UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2021

☐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)

5718 Westheimer Road, Suite 700, Houston, Texas		77057-5745
(Address of principal executive offices)		(Zip Code)

(713) 626-8525

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

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


Large accelerated filer ☐	Accelerated filer	☑
Non-accelerated filer ☐	Smaller reporting company	☐
	Emerging growth company	☐

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

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

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.00001	WTI	New York Stock Exchange

As of October 31, 2021 there were 142,367,272 shares outstanding of the registrant’s common stock, par value $0.00001.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I –FINANCIAL INFORMATION		1

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2021 and 2020	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended September 30, 2021 and 2020	3
	Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2021 and 2020	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	38

PART II – OTHER INFORMATION		39
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 5.	Other Information	39
Item 6.	Exhibits	40

SIGNATURE		41

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)


	September 30,		December 31,
	2021		2020
Assets
Current assets:
Cash and cash equivalents	$	257,584	$	43,726
Receivables:
Oil and natural gas sales		38,326		38,830
Joint interest, net		13,012		10,840
Income taxes		20		—
Total receivables		51,358		49,670
Prepaid expenses and other assets (Note 1)		73,642		13,832
Total current assets		382,584		107,228

Oil and natural gas properties and other, net (Note 1)		653,936		686,878

Restricted deposits for asset retirement obligations		29,873		29,675
Deferred income taxes		113,177		94,331
Other assets (Note 1)		63,776		22,470
Total assets	$	1,243,346	$	940,582
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	78,782	$	48,612
Undistributed oil and natural gas proceeds		30,759		19,167
Asset retirement obligations		27,545		17,188
Accrued liabilities (Note 1)		196,486		29,880
Current portion of long-term debt		46,201		—
Income tax payable		—		153
Total current liabilities		379,773		115,000
Long-term debt (Note 2)
Principal		709,481		632,460
Unamortized debt issuance costs		(13,310)		(7,174)
Long-term debt, net		696,171		625,286

Asset retirement obligations, less current portion		380,329		375,516
Other liabilities (Note 1)		83,814		32,938
Deferred income taxes		148		128
Commitments and contingencies (Note 11)		—		—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at September 30, 2021 and December 31, 2020		—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 145,236 issued and 142,367 outstanding at September 30, 2021; 145,174 issued and 142,305 outstanding at December 31, 2020		1		1
Additional paid-in capital		552,118		550,339
Retained deficit		(824,841)		(734,459)
Treasury stock, at cost; 2,869 shares at September 30, 2021 and December 31, 2020		(24,167)		(24,167)
Total shareholders’ deficit		(296,889)		(208,286)
Total liabilities and shareholders’ deficit	$	1,243,346	$	940,582

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues:
Oil	$	74,265	$	46,589	$	240,418	$	161,884
NGLs		12,205		4,464		30,397		12,833
Natural gas		45,137		19,213		113,816		69,877
Other		2,339		2,251		7,790		7,292
Total revenues		133,946		72,517		392,421		251,886
Operating costs and expenses:
Lease operating expenses		39,490		36,437		129,399		119,525
Production taxes		2,600		1,266		6,552		3,325
Gathering and transportation		3,993		3,560		13,135		12,310
Depreciation, depletion, amortization and accretion		26,291		25,127		83,879		93,736
General and administrative expenses		13,391		14,476		38,090		34,067
Derivative loss (gain)		73,137		11,161		179,156		(35,337)
Total costs and expenses		158,902		92,027		450,211		227,626
Operating (loss) income		(24,956)		(19,510)		(57,790)		24,260

Interest expense, net		18,910		14,135		50,474		46,061
Gain on debt transactions		—		—		—		(47,469)
Other expense, net		—		751		964		2,225
(Loss) income before income taxes		(43,866)		(34,396)		(109,228)		23,443
Income tax benefit		(5,902)		(21,057)		(18,846)		(23,294)
Net (loss) income	$	(37,964)	$	(13,339)	$	(90,382)	$	46,737
Basic and diluted (loss) earnings per common share	$	(0.27)	$	(0.09)	$	(0.64)	$	0.33

See Notes to Condensed Consolidated Financial Statements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)


Three Month Comparison
	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at June 30, 2021	142,367	$	1	$	551,260	$	(786,877)	2,869	$	(24,167)	$	(259,783)
Share-based compensation	—				858		—	—		—		858
Stock Issued	—		—		—		—	—		—		—
Net loss	—		—		—		(37,964)	—		—		(37,964)
Balances at September 30, 2021	142,367	$	1	$	552,118	$	(824,841)	2,869	$	(24,167)	$	(296,889)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at June 30, 2020	141,669	$	1	$	549,117	$	(712,173)	2,869	$	(24,167)	$	(187,222)
Share-based compensation	—		—		1,075		—	—		—		1,075
Stock Issued	109		—		—		—	—		—		—
Net loss	—		—		—		(13,339)	—		—		(13,339)
Balances at September 30, 2020	141,778	$	1	$	550,192	$	(725,512)	2,869	$	(24,167)	$	(199,486)


Nine Month Comparison
	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at December 31, 2020	142,305	$	1	$	550,339	$	(734,459)	2,869	$	(24,167)	$	(208,286)
Share-based compensation	—		—		1,779		—	—		—		1,779
Stock Issued	62		—		—		—	—		—		—
Net loss	—		—		—		(90,382)	—		—		(90,382)
Balances at September 30, 2021	142,367	$	1	$	552,118	$	(824,841)	2,869	$	(24,167)	$	(296,889)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at December 31, 2019	141,669	$	1	$	547,050	$	(772,249)	2,869	$	(24,167)	$	(249,365)
Share-based compensation	—		—		3,142		—	—		—		3,142
Stock Issued	109		—		—		—	—		—		—
Net income	—		—		—		46,737	—		—		46,737
Balances at September 30, 2020	141,778	$	1	$	550,192	$	(725,512)	2,869	$	(24,167)	$	(199,486)

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2021		2020
Operating activities:
Net (loss) income	$	(90,382)	$	46,737
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		83,879		93,736
Amortization of debt items and other items		4,095		5,251
Share-based compensation		1,779		3,142
Derivative loss (gain)		179,156		(35,337)
Derivative cash (payments) receipts, net		(39,554)		42,028
Derivative cash premium (payments)		(32,368)		—
Gain on debt transactions		—		(47,469)
Deferred income taxes		(18,826)		(23,407)
Changes in operating assets and liabilities:
Oil and natural gas receivables		504		35,959
Joint interest receivables		(2,172)		9,039
Prepaid expenses and other assets		(30,473)		7,951
Income tax		(153)		1,993
Asset retirement obligation settlements		(19,744)		(2,788)
Cash advances from JV partners		9,999		2,442
Accounts payable, accrued liabilities and other		65,551		(24,539)
Net cash provided by operating activities		111,291		114,738
Investing activities:
Investment in oil and natural gas properties and equipment		(16,025)		(12,954)
Changes in operating assets and liabilities associated with investing activities		3,617		(28,229)
Acquisition of property interests		—		(456)
Purchases of furniture, fixtures and other		2		(70)
Net cash used in investing activities		(12,406)		(41,709)
Financing activities:
Borrowings on credit facility		—		25,000
Repayments on credit facility		(80,000)		(50,000)
Purchase of Senior Second Lien Notes		—		(23,930)
Proceeds from Term Loan		215,000		—
Repayments on Term Loan		(11,778)		—
Debt issuance costs and other		(8,249)		—
Net cash provided by (used in) financing activities		114,973		(48,930)
Increase in cash and cash equivalents		213,858		24,099
Cash and cash equivalents, beginning of period		43,726		32,433
Cash and cash equivalents, end of period	$	257,584	$	56,532

See Notes to Condensed Consolidated Financial Statements.

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1. Basis of Presentation

Operations. W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Our interests in fields, leases, structures and equipment are primarily owned by the Company and its 100% owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC, and Aquasition II, LLC, and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 5.

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, 2020.

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.

Accounting Standards Updates effective January 1, 2021

Simplifying the Accounting for Income Taxes. In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes ("ASU 2019-12"). ASU 2019-12 simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and by clarifying and amending existing guidance. ASU 2019-12 is effective for annual and interim financial statement periods beginning after December 15, 2020. Adoption of the amendment did not have a material impact on our financial statements or disclosures.

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

Employee Retention Credit. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the nine months ended September 30, 2021 which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.

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Credit Risk and Allowance for Credit Losses. Our revenue is concentrated in certain major oil and gas companies. For the nine months ended September 30, 2021, and the year ended December 31, 2020, approximately 61% and 62%, respectively, of our revenue was from three major oil and gas companies and a substantial majority of our receivables were from sales with major oil and gas companies. We also have receivables related to joint interest arrangements primarily with mid-size oil and gas companies with a substantial majority of the net receivable balance concentrated in less than ten companies. A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and forecasts of future economic conditions. Our maximum exposure at any time would be the receivable balance. The receivables related to joint interest billings are reported on the Condensed Consolidated Balance Sheets net of the allowance for credit losses. The allowance for credit losses was $9.2 million as of September 30, 2021 and $9.1 million December 31, 2020.

