from $27.542019.  The increase in natural gas revenues was attributable to sales volumes that more than doubled, increasing 110.0%, and partially offset by a 36.3% decrease in the average realized price to $1.91 per barrelMcf for the three months ended March 31, 2018 and sales volumes decreased 12.0%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 1.2 billion cubic feet (“Bcf”), or 14.5% and a 1.0% decrease in the average realized price to2020 from $3.00 per Mcf for the three months ended March 31, 2019 from $3.03 per Mcf for the three months ended March 31, 2018.2019.  Overall, production volumes decreased 9.8%increased 60.6% on a BoeBoe/day basis.  The largest production increases for the three months ended March 31, 20192020 compared to the three months ended March 31, 2018 were from2019 was related to our interestacquisition of the interests in the Heidelberg field,Mobile Bay Properties in August 2019, which was acquired in April 2018, andproduced an average of 18,500 Boe per day during the three months ended March 31, 2020, increases in production at our Ship Shoal 349Mahogany field (Mahogany).  Offsettingand the acquisition of Garden Banks 783 field (Magnolia) assets in December 2019.  These increases were partially offset by production decreases primarily from increases in downtime, with the largest amounts related to planned maintenance, well servicing and rig movements at certain platforms and pipelines.natural production declines.  Our estimate of deferred production for the three months ended March 31, 20192020 was approximately 7,2003,600 Boe per day as compared to 4,2007,200 Boe per day for the three months ended March 31, 2018, which comprises 83% of the production volume variance between the two periods.  In April 2019, a majority of the pipeline and facility maintenance was completed and improved well performance and continued ramp up of new wells enabled the mid-April production rate to increase to over 37,000 Boe/day.  2019.    

Revenues from oil and NGLs as a percent of our total revenues were 73.4% for the three months ended March 31, 2020 compared to 80.2% for the three months ended March 31, 2019 compared to 79.7% for the three months ended March 31, 2018.2019.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 28.1% for the three months ended March 31, 2020 compared to 35.6% for the three months ended March 31, 2019 compared to 44.0% for the three months ended March 31, 2018.2019.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $6.6$11.3 million, or 17.9%26.0%, to $43.5$54.8 million in the three months ended March 31, 20192020 compared to the three months ended March 31, 2018.2019.  On a component basis, base lease operating expenses increased $1.4$15.9 million, workover expenses increased $2.3decreased $3.4 million, and facilities maintenance expense increased $2.9decreased $1.2 million.  Base lease operating expenses increased primarily due to the additionacquisition of the Heidelberg field interest, acquiredMobile Bay Properties in April 2018, andAugust 2019, which had base lease operating expenses of $1.7$11.3 million for the three months ended March 31, 2020.  In addition, the acquisition of the Magnolia field in December 2019 increased base lease operating expenses by $3.2 million.  The decreases in workover expense and facility maintenance were due to fewer projects undertaken, with the primary decrease due to a workover at the Mississippi Canyon 800 field occurring during the three months ended March 31, 2019. 

Production taxes.  Production taxes increased $0.5 million to $0.9 million in the three months ended March 31, 2020 compared to the three months ended March 31, 2019 due to the acquisition of the Mobile Bay Properties, which has operations in state waters. 

Gathering and transportation.  Gathering and transportation expenses decreased $1.0 million to $5.4 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to lower transportation rates at certain fields and lower volumes at the Green Canyon 859 (Heidelberg) field. 

Depreciation, depletion, amortization and accretion (“DD&A”).  DD&A, which includes accretion for ARO, decreased to $8.03 per Boe for the three months ended March 31, 2020 from $11.25 per Boe for the three months ended March 31, 2019.  On a nominal basis, DD&A increased to $39.1 million (or 15.9%) for the three months ended March 31, 2020 from $33.8 million for the three months ended March 31, 2019.  DD&A on a nominal basis increased largely due to higher production, partially offset by 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 and revisions to proved reserve volumes.   