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


	September 30, 2021		December 31, 2020
Derivatives – current ⁽¹⁾	$	52,327	$	2,752
Unamortized insurance/bond premiums		6,969		4,717
Prepaid deposits related to royalties		6,254		4,473
Prepayment to vendors		4,265		1,429
Prepayments to joint interest partners		3,604		402
Other		223		59
Prepaid expenses and other assets	$	73,642	$	13,832

⁽¹⁾	^{Includes closed contracts which have not yet settled.}

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


	September 30, 2021		December 31, 2020
Oil and natural gas properties and equipment, at cost	$	8,601,081	$	8,567,509
Furniture, fixtures and other		20,844		20,847
Total property and equipment		8,621,925		8,588,356
Less: Accumulated depreciation, depletion, amortization and impairment		7,967,989		7,901,478
Oil and natural gas properties and other, net	$	653,936	$	686,878

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


	September 30, 2021		December 31, 2020
Right-of-Use assets	$	10,689	$	11,509
Unamortized debt issuance costs		1,075		2,094
Investment in White Cap, LLC		3,034		2,699
Unamortized brokerage fee for Monza		—		626
Proportional consolidation of Monza's other assets (Note 5)		2,992		1,782
Derivatives		44,920		2,762
Other		1,066		998
Total other assets (long-term)	$	63,776	$	22,470

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


	September 30, 2021		December 31, 2020
Accrued interest	$	25,693	$	10,389
Accrued salaries/payroll taxes/benefits		7,604		4,009
Litigation accruals		530		436
Lease liability		845		394
Derivatives ⁽¹⁾		159,538		13,620
Other		2,276		1,032
Total accrued liabilities	$	196,486	$	29,880

⁽¹⁾	^{Includes closed contracts which have not yet settled.}

Paycheck Protection Program ("PPP"). On April 15, 2020, the Company received $8.4 million under the PPP offered by the U.S. Small Business Administration ("SBA"). We applied the guidance under IAS 20 and accounted for the PPP as a government grant with an offset to the applicable expenses for which the funds were utilized. The Company submitted an application to the SBA on August 20, 2020, requesting that the PPP funds received be applied to specific covered and non-covered payroll costs as allowed under the program. On June 11, 2021, we received notification that the SBA accepted our application and approved forgiveness of our PPP; therefore, we will not be required to repay the grant.

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


	September 30, 2021		December 31, 2020
Dispute related to royalty deductions	$	5,247	$	5,467
Derivatives		55,467		4,384
Lease liability		11,190		11,360
Black Elk escrow		11,102		11,103
Other		808		624
Total other liabilities (long-term)	$	83,814	$	32,938

2. Debt

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


	September 30, 2021		December 31, 2020
Term Loan:
Principal	$	203,223	$	—
Unamortized debt issuance costs		(7,838)		—
Total Term Loan		195,385		—

Company Credit Agreement borrowings:		—		80,000

Senior Second Lien Notes:
Principal		552,460		552,460
Unamortized debt issuance costs		(5,473)		(7,174)
Total Senior Second Lien Notes		546,987		545,286

Less current portion		(46,201)		—
Total long-term debt, net	$	696,171	$	625,286

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Current Portion of Long-Term Debt

As of September 30, 2021, the current portion of long-term debt of $46.2 million represented principal payments due within one year on the Term Loan (defined below).

Term Loan (Subsidiary Credit Agreement)

On May 19, 2021, Aquasition LLC (“A-I LLC”) and Aquasition II LLC (“A-II LLC”) (collectively, the “Borrowers”), both Delaware limited liability companies and indirect, wholly-owned subsidiaries of W&T Offshore, Inc., entered into a credit agreement (the “Subsidiary Credit Agreement”) providing for a term loan in an aggregate principal amount equal to $215.0 million (the “Term Loan”). The Term Loan requires quarterly amortization payments commencing September 30, 2021. The Term Loan bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and any subsidiaries other than the Borrowers and the subsidiary that owns the equity in the Borrowers, and is secured by the first lien security interests in the equity of the Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Borrowers (the Mobile Bay Properties, defined below).

In exchange for the net cash proceeds received by the Borrowers from the Term Loan, the Company assigned to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore crude oil treating and sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”). A portion of the proceeds to the Company was used to repay the $48.0 million outstanding balance on its reserve-based lending facility under the Company Credit Agreement (defined below), with the majority of the proceeds to W&T expected to be used for general corporate purposes, including oil and gas acquisitions, development activities, and other opportunities to grow the Company’s broader asset base. We refer to the transactions contemplated by the Subsidiary Credit Agreement, including the assignment of the Mobile Bay Properties to A-I LLC and the assignment of the Midstream Assets to A-II LLC as the “Mobile Bay Transaction”.

For information about Mobile Bay Transaction refer to Note 4, Mobile Bay Transaction.

Company Credit Agreement

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “Company Credit Agreement”), which matures on October 18, 2022. On May 19, 2021, we entered into a Waiver, Consent to Second Amendment to Intercreditor Agreement and Sixth Amendment to Sixth Amended and Restated Credit Agreement (the “Sixth Amendment”) which amended the Company Credit Agreement. The Sixth Amendment, among other things, (i) amended the Company Credit Agreement to effectuate the Mobile Bay Transaction (as discussed under Term Loan above and Note 4, Mobile Bay Transaction below) by specifically permitting the Mobile Bay Transaction and related transactions under certain covenants and (ii) consented to and waived certain technical defaults arising from the formation of certain company subsidiaries that were formed in advance of, and in order to effectuate, the consummation of the Mobile Bay Transaction and related transactions. On July 15, 2021, the Company entered into a Waiver and Seventh Amendment to Sixth Amended and Restated Credit Agreement (the “Seventh Amendment”) dated effective June 30, 2021, which further amended the Company Credit Agreement.

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The primary terms and covenants associated with the Company Credit Agreement as of September 30, 2021, as amended by the Sixth and Seventh Amendments, are as follows, with capitalized terms defined under the Company Credit Agreement:

The borrowing base was $190.0 million, subject to the next redetermination in the fourth quarter of 2021.

Letters of credit may be issued in amounts up to $30.0 million, provided availability under the Company Credit Agreement exists.

From the period ended June 30, 2020 through the period ended December 31, 2021 (the "Waiver Period"), the Company is not required to comply with the Leverage Ratio covenant. The Leverage Ratio, as defined in the Company Credit Agreement, is limited to 3.00 to 1.00 for quarters ending March 31, 2022 and thereafter.

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 Company Credit Agreement on the last day of the most recent quarter to EBITDAX for the trailing four quarters.

·The Current Ratio, as defined in the Company Credit Agreement, must be maintained at greater than 1.00 to 1.00.

The Company used a portion of the proceeds from Mobile Bay Transaction to repay $48.0 million outstanding balance on its reserve-based lending facility under the Company Credit Agreement. All liens on the Mobile Bay Properties granted to secure obligations under the Company Credit Agreement were released in connection with the transfer of such assets to Borrowers. The Company Credit Agreement is collateralized by a first priority lien on properties constituting at least 90% of the total proved reserves of the Company as set forth on reserve reports required to be delivered under the Company Credit Agreement and certain personal property, excluding those liens released in the Mobile Bay Transaction as described above.

As of September 30, 2021 and December 31, 2020, we had $4.4 million of letters of credit issued and outstanding under the Company Credit Agreement. Borrowings under the Company Credit Agreement were $0 and $80.0 million as of September 30, 2021 and December 31, 2020, respectively. The annualized interest rate on borrowings outstanding for the nine months ended September 30, 2021 was 3.2%, which excludes debt issuance costs, commitment fees and other fees.

Subsequent to September 30, 2021, the Company entered into two amendments of its Company Credit Agreement which significantly revised its first lien secured revolving credit facility. See Note 12 – Subsequent Events for additional information.

9.75% Senior Second Lien Notes Due 2023

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

During the year ended December 31, 2020, we acquired $72.5 million in principal of our outstanding Senior Second Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million, which included a reduction of $1.1 million related to the write-off of unamortized debt issuance costs. No such transactions were completed during the three and nine months ended September 30, 2021. As a result of these purchases, $552.5 million in principal amount of Senior Second Lien Notes remains issued and outstanding as of September 30, 2021 and December 31, 2020.

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

Covenants

As of September 30, 2021 and for all prior measurement periods, we were in compliance with all applicable covenants of the Company Credit Agreement and the Indenture. The Seventh Amendment revised certain covenants under the Company Credit Agreement related to hedging our future production and waived compliance with such requirements, including the requirement that certain existing hedge transactions be unwound or terminated, until our next semi-annual borrowing base redetermination occurs.

Fair Value Measurements

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

3. Fair Value Measurements

Derivative Financial Instruments

We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our open derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. Our open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 7 Derivative Financial Instruments, for additional information on our derivative financial instruments.

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


	September 30, 2021		December 31, 2020
Assets:
Derivatives instruments - open contracts, current	$	45,901	$	2,705
Derivatives instruments - open contracts, long-term		44,920		2,762

Liabilities:
Derivatives instruments - open contracts, current		140,601		13,291
Derivatives instruments - open contracts, long-term		55,467		4,384

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Debt

The fair value of the Term Loan was measured using a discounted cash flows model and current market rates. The net value of our debt under the Company Credit Agreement approximates fair value because the interest rates are variable and reflective of current market rates. The fair value of our Senior Second Lien Notes was measured using quoted prices, although the market is not a highly liquid market. The fair value of our debt was classified as Level 2 within the valuation hierarchy. See Note 2 – Debt for additional information on our debt.

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


	September 30, 2021				December 31, 2020
	Net Value		Fair Value		Net Value		Fair Value
Liabilities:
Term Loan	$	195,385	$	199,615	$	—	$	—
Company Credit Agreement		—		—		80,000		80,000
Senior Second Lien Notes		546,987		524,997		545,286		393,352
Total		742,372		724,612		625,286		473,352

4. Mobile Bay Transaction

On May 19, 2021, the Company’s wholly-owned special purpose vehicles (the “SPVs”), A-I LLC and A-II LLC or the Borrowers, entered into the Subsidiary Credit Agreement providing for the Term Loan in an aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts described in more detail under Note 7 – Derivative Financial Instruments, of this Quarterly Report.