General and administrative expenses (“G&A”).  G&A was $14.0 million for the three months ended March 31, 2020, decreasing 1.0 % from $14.1 million for the three months ended March 31, 2019.  The increase in workover expensedecrease was primarily due to 2019 projects at our Mahogany field.  The facility maintenance expense increase was primarily attributableincreased fees for overhead charged to work performed in 2019 at our Mahogany field combined with multiple other fields.  

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

Depreciation, depletion, amortization and accretion (“DD&A”). DDincentive compensation expenses.  G&A which includes accretion for ARO, decreased to $11.25on a per Boe basis was $2.87 per Boe for the three months ended March 31, 2019 from $11.44 per Boe for the three months ended March 31, 2018.  On a nominal basis, DD&A decreased2020 compared to $33.8 million (or 11.3%) for the three months ended March 31, 2019 from $38.1 million for the three months ended March 31, 2018.  DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are production, capital expenditures, sales of assets and changes in proved reserves volumes.    


General and administrative expenses (“G&A”).  G&A was $14.1 million for the three months ended March 31, 2019, decreasing 6.2% from $15.0 million for the three months ended March 31, 2018.  The decrease was primarily due to a decrease in incentive compensation.  G&A on a per Boe basis was $4.70 per Boe for the three months ended March 31, 2019 compared to $4.52 per Boe for the2019.

Derivative (gain) loss.  The three months ended March 31, 2018.

Derivative loss. 2020 reflects a $61.9 million derivative gain primarily due to decreased crude oil prices during March 2020 as compared to oil prices during December 2019, which increased the estimated fair value of closed and open crude oil contracts between the two measurement dates.  The three months ended March 31, 2019 reflects a $48.9 million derivative loss primarily due to increased crude oil prices during March 2019 as compared to oil prices during December 2018, which decreased the estimated fair value of open crude oil contracts between the two measurement dates.  For the three months ended March 31, 2018, we did not have any gains or losses from derivative contracts.  

Interest expense, net.  Interest expense, net, was $16.3$17.1 million and $11.0$16.3 million for the three months ended March 31, 2020 and 2019, and 2018, respectively.  During 2018, a portionThe increase is due to higher borrowings under the Credit Agreement related to the acquisition of the Mobile Bay Properties. 

Gain on purchase of debt: A gain of $18.5 million was recorded related to the purchase of $27.5 million of principal of our interest was recorded as offsets to carrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60, Troubled Debt Restructuring (“ASC 470-60”), which lowered reported interest expense foroutstanding Senior Second Lien Notes during the three months ended March 31, 2018 and affects the comparability.  2020.

Income tax expense. Our income tax expense for the three months ended March 31, 2020 and 2019 was $6.5 million and 2018 was $0.2 million, and $0.1 million, respectively.  Immaterial deferredFor the three months ended March 31, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of   the CARES Act on March 27, 2020.  The CARES Act modified certain income tax statutes including changes related to the business interest expense was recorded forlimitation under Internal Revenue Code Section 163(j).  For the three months ended March 31, 2019, immaterial deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance.  Our effective tax rate using book pre-tax incomewas 9.0% for the three months ended March 31, 2020 and was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.three months ended March 31, 2019.  As of March 31, 2019,2020, our valuation allowance was $127.8$47.8 million.  We continually evaluate the need to maintain a valuation allowance on our deferred tax assets.  Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs.See Financial Statements – Note 89 –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 property acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, make related interest paymentsoperate 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 worldly events impact crude oil prices, and to a lesser degree, natural gas prices, we are actively monitoring the impacts on our results of operations, financial position, and liquidity.  As of March 31, 2020, we had $47.6 million cash on hand, availability of $170 million under the Credit Agreement (and subsequently reduced by $35 million to $135 million due to redetermination of the borrowing base as discussed in the Credit Agreement section below) and no maturities of long-term debt until 2022.  Despite this appearance of liquidity, the impact of unprecedented decline in oil prices during March and April of 2020 were severe and so dramatic as to threaten the entire oil and gas industry including the Company.  Oil prices began recovering some in May 2020 and through mid-June 2020.  In reaction to these events, we moved quickly to preserve resources and protect the health of our employees.  Furthermore, we have taken certain actions to address the current economic environment as follows:

We have reduced our capital expenditure budget for the remainder o.  f 2020.  Excluding acquisitions and plugging and abandonment expenditures, we are estimating capital expenditures to be approximately $15 million to $25 million for 2020.   ARO (plugging and abandonment) spending is estimated to be between of $2 million to $4 million..

Since December 31, 2019, we have reduced the amount outstanding of our Senior Second Lien Notes by $72.5 million to $552.5 million as of June 22, 2020 through purchases in the open market for $23.9 million, resulting in annualized interest savings of $7.1 million.

On October 18, 2018,June 17, 2020, we entered into the Third Amendment and Waiver to the Credit Agreement, which, maturesamong other things, waived the Leverage Ratio (as defined in the Credit Agreement) and replaced it with a first lien leverage covenant of 2.00 to 1.00 through year-end 2021.

While we currently expect our cash on Octoberhand, 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 three months ended March 31, 2020 and 2019 was $84.3 million and $84.8 million, respectively.  Production volumes increased by 60.6% measured on a Boe per day basis, which caused revenues to increase by $48.4 million.  Our combined average realized sales price per Boe decreased by 35.5% for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, which caused total revenues to decrease $43.0 million.  

Other items affecting operating cash flows were lower receivable balances, which increased operating cash flows by $29.1 million for the three months ended March 31, 2020 compared to an increase of $3.5 million for the three months ended March 31, 2019;  lower cash advance balances from joint venture partners, which decreased $31.6 million between the two periods; lower cash derivative receipts, net, which decreased $7.5 million between the two periods; and a return of collateral related to a bond of $6.9 million which occurred during the three months ended March 31, 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 partially offset by sales of such assets.  Net cash used in investing activities for the three months ended March 31, 2020 and 2019 was $35.6 million and $31.6 million, respectively.  Our capital expenditures on an occurrence basis for the three months ended March 31, 2020 were split approximately 25% for investments in the deep waters of the Gulf of Mexico and approximately 75% for investments on the conventional shelf of the Gulf of Mexico.  During the three months ended March 31, 2020, the purchase of the remaining 25% interest in the Magnolia field was consummated for approximately $2.0 million.

Net cash used by financing activities for the three months ended March 31, 2020 and 2019 was $33.5 million and $0.4 million, respectively.  The net cash used for the three months ended March 31, 2020 included repayment borrowings of $25.0 million under the Credit Agreement and $8.5 million to purchase $27.5 million principal of Senior Second Lien Notes on the open market.  Net cash used by financing activities for the three months ended March 31, 2019 was $0.4 million related to debt issuance costs.

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 three months ended March 31, 2020, we entered into derivative contracts for natural gas for a portion of our future production.  During the second quarter of 2020, we added the following derivative contracts: (i) Henry Hub cashless collars on 10,000 Mcf per day of production for the period of May 2020 through December 2020 with a floor of $1.75 per Mcf and a ceiling of $2.58 per Mcf; (ii)  Henry Hub cashless collars on 20,000 Mcf per day of production for the period of January 2021 through December 2021 with an average floor of $2.17 per Mcf and an average ceiling of $3.00 per Mcf; and (iii) NYMEX crude oil swaps of 1,000 barrels per day for January 2021 through December 2021 at a weighted average price of $41.00 per barrel.  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 March 31, 2020 and December 31, 2019 were $364.1 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 expect to collect the income tax receivable of $1.9 million during 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 first quarter 2020, we significantly reduced our 2020 capital expenditure budget in response to the unprecedented decline in oil prices.  The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