As part of the Mobile Bay Transaction, the SPVs entered into a management services agreement (the “Services Agreement”) with the Company, pursuant to which the Company will provide (a) certain operational and management services for i) the Mobile Bay Properties and ii) the Midstream Assets and (b) certain corporate, general and administrative services for A-I LLC and A-II LLC (collectively in this capacity, the “Services Recipient”). Under the Services Agreement, the Company will indemnify the Services Recipient with respect to claims, losses or liabilities incurred by the Services Agreement Parties that relate to personal injury or death or property damage of the Company, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Services Recipient. The Services Recipient will indemnify the Company with respect to claims, losses or liabilities incurred by the Company that relate to personal injury or death of the Services Recipient or property damage of the Services Recipient, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Company. The Services Agreement will terminate upon the earlier of (a) termination of the Subsidiary Credit Agreement and payment and satisfaction of all obligations thereunder or (b) the exercise of certain remedies by the secured parties under the Subsidiary Credit Agreement and the realization by such secured parties upon any of the collateral under the Subsidiary Credit Agreement.

The SPVs are wholly-owned subsidiaries of the Company; however, the assets of the SPVs will not be available to satisfy the debt or contractual obligations of any non-SPV entities, including debt securities or other contractual obligations of W&T Offshore, Inc., and the SPVs do not bear any liability for the indebtedness or other contractual obligations of any non-SPVs, and vice versa. As of September 30, 2021, the book value of the assets of the SPVs were $319.6 million.

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5. Joint Venture Drilling Program

In March 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with us in the exploration, drilling and development of certain drilling projects (the “Joint Venture Drilling Program”) in the Gulf of Mexico. Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T’s commitment to fund its retained interest in Monza projects held outside of Monza, are $361.4 million. W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our retained working interest in the Monza projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board.

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

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

Through September 30, 2021, nine wells have been completed since the inception of the Joint Venture Drilling Program. In 2020, one well was drilled to target depth, which we expect to be completed in the fourth quarter of 2021 and we expect production to commence late in the fourth quarter of 2021. W&T is the operator for seven of the nine wells completed through September 30, 2021.

Through September 30, 2021, members of Monza made partner capital contributions, including our contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling $85.5 million. Our net contribution to Monza, reduced by distributions received, as of September 30, 2021 was $60.7 million. W&T is obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for the Joint Venture Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

Consolidation and Carrying Amounts

Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation. Through September 30, 2021, there have been no events or changes that would cause a redetermination of the variable interest status. We do not fully consolidate Monza because we are not considered the primary beneficiary of Monza. As of September 30, 2021, in the Condensed Consolidated Balance Sheet, we recorded $5.1 million, net, in Oil and natural gas properties and other, net, $3.0 million in Other assets, $0.3 million in Asset Retirement Obligations ("ARO") and $3.2 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. As of December 31, 2020, in the Condensed Consolidated Balance Sheet, we recorded $9.9 million, net, in Oil and natural gas properties and other, net, $1.8 million in Other assets, $0.2 million in ARO and $1.3 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. Additionally, during the nine months ended September 30, 2021 and during the year ended December 31, 2020, we called on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of September 30, 2021 and December 31, 2020 were $17.3 million and $7.3 million, respectively, which are included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners. For the nine months ended September 30, 2021, in the Condensed Consolidated Statement of Operations, we recorded $8.7 million in Total revenues and $9.5 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations. For the year ended December 31, 2020, in the Condensed Consolidated Statement of Operations, we recorded $8.4 million in Total revenues and, $12.1 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.

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6. Asset Retirement Obligations

Our ARO represent the estimated present value of the amount incurred to plug, abandon and remediate our properties at the end of their productive lives.

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


Balances, December 31, 2020	$	392,704
Liabilities settled		(19,744)
Accretion of discount		17,368
Liabilities incurred and assumed through acquisition		417
Revisions of estimated liabilities		17,129
Balances, September 30, 2021		407,874
Less current portion		(27,545)
Long-term	$	380,329

7. Derivative Financial Instruments

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

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

We entered into commodity contracts for crude oil and natural gas which related to a portion of our expected future production. The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices and the natural gas contracts are based off the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).

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The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts as of September 30, 2021:



		Average
	Instrument	Daily	Total	Weighted		Weighted		Weighted
Period	Type	Volumes	Volumes	Strike Price		Put Price		Call Price

Crude Oil - WTI (NYMEX)		(Bbls)⁽¹⁾	(Bbls)⁽¹⁾		($/Bbls)⁽¹⁾		($/Bbls)⁽¹⁾		($/Bbls)⁽¹⁾
Oct 2021 - Dec 2021	swaps	4,000	368,000	$	42.06	$	—	$	—
Jan 2022 - Nov 2022	swaps	2,525	843,256	$	49.99	$	—	$	—
Oct 2021 - Dec 2021	collars	1,762	162,084	$	—	$	39.55	$	58.12
Jan 2022 - Nov 2022	collars	2,428	811,096	$	—	$	41.71	$	58.91

Natural Gas - Henry Hub (NYMEX)		(MMbtu)⁽²⁾	(MMbtu)⁽²⁾		($/MMbtu)⁽²⁾		($/MMbtu)⁽²⁾		($/MMbtu)⁽²⁾
Oct 2021 - Dec 2021	calls	80,000	7,360,000	$	—	$	—	$	3.25
Jan 2022 - Dec 2022	calls	77,000	28,105,000	$	—	$	—	$	3.24
Jan 2023 - Dec 2023	calls	70,000	25,550,000	$	—	$	—	$	3.50
Jan 2024 - Dec 2024	calls	65,000	23,790,000	$	—	$	—	$	3.50
Jan 2025 - Mar 2025	calls	62,000	5,580,000	$	—	$	—	$	3.50
Oct 2021 - Dec 2021	collars	70,000	6,440,000	$	—	$	1.98	$	3.00
Jan 2022 - Dec 2022	collars	47,370	17,290,000	$	—	$	1.89	$	3.17
Oct 2021 - Dec 2021	swaps	10,000	920,000	$	2.62	$	—	$	—
Oct 2021 - Dec 2021 ⁽³⁾	swaps	81,522	7,500,000	$	3.06	$	—	$	—
Jan 2022 - Nov 2022	swaps	17,160	5,731,485	$	2.60	$	—	$	—
Jan 2022 - Dec 2022 ⁽³⁾	swaps	78,904	28,800,000	$	2.69	$	—	$	—
Jan 2023 - Dec 2023 ⁽³⁾	swaps	72,329	26,400,000	$	2.48	$	—	$	—
Jan 2024 - Dec 2024 ⁽³⁾	swaps	65,574	24,000,000	$	2.46	$	—	$	—
Jan 2025 - Mar 2025 ⁽³⁾	swaps	63,333	5,700,000	$	2.72	$	—	$	—
Apr 2025 - Dec 2025⁽³⁾	puts	62,182	17,100,000	$	—	$	2.27	$	—
Jan 2026 - Dec 2026 ⁽³⁾	puts	55,890	20,400,000	$	—	$	2.35	$	—
Jan 2027 - Dec 2027 ⁽³⁾	puts	52,603	19,200,000	$	—	$	2.37	$	—
Jan 2028 - Apr 2028 ⁽³⁾	puts	49,587	6,000,000	$	—	$	2.50	$	—

⁽¹⁾	^{Bbls – Barrels}

⁽²⁾	^{MMbtu – Million British Thermal Units}

⁽³⁾	^{These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with the Mobile Bay Transaction (see Note 4}^{Mobile Bay Transaction).}

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


	September 30,		December 31,
	2021		2020
Prepaid expenses and other current assets	$	52,327	$	2,752
Other assets (long-term)		44,920		2,762
Accrued liabilities		159,538		13,620
Other liabilities (long-term)		55,467		4,384

The amounts recorded on the Condensed Consolidated Balance Sheets are on a gross basis.

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Changes in the fair value and settlements of contracts are recorded on the Condensed Consolidated Statements of Operations as Derivative loss (gain). The impact of our commodity derivative contracts has on the Condensed Consolidated Statements of Operations were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Realized loss (gain)	$	30,026	$	(1,951)	$	53,627	$	(33,921)
Unrealized loss (gain)		43,111		13,112		125,529		(1,416)
Derivative loss (gain)	$	73,137	$	11,161	$	179,156	$	(35,337)

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


	Nine Months Ended September 30,
	2021		2020
Derivative loss (gain)	$	179,156	$	(35,337)
Derivative cash (payments) receipts, net		(39,554)		42,028
Derivative cash premiums (payments)		(32,368)		—

Subsequent Events. On October 6, 2021, the Company executed the unwinding of two natural gas collar contracts for $5.2 million. The following table reflects the contracted volumes and weighted average prices under the terms of these two contracts as of September 30, 2021:

Average

Instrument

Daily

Total

Weighted

Period

Type

Volumes

Strike Price

Put Price

Call Price

Natural Gas - Henry Hub (NYMEX)

(MMbtu)(2)

($/MMbtu)(2)

Nov 2021 - Dec 2021

collars

30,000

1,830,000

—

2.18

3.00

The following table presents the fair value of the open positions related to the two unwound contracts as recorded in the Condensed Consolidated Balance Sheets as of September 30, 2021 in the category presented (in thousands):


	September 30,
	2021
Accrued liabilities	$	5,189

Additionally, as a result of certain amendments to the Company Credit Agreement entered into on November 2, 2021 (as described in Note 12 – Subsequent Events), certain existing commodity derivative contracts not associated with the Mobile Bay Transaction (as described above in Note 4) have been novated to a new counterparty at the same terms.

8. Share-Based Awards and Cash-Based Awards

Share-Based Awards to Employees

The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by our shareholders in 2010. Under the Plan, the Company may issue, subject to the approval of the Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, performance units or shares, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants.

As of September 30, 2021, there were 10,347,591 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 awards are settled in

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shares of common stock, which shares of common stock are issued net of withholding tax through the withholding of shares. The Company has the option following vesting to settle awards in stock or cash, or a combination of stock and cash. The Company expects to settle outstanding awards, discussed below, that vest in the future using shares of common stock.