  

Three Months Ended March 31,

 
  

2020

  

2019

 

Exploration (1)

 $1,206  $4,251 

Development (1)

  7,180   17,269 

Magnolia acquisition

  2,002    

Seismic and other

  1,156   9,113 

Investments in oil and gas property/equipment

 $11,544  $30,633 

(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):

  

Three Months Ended March 31,

 
  

2020

  

2019

 

Conventional shelf

 $6,322  $6,079 

Deepwater

  2,064   15,441 

Exploration and development capital expenditures

 $8,386  $21,520 

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

Our capital expenditures for the three months ended March 31, 2020 were financed by cash flow from operations and cash on hand.

 Drilling Activity

During the three months ended March 31, 2020, we drilled the East Cameron 349 B-1 well (Cota) to target depth.  We expect initial production to be 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 three months ended March 31, 2020. 

 Offshore Lease Awards 

During the three months ended March 31, 2020, we were the apparent high bidder on two blocks in the Gulf of Mexico Lease Sale 254 held by the BOEM on March 18, 2022.2020.  We are the apparent high bidder on one deepwater block, Garden Bank 782, and one shallow water block, Eugene Island Area South block 345.  The two blocks cover a total of approximately 10,760 acres and we will pay $0.7 million combined for a 100% working interest if awarded.

Debt

Credit Agreement.  As of March 31, 2019, we had $21.0 million2020, borrowings outstanding under the Credit Agreement and $8.1were $80.0 million ofand letters of credit issued under the Credit Agreement.Agreement were $5.8 million.  During the three months ended March 31, 2019, we did not have any additional borrowings or repayments under the Credit Agreement.2020, a repayment of $25.0 million was made.  Availability under our Credit Agreement as of March 31, 20192020 was $220.9$164.2 million.  As of June 17, 2020, following the borrowing base retermination and the recent Senior Second Lien Note purchases, availability under the Credit Agreement was $128.9 million and we had $80.0 million of borrowings outstanding under the Credit Agreement.  The Credit Agreement matures on October 18, 2022.

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, which was initially set at $250.0 million and was reduced to $215.0 million in June 2020.  The next redetermination will occur in the fall of 2020.  Generally, we must be in compliance with the next redetermination to be completed by May 15, 2019.  Any redetermination by our lenders to change our borrowing base will resultcovenants in a similar change in the availability under our Credit Agreement.  TheAgreement in order to access borrowings under the Credit Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.Agreement.

We currently have six lenders under our Credit Agreement, with commitments ranging from $25.0 million to $62.5 million for the current borrowing base.Agreement.  While we havedo not experienced, nor do we 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 and –Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.


Senior Second Lien Notes.  As of March 31, 2019,2020, we had outstanding $625.0$597.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023.  TheDuring the three months ended March 31, 2020, we purchased $27.5 million in principal of our outstanding Senior Second Lien Notes are secured by a second-priority lienin the open market for $8.5 million.  Subsequent to March 31, 2020, we purchased an additional $45.1 million in outstanding notes on all of our assets that are secured under the Credit Agreement.open market for $15.3 million. See Financial Statements – Note 2 –Long-Term– Long-Term Debtand–Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.

Debt Covenants.  The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes.  We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of March 31, 2019.2020.  See Financial Statements – Note 2 – Long-Term Debt and–Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.

BOEM

Uncertainties

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

Surety Bond Collateral.  Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.  No additional demands were made to us by sureties during 20192020 as of the filing date of this Form 10-Q.10-Q and we currently do not have surety bond collateral outstanding.

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

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

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

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

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


Derivative Financial Instruments.  From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas.  During 2018, we entered into derivative contracts for crude oil and natural gas for a portion of our future production.  See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  

 

Insurance Coverage

Insurance Coverage.  We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.  With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $30.0 million. Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.  The operational and named windstorm coverages are effective for one year beginning June 1, 2018.2020.  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, 20192020 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

 

Although we were able to renew our general and excess liability policies effective on May 1, 2019,2020, and we expect to renew our Energy Package effective on June 1, 2019,2020, 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.