Restricted Stock Units (“RSUs”) RSUs currently outstanding relate to the 2021 and 2019 grants. During the nine months ended September 30, 2021, the Company granted RSUs under the plan to certain employees. No RSUs were granted in 2020. The 2021 RSUs granted are a long-term compensation component, subject to service conditions, with one-third of the award vesting each year on January 1, 2022, 2023, and 2024, respectively.

The 2019 grants were subject to predetermined performance criteria applied against the applicable performance period. All of the 2019 RSUs currently outstanding are also subject to employment-based criteria and, subject to the satisfaction of the service conditions, vesting of the outstanding 2019 RSUs will occur in December 2021.

A summary of activity related to RSUs during the nine months ended September 30, 2021 is as follows:


	Restricted Stock Units
		Weighted
		Average
		Grant Date Fair
	Units	Value Per Unit
Nonvested, December 31, 2020	763,688	$	4.51
Granted	704,949		4.71
Vested	—		—
Forfeited	(43,132)		4.55
Nonvested, September 30, 2021	1,425,505		4.61

For the outstanding RSUs issued to the eligible employees as of September 30, 2021, vesting is expected to occur as follows (subject to forfeitures):


		Restricted
		Shares
2021		731,095
2022		231,470
2023		231,470
2024		231,470
Total		1,425,505

Performance Share Units (“PSUs”) During the nine months ended September 30, 2021, the Company granted PSUs under the plan to certain employees. The PSUs are RSU awards granted subject to performance criteria. The performance criteria relates to the evaluation of the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for the applicable performance period (2021) and service-based criteria. TSR is determined based on the change in the entity’s stock price plus dividends for the applicable performance period. Subsequent to the performance period, the PSUs will continue to be subject to service-based criteria with vesting occurring on October 1, 2023.

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A summary of activity related to PSUs during the nine months ended September 30, 2021 is as follows:


	Performance Share Units
		Weighted
		Average
		Grant Date Fair
	Units	Value Per Unit
Nonvested, December 31, 2020	—	$	—
Granted	391,189		5.57
Vested	—		—
Forfeited	(4,890)		5.57
Nonvested, September 30, 2021	386,299		5.57

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. All PSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. The grant date fair value of the PSUs was determined through the use of the Monte Carlo simulation method. This method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group companies’ stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies. The valuation model assumes dividends, if any, are immediately reinvested. The grant date fair value of the PSUs granted during the nine months ended September 30, 2021, is $2.2 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted:


	2021 Grant Date
	June 28
Expected term for performance period (in years)	0.5
Expected volatility	67.9	%
Risk-free interest rate	0.1	%

Share-Based 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 the nine months ended September 30, 2021, and during the year ended December 31, 2020. During the second quarter of 2020, our shareholders approved increasing the shares available under the Director Compensation Plan by 500,000 shares. As of September 30, 2021, there were 410,742 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available are reduced on a one-to-one basis when Restricted Shares are granted.

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

The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless otherwise approved by the Board of Directors. Restricted Shares cannot be sold, transferred or disposed of during the restricted period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such Restricted Shares, including the right to vote and receive dividends or other distributions paid with respect to the Restricted Shares.

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A summary of activity related to Restricted Shares during the nine months ended September 30, 2021 is as follows:


	Restricted Shares
		Weighted
		Average
		Grant Date Fair
	Units	Value Per Unit
Nonvested, December 31, 2020	154,128	$	3.64
Granted	62,502		3.36
Vested	(146,404)		3.51
Nonvested, September 30, 2021	70,226		3.67

Subject to the satisfaction of the service conditions, the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2021 are eligible to vest in 2022.

Share-Based Compensation Expense

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Restricted stock units	$	587	$	927	$	1,263	$	2,854
Performance share units		207		—		207
Restricted Shares		64		148		309		288
Total	$	858	$	1,075	$	1,779	$	3,142

Unrecognized Share-Based Compensation Expense

As of September 30, 2021, unrecognized share-based compensation expense related to our awards of RSUs, PSUs, and Restricted Shares was $2.7 million, $1.6 million, and $0.1 million, respectively. Unrecognized share-based compensation expense will be recognized through December 2023 for RSUs, September 2023 for PSUs, and April 2022 for Restricted Shares.

Cash-Based Incentive Compensation

In addition to share-based compensation, both short-term and long-term cash-based incentive awards were granted under the Plan to all eligible employees in 2021.

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Short-term Cash-Based Incentive Compensation There are two components of the short-term cash-based incentive award granted during the nine months ended September 30, 2021.

●

The first short-term, cash-based award granted in February 2021 was discretionary and subject only to continued employment on the payment dates. The 2021 discretionary bonus award was paid in equal installments on March 15, 2021 and April 15, 2021, to substantially all employees subject to employment on those dates. Incentive compensation expense of $7.6 million was recognized during the nine months ended September 30, 2021, related to these awards.

●

The second short-term, cash-based award granted in June 2021 is subject to Company performance-based criteria and individual performance criteria. Incentive compensation expense is based on estimates of Company metrics for full-year 2021 and is being recognized during the service period. Incentive compensation expense of $3.9 million was recognized during three and nine months ended September 30, 2021, respectively, related to these awards.

No cash-based incentive awards were granted in 2020. Cash-based incentive compensation expense recorded in 2020 related to the amortization of long-term cash awards granted in prior periods.

Long-term Cash-Based Incentive Compensation

The 2021 long-term, cash-based awards (“Cash Awards”) were granted in June 2021 and are subject to the same performance-based criteria as the PSUs noted above. The Company’s TSR ranking against peer companies will be evaluated for the performance period of 2021. Subsequent to the performance period, the Cash Awards will continue to be subject to service-based criteria with vesting occurring on October 1, 2023.

These Cash Awards are accounted for as liability awards and are measured at fair value each reporting date. We recognize compensation cost for share-based payments to employees over the service period from June 28, 2021 through October 1, 2023. The reporting date fair value of the awards was determined through the use of the Monte Carlo simulation method. This method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined peer group companies’ stock, risk-free rate of return, cross-correlations between the Company and our peer group companies, and an appropriate discount rate. The valuation model assumes dividends are immediately reinvested. The fair value of the awards as of September 30, 2021, is $0.7 million. As of September 30, 2021, unrecognized compensation expense related to these awards was $0.6 million. The following table summarizes the assumptions used to calculate the fair value of the outstanding long-term Cash Awards as of September 30, 2021:


Expected term for performance period (in years)	0.3
Expected volatility	76.0	%
Risk-free interest rate	0.3	%
Expected term for cash payment (in years)	2.0
Discount rate used to discount expected cash payment	12.9	%

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Share-based compensation included in:
General and administrative expenses	$	858	$	1,075	$	1,779	$	3,142
Cash-based incentive compensation included in:
Lease operating expense ⁽¹⁾		1,119		—		2,774		849
General and administrative expenses ⁽¹⁾		2,809		154		8,167		3,944
Total charged to operating (loss) income	$	4,786	$	1,229	$	12,720	$	7,935

(1)

Includes adjustments of accruals to actual payments.

9. Income Taxes

Tax Benefit and Tax Rate Income tax benefit for the three months ended September 30, 2021 and 2020 was $5.9 and $21.1 million, respectively. For the nine months ended September 30, 2021 and 2020, income tax benefit was $18.8 million and $23.3 million, respectively. For the three and nine months ended September 30, 2021, our effective tax rate differed from the statutory Federal tax rate primarily as a result of adjustments in our valuation allowance on certain deferred tax assets. For the three and nine months ended September 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 13.5% and 17.3% for the three and nine months ended September 30, 2021, respectively, and not meaningful for the three and nine months ended September 30, 2020, respectively.

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

As of September 30, 2021 and December 31, 2020, our valuation allowance was $24.1 million and $22.4 million, respectively, and relates primarily to state net operating losses and the disallowed interest expense limitation carryover.

Income Taxes Receivable, Refunds and Payments As of September 30, 2021 and December 31, 2020, we did not have any material outstanding current income taxes receivable. During the three months ended September 30, 2021, we did not receive any income tax refunds or make any income tax payments of significance. During the nine months ended September 30, 2020 we received an income tax refund of $1.9 million. The refund related primarily to a net operating loss (“NOL”) carryback claim for 2017 that was carried back to prior years.

The tax years 2018 through 2020 remain open to examination by the tax jurisdictions to which we are subject.

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10. Earnings Per Share

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net (loss) income	$	(37,964)	$	(13,339)	$	(90,382)	$	46,737
Less portion allocated to nonvested shares		—		—		—		549
Net (loss) income allocated to common shares	$	(37,964)	$	(13,339)	$	(90,382)	$	46,188
Weighted average common shares outstanding		142,297		141,624		142,231		141,589
Basic and diluted (loss) earnings per common share	$	(0.27)	$	(0.09)	$	(0.64)	$	0.33
Shares excluded due to being anti-dilutive (weighted-average)		1,514		1,677		1,106		—

11. Contingencies

Appeal with the Office of Natural Resources Revenue (“ONRR”) In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which ultimately led to our posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the Interior Board of Land Appeals (“IBLA”) decision, of which the cash collateral held by the surety was subsequently returned during the first quarter of 2020. We have continued to pursue our legal rights and, at present, the case is in front of the U.S. District Court for the Eastern District of Louisiana where both parties have filed cross-motions for summary judgment and opposition briefs. W&T has filed a Reply in support of its Motion for Summary Judgment and the government has in turn filed its Reply brief. With briefing now completed, we are waiting for the district court’s ruling on the merits. In compliance with the ONRR’s request for W&T to periodically increase the surety posted in the appeal to cover pre- and post-judgement interest, the sum of the bond posted is currently $8.2 million.

Royalties – “Unbundling” Initiative In 2016, the ONRR publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. While the amounts paid for the three and nine months ended September 30, 2021 and 2020 were immaterial, we are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

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Civil Penalty Assessments In January 2021, we executed a Settlement Agreement with the Bureau of Safety and Environmental Enforcement (“BSEE”) which resolved nine pending civil penalties issued by BSEE. The civil penalties pertained to Incidents of Noncompliance (“INCs”) issued by BSEE alleging regulatory non-compliance at separate offshore locations on various dates between July 2012 and January 2018, with the proposed civil penalty amounts totaling $7.7 million. Under the Settlement Agreement, W&T will pay a total of $720,000 in three annual installments. The first installment was paid in March 2021. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022. In September 2021, we paid $40,200 related to an INC issued in 2018. Additionally, we were notified of a new proposed civil penalty assessment for $46,000 for an INC that occurred at one of our properties in 2018.

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

12. Subsequent Events

Calculus Lending Facility

On November 2, 2021, the Company entered into the Eighth Amendment to Sixth Amended and Restated Credit Agreement and Master Assignment, Resignation and Appointment Agreement (the “Eighth Amendment”) which effectively terminated the Company’s reserve based lending relationship with commercial bank lenders who have traditionally provided its secured revolving credit facility. The Company has not had any borrowings under the Company Credit Agreement since the closing of the Mobile Bay Transaction in May of this year. As of November 2, 2021, the Company has cash collateralized or otherwise provided credit support for each of the outstanding letters of credit in the aggregate amount of approximately $4.4 million issued by the commercial bank lenders under the amended Credit Agreement. Alter Domus (US) LLC was appointed to replace Toronto Dominion (Texas) LLC as administrative agent under the amended Company Credit Agreement.

On November 2, 2021, the Company also entered into the Ninth Amendment to the Sixth Amended and Restated Credit Agreement (the “Ninth Amendment”), which establishes a short-term $100 million first priority lien secured revolving facility with a borrowing base of $50 million (the “Calculus Lending facility”) provided by Calculus Lending, LLC, (“Calculus”) a company affiliated with, and controlled by W&T’s Chairman and Chief Executive Officer, Tracy W, Krohn, as sole lender under the Calculus Lending facility. A committee of the independent members of the Board of Directors reviewed and approved the amendments given the CEO’s affiliation with Calculus Lending, LLC.

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As a result the Eighth Amendment and Ninth Amendment and related assignments and agreements, the key terms and covenants associated with the Calculus Lending facility under the amended Company Credit Agreement are as follows:

The revised borrowing base is $50.0 million.

The Calculus Lending facility commitment will expire and final maturity of any and all outstanding loans is April 30, 2022. Outstanding borrowings will accrue interest at LIBOR plus 6.0% per annum. The commitment fee for the unused portion of available borrowing amounts will be 3.0% per annum.

The Company’s ratio of first lien debt outstanding under the Calculus Lending facility on the last day of the most recent quarter to EBITDAX (as such term is defined in the amended Company Credit Agreement) for the trailing four quarters must not be greater than 2.50 to 1.00 on the last day of the fiscal quarter ending March 31, 2022 and on the last day of each fiscal quarter thereafter.

The Company’s ratio of Total Proved PV-10 to First Lien Debt (as such terms are defined in the amended Company Credit Agreement) as of the last day of any fiscal quarter commencing with the fiscal quarter ending March 31, 2022 must be equal to or greater than 2.00 to 1.00.

The ratio of the Company and its restricted subsidiaries’ consolidated current assets to Company and its restricted subsidiaries’ consolidated current liabilities (subject in each case to certain exceptions and adjustments as set forth in the amended Company Credit Agreement) at the last day of any fiscal quarter must be greater than or equal to 1.00 to 1.00.

●

As of the last day of any fiscal quarter commencing with the fiscal quarter ending March 31, 2022, the Company and its restricted subsidiaries on a consolidated basis must pass a “Stress Test” consisting of an analysis conducted by the lender in good faith and in consultation with the Company based upon the latest engineering report furnished to lender, which analysis is designed to determine whether the future net revenues expected to accrue to the Company’s and its guarantor subsidiaries’ interest (and the interest of certain joint ventures) in the oil and gas properties included in the properties used to determine the latest borrowing base during half of the remaining expected economic lives of such properties are sufficient to satisfy the aggregate first lien indebtedness of the Company and its restricted subsidiaries in accordance with the terms of such indebtedness assuming the Calculus Lending facility is 100% funded or fully utilized.

●

Certain related party transactions are required to meet certain arm’s length criteria; except in each case as specifically permitted or excluded from the covenant under the amended Company Credit Agreement.

As consideration for its commitment as sole lender and consistent with customary non-commercial bank lending practice, Calculus will be paid certain market-based fees in connection with its commitment. Additionally, as a result of the recent amendments to the Company Credit Agreement and related agreements, certain existing commodity derivative contracts not associated with the Mobile Bay Transaction have been novated to a new counterparty at the same terms.

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

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to those financial statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited Consolidated Financial Statements and the notes thereto in our 2020 Annual Report and the Related Management’s Discussion and Analysis of Financial Condition and the Results of Operations included in Part II, Item 7 of our 2020 Annual Report on Form 10-K (the “2020 Annual Report”).

Forward-Looking Statements

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These forward-looking statements are subject risks, uncertainties and assumptions, most of which are difficult to predict and many of which are beyond our control. 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. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, estimates, 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 2020 Annual Report, 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. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of September 2021, we hold working interests in 42 offshore fields in federal and state waters (41 fields producing and 1 field capable of producing, which include 34 fields in federal waters and 8 in state waters). We currently have under lease approximately 611,000 gross acres (414,000 net acres) spanning across the outer continental shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama State waters, 416,000 gross acres on the conventional shelf and approximately 186,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, W & T Energy VI, LLC, Delaware limited liability companies, and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements – Note 5 Joint Venture Drilling Program under Part I, Item 1 in this Quarterly Report.

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Recent Events

As COVID-19 vaccines have been more widely distributed, global economic activity is improving and commodity prices are currently above pre-pandemic levels. However, the energy markets remain subject to heightened levels of uncertainty as responses to COVID-19 and COVID-19 variants continue to evolve. We will continue to monitor the effects of the pandemic on the energy markets in the future.

Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, and Liquidity and Capital Resources in this Item 2 of this Quarterly Report for additional information.

During the second quarter of 2021, the Company’s wholly-owned special purpose vehicles, A-I LLC and A-II LLC or the Borrowers, entered into the Subsidiary Credit Agreement providing for a secured term loan (“Term Loan”) in an aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts. This transaction is described in more detail under Financial Statements –Note 4 – Mobile Bay Transaction, under Part 1, Item 1, of this Quarterly Report.

Commencing in late August 2021, we experienced a significant temporary shut-in and deferral of as much as approximately 80% of the Company’s production in preparation for, and as a result of, the effects of Hurricane Ida. The majority of our impacted production was brought back online during September 2021. We expect our hurricane impacted production remaining shut in or reduced on the date of the filing of this report to be online by the end of 2021, depending in part upon the resolution of issues by our non-operated property operators and issues with third party pipelines, refineries and other onshore infrastructure. While Company assets and infrastructure did not suffer significant damage during the storm, unplanned costs for minor repairs and restoring production, as well as evacuating employees and contractors, were incurred as a result of the hurricane and reflected in lease operating expense.

Oil and Natural Gas Production and Commodity Pricing

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. The price of those commodities is affected by both domestic and international factors, including domestic production. Our production volumes for the nine months ended September 30, 2021 were comprised of 36.3% crude oil and condensate, 10.5% NGLs and 53.2% natural gas, determined on a barrel of oil equivalent (“Boe”) basis using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil or NGLs. The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past. For the nine months ended September 30, 2021, our total revenues were 55.8% higher than the nine months ended September 30, 2020 due to higher realized prices for crude oil, NGLs and natural gas, which were partially offset by lower volumes. See Results of Operations –Nine Months Ended September 30, 2021, Compared to the Nine Months Ended September 30, 2020 in this Item 2 for additional information.

During the nine months ended September 30, 2021, our average realized crude oil price was $63.07 per barrel. This is an increase of 69.7% from our average realized crude oil price of $37.17 per barrel during the nine months ended September 30, 2020. Per the Energy Information Administration ("EIA"), crude oil prices using average West Texas Intermediate (“WTI”) daily spot pricing increased to $65.05 per barrel during the nine months ended September 30, 2021 compared to $38.04 per barrel during the nine months ended September 30, 2020 representing an increase of 71.0%. Crude oil prices have recovered to pre-pandemic levels from their April 2020 lows caused by the ongoing COVID-19 pandemic as the vaccines have been more widely distributed and economic activity has increased.

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Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary significantly by field. All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of Poseidon, LLS and HLS to WTI for the nine months ended September 30, 2021 averaged ($0.90), $1.70, and $1.08 per barrel, respectively, and each average differential has changed ($0.68), ($0.68), and ($0.73) per barrel, respectively compared to the nine months ended September 30, 2021.

Our average realized price of natural gas of $3.40 per Mcf for the nine months ended September 30, 2021 was 80.9% higher than the average realized price of $1.88 per Mcf for the nine months ended September 30, 2020. The average Henry Hub ("HH") daily natural gas spot price of $3.61 per Mcf for the nine months ended September 30, 2021 was 89.7% higher than the average HH natural gas price of $1.94 per Mcf for the nine months ended September 30, 2020. Per the EIA, this increase was caused by increased demand related to the increase in economic activity and is somewhat elevated by the much higher average price in February 2021 caused by much colder-than-normal temperatures across the country.