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

Contractual Obligations

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2019

 

 

2018

 

Exploration (1)

 

$

4,251

 

 

$

2,718

 

Development (1)

 

 

17,269

 

 

 

30,907

 

Reimbursement from Monza for 2017 expenditures

 

 

 

 

 

(14,075

)

Seismic and other

 

 

9,113

 

 

 

1,567

 

Investments in oil and gas property/equipment

 

$

30,633

 

 

$

21,117

 

(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):

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2019

 

 

2018

 

Conventional shelf

 

$

6,079

 

 

$

24,284

 

Deepwater

 

 

15,441

 

 

 

9,341

 

Exploration and development capital expenditures

 

$

21,520

 

 

$

33,625

 

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

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

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

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

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

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

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

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


Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt,andNote 5 – Asset Retirement Obligations andNote 12, Subsequent Events underPart I, Item 1 of this Form 10-Q.  As of March 31, 2019,2020, there were no drilling rig commitments, excluding ARO drilling rig commitments, were approximately $9.2 million, which was approximately the same as the amount as of December 31, 2018.commitments.  Except for scheduled utilization, other contractual obligations as of March 31, 20192020 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018.2019.

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, 2018.2019. See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1of this Form 10-Q for additional information.

 

Recent Accounting Pronouncements

See Financial Statements - Note 1 - Basis of Presentation underPart 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 three months ended March 31, 20192020 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2018.  As such,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, 2018.  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 couldsustain current prices would have significant impacts on our business in the future.  During 2018,2020, we entered into derivative crude oilnatural 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 March 31, 2019,2020, we had $21.0$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. ControlsControls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of March 31, 2019,2020, 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 March 31, 2019,2020, 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 1011 –Contingencies, under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.

Item 1A. Risk Factors

Investors should carefully consider

The 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 risk factors included under Part I, Item 1A, Risk Factors,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 ended December 31, 2018,2019.

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 quarter 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.  We will likely incur greater 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 5. Other Information

On June 17, 2020,the lenders under the Credit Agreement completed their semi-annual borrowing base redetermination and entered into the Third Amendment and Waiver 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 potential effects of crude oil prices are discussedThird Amendment includes the following changes, among other things, to the Credit Agreement:

The borrowing base under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the yearCredit Agreement was reduced from $250.0 million to $215.0 million.

Increase the interest rate margin by 25 basis points.

Amend the financial covenants as follows:  

From the period ended June 30, 2020 through the period ended December 31, 2018 and also discussed in2021, the Part I, Item 2, Management’s Discussion and AnalysisCompany 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 Financial Condition and Resultsfirst lien debt outstanding under the Credit Agreement on the last day of Operations in the Overview section of this Form 10-Q.

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

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

 

 

 

 

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 3.23.1 of the Company’s Registration StatementCurrent Report on Form S-1,8-K, filed May 3, 2004March 22, 2019 (File No. 333-115103)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))

3.5

10.1*SecondThird Amendment and Waiver to Sixth Amended and Restated Bylaws ofCredit Agreement, dated June 17, 2020, by and among W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of, Toronto Dominion (Texas) LLC, as agent and the Company’s Current Report on Form 8-K, filed March 22, 2019 (File No. 001-32414))various agents and lenders party thereto.

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*

XBRL Instance Document.

101.SCH*

XBRL Schema Document.

101.CAL*

XBRL Calculation Linkbase Document.

101.DEF*

XBRL Definition Linkbase Document.

101.LAB*

XBRL Label Linkbase Document.

101.PRE*

XBRL Presentation Linkbase Document.

 

*

Filed or Furnishedfurnished 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 May 2, 2019.June 23, 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

 

 

 

35

37