Our average realized price of NGLs of $27.51 per barrel for the nine months ended September 30, 2021 was 181.3% higher than the average realized price of $9.78 per barrel for the nine months ended September 30, 2020. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, average prices for domestic ethane increased by 53.7% and average domestic propane prices increased by 128.9% as measured using a price index for Mount Belvieu. The average prices for other domestic NGLs components increased from 95.5% to 106.2% for the nine months ended September 30, 2021 compared to the same period in 2020. 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 in the U.S. as reported in their October 15, 2021 report was higher than a year ago, increasing to 543 rigs compared to 282 rigs a year ago. The oil rig count increased to 445 rigs compared to 205 rigs a year ago and the gas and miscellaneous rigs increased to 98 rigs from 77 a year ago. In the Gulf of Mexico, the number of working rigs was 12 rigs compared to 14 a year ago.

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Results of Operations

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020			Change	2021		2020			Change

	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	74,265	$	46,589	$	27,676	$	240,418	$	161,884	$	78,534
NGLs		12,205		4,464		7,741		30,397		12,833		17,564
Natural gas		45,137		19,213		25,924		113,816		69,877		43,939
Other		2,339		2,251		88		7,790		7,292		498
Total revenues		133,946		72,517		61,429		392,421		251,886		140,535
Operating costs and expenses:
Lease operating expenses		39,490		36,437		3,053		129,399		119,525		9,874
Production taxes		2,600		1,266		1,334		6,552		3,325		3,227
Gathering and transportation		3,993		3,560		433		13,135		12,310		825
Depreciation, depletion, amortization and accretion		26,291		25,127		1,164		83,879		93,736		(9,857)
General and administrative expenses		13,391		14,476		(1,085)		38,090		34,067		4,023
Derivative loss (gain)		73,137		11,161		61,976		179,156		(35,337)		214,493
Total costs and expenses		158,902		92,027		66,875		450,211		227,626		222,585
Operating (loss) income		(24,956)		(19,510)		(5,446)		(57,790)		24,260		(82,050)
Interest expense, net		18,910		14,135		4,775		50,474		46,061		4,413
Gain on debt transactions		—		—		—		—		(47,469)		47,469
Other expense, net		—		751		(751)		964		2,225		(1,261)
(Loss) income before income tax (benefit) expense		(43,866)		(34,396)		(9,470)		(109,228)		23,443		(132,671)
Income tax (benefit) expense		(5,902)		(21,057)		15,155		(18,846)		(23,294)		4,448
Net (loss) income	$	(37,964)	$	(13,339)	$	(24,625)	$	(90,382)	$	46,737	$	(137,119)
Basic and diluted (loss) earnings per common share	$	(0.27)	$	(0.09)	$	(0.18)	$	(0.64)	$	0.33	$	(0.97)

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020			Change	2021		2020			Change
Operating:^{(1) (2)}
Net sales:
Oil (MBbls)		1,083		1,115		(32)		3,812		4,356		(544)
NGLs (MBbls)		376		407		(31)		1,105		1,312		(207)
Natural gas (MMcf)		10,481		9,897		584		33,469		37,210		(3,741)
Total oil equivalent (MBoe)		3,206		3,170		36		10,495		11,869		(1,374)

Average daily equivalent sales (Boe/day)		34,846		34,459		387		38,444		43,317		(4,873)
Average realized sales prices:
Oil ($/Bbl)	$	68.57	$	41.81	$	26.76	$	63.07	$	37.17	$	25.90
NGLs ($/Bbl)		32.46		10.99		21.47		27.51		9.78		17.73
Natural gas ($/Mcf)		4.31		1.94		2.37		3.40		1.88		1.52
Oil equivalent ($/Boe)		41.05		22.16		18.89		36.65		20.61		16.04
Oil equivalent ($/Boe), including realized commodity derivatives		31.69		22.78		8.90		31.54		23.47		8.07

Average per Boe ($/Boe):
Lease operating expenses	$	12.32	$	11.49	$	0.83	$	12.33	$	10.07	$	2.26
Gathering and transportation		1.25		1.12		0.13		1.25		1.04		0.21
Production costs		13.57		12.61		0.96		13.58		11.11		2.47
Production taxes		0.81		0.40		0.41		0.62		0.28		0.34
DD&A		8.20		7.93		0.27		7.99		7.90		0.09
G&A expenses		4.18		4.57		(0.39)		3.63		2.87		0.76
Operating costs	$	26.76	$	25.51	$	1.25	$	25.82	$	22.16	$	3.66

⁽¹⁾

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

⁽²⁾	^{Some average figures in this table may not compute due to rounding.}


Volume measurements not previously defined:
MBbls — thousand barrels for crude oil, condensate or NGLs		Mcf — thousand cubic feet
MBoe — thousand barrels of oil equivalent		MMcf – million cubic feet

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Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020

Revenues. The increase in oil revenues was attributable to an increase in average realized sales price per Bbl to $68.57 from $41.81 for the three months ended September 30, 2021 and 2020, respectively. This was partially offset by a 2.9% decrease in oil sales volumes for the three months ended September 30, 2021 as compared to the same period in the prior year. The increase in NGLs revenues was attributable to an increase in the average realized sales price per Bbl to $32.46 from $10.99 for the three months ended September 30, 2021 and 2020, respectively. This was partially offset by a 7.6% decrease in NGL sales volumes during the three months ended September 30, 2021 as compared to the same period in the prior year. The increase in natural gas revenues was attributable to an increase in the average realized price to $4.31 per Mcf from $1.94 per Mcf for the three months ended September 30, 2021 and 2020, respectively, and a 5.9% increase in volumes.

Overall sales volumes increased 1.1% on a Boe per day basis for the three months ended September 30, 2021 compared to the three months ended September 30, 2020. Both periods included hurricane related downtime as well as other deferred production for various reasons. We estimate that deferred production reduced the produced volumes for the three months ended September 30, 2021 by approximately 9,400 Boe per day as compared to 13,500 Boe per day for the three months ended September 30, 2020. This decrease in deferred production was comprised of 1,600 Boe per day less hurricane downtime and 2,500 Boe per day less shutting-in certain operated fields and non-operated field issues. Production from certain of our properties continue to be impacted in the fourth quarter 2021 by the temporary shut-in and deferral of production resulting from the effects of Hurricane Ida which will affect primarily oil revenues for that quarter. See “Recent Events” in this Item 2 above.

Revenues from oil and NGLs as a percent of our total revenues were 64.6% for the three months ended September 30, 2021 compared to 70.4% for the three months ended September 30, 2020. Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased to 47.3% for the three months ended September 30, 2021 compared to 26.3% for the three months ended September 30, 2020.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased $3.1 million, or 8.4% for the three months ended September 30, 2021 compared to the three months ended September 30, 2020. On a component basis, base lease operating expenses decreased $0.4 million, workover expenses increased $0.4 million, facilities maintenance expense increased $2.4 million, and hurricane repairs increased $0.7 million.

Base lease operating expenses decreased primarily due to decreased contract labor and supplies due to the consolidation of our two gas processing plants in Alabama. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Lastly, we incurred $0.7 million in expenses related to repairs associated with Hurricane Ida during the three months ended September 30, 2021 that we did not incur during the comparable prior year period.

Certain facility-related expenses planned to be incurred in the three months ended September 30, 2021 were postponed until the fourth quarter of 2021 due to Hurricane Ida.

Production taxes. Production taxes increased $1.3 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020 due to the increase in realized natural gas prices, increased NGL prices, and to a lesser extent increased natural gas production volumes.

Gathering and transportation. Gathering and transportation expenses increased $0.4 million for the three months ended September 30, 2021 compared to the three months ended September 30, 2020 primarily due to lower costs in the comparable prior year period that were impacted by credits to expense associated with the finalization of the Mobile Bay acquisition.

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Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, increased to $8.20 per Boe for the three months ended September 30, 2021 from $7.93 per Boe for the three months ended September 30, 2020. On a nominal basis, DD&A increased 4.6%, or $1.2 million for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020. The rate per Boe increased year-over-year mostly as a result of increases in the future development costs included in the depreciable base compared to the smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”). G&A decreased $1.1 million, or 7.5%, for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020. The decrease was primarily due to (i) a decrease in legal costs of $1.4 million; (ii) a decrease of $0.9 million in other G&A expenses, primarily related to lower rent expense; and (iii) an increase in overhead allocations to partners (credits to expense) of $0.3 million; partially offset by, (iv) increased incentive compensation expenses of $1.5 million.

Derivative loss (gain). The three months ended September 30, 2021 includes an $73.1 million derivative loss primarily due to increased crude oil prices during September 2021 compared to prices during June 2021, which decreased the estimated fair value of open crude oil contracts between the two measurement dates, partially offset by increased natural gas prices during September 2021 compared to prices at June 2021 which increased the estimated fair value of open natural gas call option contracts between the two measurement dates. The three months ended September 30, 2020 reflects a $11.2 million derivative loss primarily due to increased crude oil prices during September 2020 compared to oil prices during June 2020, which decreased the estimated fair value of open crude oil contracts between the two measurement dates. Partially offsetting this decrease were realized gains from oil collar contracts where the prevailing oil price was below the contract floor price.

Interest expense, net. Interest expense, net, was $18.9 million and $14.1 million for the three months ended September 30, 2021 and 2020, respectively. The increase of $4.8 million in 2021 is primarily due to interest expense on the principal balance of the Term Loan, and a reduction in credits to interest expense related to the PPP funds received in the prior period; partially offset by reductions to outstanding borrowings (lower interest expense) under the Company Credit Agreement during 2021.

Income tax benefit. Our income tax benefit was $5.9 million and $21.1 million for the three months ended September 30, 2021 and 2020, respectively. For the three months ended September 30, 2021, our income tax benefit primarily differed from the statutory Federal tax rate as a result of adjustments to our valuation allowance on certain deferred tax assets. For the three months ended September 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 13.5% for the three months ended September 30, 2021 and not meaningful for the three months ended September 30, 2020.

As of September 30, 2021, the valuation allowance on our deferred tax assets was $24.1 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Revenues. The increase in oil revenues was attributable to an increase in the average realized sales price per Bbl to $63.07 from $37.17 for the nine months ended September 30, 2021 and 2020, respectively. This was partially offset by a decrease in oil sales volumes of 12.5%. The increase in NGLs revenues was attributable to a 181.3% increase in the average realized sales price for the nine months ended September 30, 2021 compared to 2020. This was partially offset by a decrease in NGL sales volumes of 15.8% for the same period. The increase in natural gas revenues was attributable to an 80.9% increase in the average realized sales price for the nine months ended September 30, 2021 compared to 2020. This was partially offset by a 10.1% decrease in natural gas sales volumes for the same period.

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Overall, sales volumes decreased 11.2% on a Boe per day basis primarily due to shut-ins related to adverse weather events, well maintenance and natural declines at various fields during the nine months ended September 30, 2021. We estimate that these shut-ins reduced the produced volumes for the nine months ended September 30, 2021 by approximately 5,954 Boe per day as compared to 3,800 Boe per day for the nine months ended September 30, 2020. Production from certain of our properties continue to be impacted in the fourth quarter 2021 by the temporary shut-in and deferral of production resulting from the effects of Hurricane Ida which will affect revenues for that quarter. See “Recent Events” in this Item 2 above.

Revenues from oil and NGLs as a percent of our total revenues were 69.0% for the nine months ended September 30, 2021 compared to 69.4% for the nine months ended September 30, 2020. Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased to 43.6% for the nine months ended September 30, 2021 compared to 26.3% for the nine months ended September 30, 2020.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $9.9 million, or 8.3%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. On a component basis, base lease operating expenses increased $1.1 million, workover expenses increased $1.4 million, facilities maintenance expense increased $2.9 million, and hurricane repairs increased $4.5 million.

Base lease operating expenses increased during the nine months ended September 30, 2021 primarily due to (i) a net increase in contract labor, equipment rental, and transportation costs of $3.1 million at various fields; (ii) increased incentive compensation costs related to field employees of $2.2 million; (iii) a reduction in credits to expense from prior period royalty adjustments of $2.2 million as compared to the prior period; (iv) a reduction in credits to expense of $2.3 million received in prior period from the PPP funds; and (v) a reduction in credits to expense in the prior year associated with the finalization of the Mobile Bay acquisition; partially offset by (vi) $5.7 million of reduced expenses during the first quarter of 2021 related to successful cost reduction efforts at various fields and other reduced expenses; and (vii) $3.1 million of reduced expenses related to fields that were no longer producing during the nine months ended September 30, 2021, cost savings from the consolidation of our two gas processing plants in Alabama, and other miscellaneous items. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Lastly, we incurred $3.8 million in expenses related to hurricane repairs at various fields during the nine months ended September 30, 2021 that we did not incur during the prior year period.

Certain facility-related expenses planned to be incurred in the three months ended September 30, 2021 were postponed until the fourth quarter of 2021 due to Hurricane Ida.

Production taxes. Production taxes increased $3.2 million during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 due to the increase in realized natural gas prices, partially offset by decreased natural gas production volumes.

Gathering and transportation. Gathering and transportation expenses increased $0.8 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 primarily due to lower costs in the comparable prior year period that were impacted by credits to expense associated with the finalization of the Mobile Bay acquisition.

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, increased to $7.99 per Boe for the nine months ended September 30, 2021 from $7.90 per Boe for the nine months ended September 30, 2020. On a nominal basis, DD&A decreased 10.5%, or $9.9 million for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020. The rate per BOE increased year-over-year mostly as a result of increases in future development costs included in the depreciable base compared to the relatively smaller increase in proved reserves and the decrease in production volumes over the same period.

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General and administrative expenses. G&A increased $4.0 million, or 11.8%, for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020. The increase was primarily due to (i) credits related to the PPP funds received in the prior period; (ii) a reduction in overhead allocations to partners (credits to expense) of $1.3 million; and (iii) a net increase of $0.9 million in payroll and incentive compensation expenses; partially offset by (iv) the $2.1 million employee retention credit recognized during the three months ended March 31, 2021, and (v) a net decrease in legal costs and other miscellaneous expenses of $0.3 million. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, and Liquidity and Capital Resources in this Item 2 of this Quarterly Report for additional information on the employee retention credit.

Derivative loss (gain). The nine months ended September 30, 2021 reflects a $179.2 million derivative loss primarily due to increased crude oil prices during the nine months ended September 30, 2021 compared to prices during as of December 31, 2020, which decreased the estimated fair value of open crude oil contracts between the two measurement dates, partially offset by increased natural gas prices during the nine months ended September 30, 2021 compared to prices as of December 31, 2020 which increased the estimated fair value of open natural gas call option contracts between the two measurement dates. The nine months ended September 30, 2020 reflects a $35.3 million derivative gain primarily due to realized gains on oil swap and collar contracts where the prevailing prices were below the strike or floor price.

Interest expense, net. Interest expense, net, was $50.5 million and $46.1 million for the nine months ended September 30, 2021 and 2020, respectively. The increase of $4.5 million is primarily due to interest expense on the principal balance of the Term Loan, and a reduction in credits to interest expense related to the PPP funds received in the prior period; partially offset by reductions to outstanding borrowings (lower interest expense) under the Company Credit Agreement during 2021.

Gain on purchase of debt. A gain of $47.5 million was recorded related to the purchase of $72.5 million of principal of our outstanding Senior Second Lien Notes during the nine months ended September 30, 2020. No such transactions occurred during the nine months ended September 30, 2021.

Income tax benefit. Our income tax benefit was $18.8 million and $23.3 million for the nine months ended September 30, 2021 and 2020, respectively. For the nine months ended September 30, 2021, our income tax benefit primarily differed from the statutory Federal tax rate as a result of adjustments to our valuation allowance on certain deferred tax assets. For the nine months ended September 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 17.3% for the nine months ended September 30, 2021 and not meaningful for the nine months ended September 30, 2020.

Liquidity and Capital Resources

Liquidity Overview

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

As of September 30, 2021, we had $257.6 million cash on hand, no borrowings under the revolving credit facility under out Sixth Amended and Restated Credit Agreement (the “Company Credit Agreement”) and no maturities of long-term debt until October 2023, other than scheduled quarterly amortization payments under the Term Loan (see Financial Statements – Note 2 – Debt, under Part I, Item 1 of this Quarterly Report for additional information). We currently expect our cash on hand, net cash provided by operating activities and other available sources of liquidity to be sufficient to meet our cash requirements over the next 12 months.

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On November 2, 2021, the Company entered into the Eighth Amendment to Sixth Amended and Restated Credit Agreement and Master Assignment, Resignation and Appointment Agreement and a Ninth Amendment to Sixth Amended and Restated Credit Agreement which effectively terminated the Company’s existing reserve based lending(“RBL”) relationship with commercial bank lenders who have traditionally provided the Company’s revolving credit facility and establishes, a $100 million first priority lien secured revolving facility with a borrowing base of $50 million provided by Calculus Lending, LLC, an affiliated company of W&T’s Chairman and Chief Executive Officer (the “Calculus Lending facility”). The Company has not had any borrowings under its RBL credit facility since the closing of the Mobile Bay Transaction in May of this year. The Company currently has no borrowings outstanding under the Company’s new Calculus Lending facility. See Financial Statements – Note 12 –Subsequent Events, under Part I, Item 1, of this Quarterly Report for additional information concerning these two recent amendments to the Company Credit Agreement and the Calculus Lending facility.

We are actively monitoring the debt capital markets, and we intend to seek financings with longer tenors and market based covenants to continue to provide working and potential acquisition capital as well as provide funding for refinancing of some or all of our Second Lien Notes. The terms of such financings, which may replace or augment our amended Company Credit Agreement and refinance some or all of our Second Lien Notes, may vary significantly from those under the amended Company Credit Agreement and our Second Lien Notes.

Sources and Uses of Cash


	Sources (Uses) of Cash (in thousands)
	Nine Months Ended September 30,
	2021		2020			Change
Operating activities	$	111,291	$	114,738	$	(3,447)
Investing activities		(12,406)		(41,709)		29,303
Financing activities		114,973		(48,930)		163,903

Operating activities. Net cash provided by operating activities decreased $3.4 million for the nine months ended September 30, 2021 compared to the corresponding period in 2020. This was primarily due to (i) cash derivative settlements and premium payments, which decreased operating cash flows by $39.6 million and $32.4 million, respectively, for the nine months ended September 30, 2021 compared to cash derivative settlement and premium payments, which increased operating cash flows $42.0 million and $0, respectively, for the nine months ended September 30, 2020; and (ii) asset retirement obligation settlements which decreased operating cash flows by $19.7 million for the nine months ended September 30, 2020 compared to $2.8 million for the nine months ended September 30, 2020; partially offset by (iii) increased oil, natural gas, and NGL revenues.

Our combined average realized sales price per Boe increased by 77.8% for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, which caused total revenues to increase $169.3 million. The increase to revenues was offset by an 11.6% decrease in total sales volumes during the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020, which caused revenues to decrease $29.3 million.

Investing activities. Net cash used in investing activities decreased $29.3 million for the nine months ended September 30, 2021 compared to the corresponding period in 2020. Our current year capital budget is weighted toward the second half of 2021. However, investing activities have been lower in the nine months ended September 30, 2021 compared to the same period in 2020 because investing activities in the prior year included $28.2 million in working capital changes associated with capital expenditures incurred in 2019 but paid during the nine months ended September 30, 2020.

Financing activities. Net cash provided by financing activities increased $163.9 million for the nine months ended September 30, 2021 compared to the corresponding period in 2020. Net cash provided by financing activities for the nine months ended September 30, 2021 was $115.0 million compared to net cash used in financing activities of $48.9

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million for the nine months ended September 30, 2020. The net cash provided for the nine months ended September 30, 2021 included the proceeds from the Term Loan of $208.2 million, offset by repayment of $80.0 million of borrowings under the Company Credit Agreement. The net cash used in financing activities for the nine months ended September 30, 2020 included repayment of $25.0 million of borrowings under the Credit Agreement and $23.9 million to purchase $72.5 million principal of Senior Second Lien Notes on the open market.

Derivative Financial Instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas. During the nine months ended September 30, 2021 we entered into derivative contracts for crude oil and natural gas for a portion of our future production. Subsequent to September 30, 2021, we executed the unwinding of two natural gas collar contracts for $5.2 million. See Financial Statements – Note 7 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information about our derivative activities. The following table summarizes the historical results of our hedging activities:


	Three Months Ended				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2021		2020		2021		2020
Crude Oil ($/Bbl):
Average realized sales price, before the effects of derivative settlements	$	68.57	$	41.81	$	63.07	$	37.17
Effects of realized commodity derivatives		(12.55)		2.44		(8.72)		7.97
Average realized sales price, including realized commodity derivative	$	56.02	$	44.25	$	54.35	$	45.14
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements	$	4.31	$	1.94	$	3.40	$	1.88
Effects of realized commodity derivatives		(1.57)		(0.08)		(0.61)		(0.02)
Average realized sales price, including realized commodity derivative	$	2.74	$	1.86	$	2.79	$	1.86

Asset Retirement Obligations. Each quarter, we review and revise our ARO estimates. Our ARO estimates as of September 30, 2021 and December 31, 2020 were $407.9 million and $392.7 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 2020 Annual Report for additional information.

Income Taxes. We do not expect to make any significant income tax payments during 2021, and we did not have any outstanding current income taxes receivable as of September 30, 2021. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

Employee Retention Credit. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the nine months ended September 30, 2021 which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.

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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. The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):


	Nine Months Ended September 30,
	2021		2020

	(In thousands)
Exploration (1)	$	5,850	$	1,754
Development (1)		5,660		9,187
Magnolia acquisition and Mobile Bay transaction		754		456
Seismic and other		3,761		2,013
Investments in oil and gas property/equipment – accrual basis	$	16,025	$	13,410

(1)

Reported geographically in the subsequent table.

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


	Nine Months Ended September 30,
	2021		2020

	(In thousands)

Conventional shelf	$	4,469	$	8,611
Deepwater		7,041		2,330
Exploration and development capital expenditures – accrual basis	$	11,510	$	10,941

Our exploration and development spending increased $0.6 million compared to prior year, with the majority of that increase occurring the third quarter. In 2021, our capital budget is weighted toward the second half of the year. Excluding acquisitions and plugging and abandonment expenditures, we are currently estimating capital expenditures to range from $30.0 million to $60.0 million for 2021 and ARO spending to range from $25.0 million to $35.0 million.

The capital expenditures are included within Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheets and recorded on an incurred basis. The capital expenditures reported within the Investing section of the Condensed Consolidated Statements of Cash Flows include adjustments to report cash payments related to capital expenditures. Our capital expenditures for the nine months ended September 30, 2021 were financed by cash flow from operations and cash on hand.

Drilling Activity

We did not drill any wells in the nine months ended September 30, 2021. During the nine months ended September 30, 2020, we drilled the East Cameron 349 B-1 well (Cota) to target depth. We expect to complete the well in the fourth quarter of 2021 and we expect initial production to commence late in the fourth quarter of 2021, subject to completion of certain infrastructure. The Cota well is in the Monza Joint Venture Drilling Program. See Financial Statements – Note 5 –Joint Venture Drilling Program under Part I, Item 1 of this Form 10-Q for additional information.

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Debt

Term Loan. As of September 30, 2021, we had $203.2 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments commencing September 30, 2021, bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than Borrowers and the subsidiary that owns the equity of Borrowers, and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of Borrowers (the Mobile Bay Properties). See Financial Statements – Note 2 –Debt under Part I, Item 1 of this Quarterly Report for additional information.

Company Credit Agreement. As of September 30, 2021, we had no borrowings outstanding under the Company Credit Agreement and letters of credit issued under the Company Credit Agreement were $4.4 million. During the nine months ended September 30, 2021, we repaid $80.0 million of borrowings.

On November 2, 2021, the Company entered into two amendments to the Company Credit Agreement which effectively terminated the Company’s existing RBL relationship with commercial bank lenders who have traditionally provided the Company’s revolving credit facility and establishes the Calculus Lending facility. The Company has not had any borrowings under the RBL credit facility since the closing of the Mobile Bay Transaction in May of this year. The Company currently has no borrowings outstanding under the new Calculus Lending facility. The Calculus Lending facility matures on April 30, 2022. Generally, we must be in compliance with the covenants in our Calculus Lending facility agreement in order to access borrowings. See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Quarterly Report for additional information concerning these recent two amendments to the Company Credit Agreement and the Calculus Lending facility.

Senior Second Lien Notes. As of September 30, 2021, we had outstanding $552.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that mature on November 1, 2023. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Company Credit Agreement. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

Debt Covenants. The Term Loan, Company 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 Subsidiary Credit Agreement, Company Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Term Loan, Company Credit Agreement and the Senior Second Lien Notes indenture as of and for the period ended September 30, 2021. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

Paycheck Protection Program. On April 15, 2020, the Company received $8.4 million under the PPP. During the eligible period, the Company incurred eligible expenses in excess of the amount received. The PPP funds are structured as a loan, but the funds can be forgiven by the SBA. The Company submitted an application for forgiveness to the SBA on August 20, 2020, requesting that the PPP funds received be applied to specific covered and non-covered payroll costs. On June 11, 2021, we received notification that the SBA accepted our application and approved forgiveness of our PPP funds; therefore, we will not be required to repay the grant.

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Uncertainties

Bureau of Ocean Energy Management (“BOEM”) Matters. In order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurance that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. 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 historically requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity. 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 2021 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

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

Insurance Coverage

Insurance Coverage. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $17.5 million on the conventional shelf properties and $12.5 million on the deepwater properties. Included within the $162.5 million aggregate limit is total loss only coverage on our Mahogany platform, which has no retention. The operational and named windstorm coverages are effective for one year beginning June 1, 2021. 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, 2021 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 $35.0 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, 2021, and our Energy Package on June 1, 2021, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims. We do not carry business interruption insurance.

Contractual Obligations

As of September 30, 2021, there were no long-term drilling rig commitments. Except for scheduled utilization and our quarterly payments under the Term Loan (see Financial Statements – Note 2 – Debt under Part 1 of this Quarterly

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Report), other contractual obligations as of September 30, 2021 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 2020 Annual Report.

Critical Accounting Policies and Estimates

We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition and income taxes as critical accounting policies. These policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used.

There have been no changes to our critical accounting policies which are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our 2020 Annual Report. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1 of this Quarterly Report for additional information.

Recent Accounting Pronouncements

See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, of this Quarterly Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about the types of market risks for the nine months ended September 30, 2021 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our 2020 Annual Report. In addition, the information contained herein should be read in conjunction with the related disclosures in our 2020 Annual Report.

Item 4. Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO have each concluded that as of September 30, 2021, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended September 30, 2021, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the information set forth in this Quarterly Report, investors should carefully consider the risk factors and other cautionary statements included under Part I, Item 1A, Risk Factors, in our 2020 Annual Report, together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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 2020 Annual Report.

Item 5. Other Information

Subsequent to September 30, 2021, the Company entered into two amendments to the Company Credit Agreement.

On November 2, 2021, the Company entered into the Eighth Amendment to Sixth Amended and Restated Credit Agreement and Master Assignment, Resignation and Appointment Agreement, among Toronto Dominion (Texas) LLC, as existing Administrative Agent, (ii) Alter Domus (US) LLC, as successor Administrative Agent (iii) W&T Offshore, Inc., as Borrower, (iv) each Borrower guarantor subsidiary and (v) BP Energy Company, as the sole Lender (the “Eighth Amendment”), which effectively terminated the Company’s reserve based lending relationship with commercial bank lenders who have traditionally provided the Company’s secured revolving credit facility.

Also on November 2, 2021, the Company also entered into the Ninth Amendment to the Sixth Amended and Restated Credit Agreement by and among W&T Offshore, Inc., as the Borrower, the Borrower guarantor subsidiaries, Calculus Lending, LLC, as sole Lender, and Alter Domus (US) LLC, as Administrative Agent for the lenders (the “Ninth Amendment”), which establishes a short-term $100 million first priority lien secured revolving facility with a borrowing base of $50 million.

See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Quarterly Report for additional information concerning the Eighth and Ninth Amendments and the Calculus Lending facility.

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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		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))

3.3		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))

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

10.1*		Eighth Amendment to Sixth Amended and Restated Credit Agreement and Master Assignment, Resignation and Appointment Agreement, dated effective as of November 2, 2021.

10.2*		Ninth Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of November 2, 2021.

31.1*		Section 302 Certification of Chief Executive Officer

31.2*		Section 302 Certification of Chief Financial Officer

32.1*		Section 906 Certification of Chief Executive Officer and Chief Financial Officer

101.INS*		Inline XBRL Instance Document

101.SCH*		Inline XBRL Schema Document

101.CAL*		Inline XBRL Calculation Linkbase Document

101.DEF*		Inline XBRL Definition Linkbase Document

101.LAB*		Inline XBRL Label Linkbase Document

101.PRE*		Inline XBRL Presentation Linkbase Document

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

*	Filed or furnished herewith.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 3, 2021.


	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