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 ~~March 31,~~September 30, 2021 and December 31, 2020	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	3
	Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended ~~March 31,~~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	20 24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30 38
Item 4.	Controls and Procedures	30
		38

PART II – OTHER INFORMATION		39
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 1.5.	Other Information	39
Item 6.	~~Legal Proceedings~~Exhibits	31 40
~~Item 1A.~~		~~Risk Factors~~	31
~~Item 6.~~	~~Exhibits~~	32

SIGNATURE		33 41

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; NaN 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

March 31,

December 31,

2021

2020

Assets

Current assets:

Cash and cash equivalents
$ 53,359 $ 43,726
Receivables:

Oil and natural gas sales
49,931 38,830
Joint interest, net
15,234 10,840
Total receivables
65,165 49,670
Prepaid expenses and other assets (Note 1)
15,350 13,832
Total current assets
133,874 107,228

Oil and natural gas properties and other, net – at cost: (Note 1)
668,969 686,878

Restricted deposits for asset retirement obligations
29,699 29,675
Deferred income taxes
94,535 94,331
Other assets (Note 1)
22,613 22,470
Total assets
$ 949,690 $ 940,582
Liabilities and Shareholders’ Deficit

Current liabilities:

Accounts payable
$ 43,714 $ 48,612
Undistributed oil and natural gas proceeds
25,338 19,167
Asset retirement obligations
26,402 17,188
Accrued liabilities (Note 1)
64,420 29,880
Income tax payable
153 153
Total current liabilities
160,027 115,000
Long-term debt: (Note 2)

Principal
600,460 632,460
Unamortized debt issuance costs
(6,622 ) (7,174 )
Long-term debt, net
593,838 625,286

Asset retirement obligations, less current portion
372,495 375,516
Other liabilities (Note 1)
31,780 32,938
Deferred income taxes
128 128
Commitments and contingencies (Note 10) — —
Shareholders’ deficit:

Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued at March 31, 2021 and December 31, 2020
0 0
Common stock, $0.00001 par value; 200,000 shares authorized; 145,174 issued and 142,305 outstanding at March 31, 2021 and at December 31, 2020
1 1
Additional paid-in capital
550,793 550,339
Retained deficit
(735,205 ) (734,459 )
Treasury stock, at cost; 2,869 shares at March 31, 2021 and December 31, 2020
(24,167 ) (24,167 )
Total shareholders’ deficit
(208,578 ) (208,286 )
Total liabilities and shareholders’ deficit
$ 949,690 $ 940,582

See Notes to Condensed Consolidated Financial Statements

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	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		0		0		0		(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

Three Months Ended March 31,

2021

2020

Revenues:

Oil
$ 78,140 $ 84,650
NGLs
9,359 6,452
Natural gas
36,209 29,300
Other
1,939 3,726
Total revenues
125,647 124,128
Operating costs and expenses:

Lease operating expenses
42,357 54,775
Production taxes
1,996 916
Gathering and transportation
4,319 5,449
Depreciation, depletion, amortization and accretion
26,637 39,126
General and administrative expenses
10,712 13,963
Derivative loss (gain)
24,578 (61,912 )
Total costs and expenses
110,599 52,317
Operating income
15,048 71,811
Interest expense, net
15,034 17,110
Gain on debt transactions
0 (18,501 )
Other expense, net
963 723
(Loss) income before income tax (benefit) expense
(949 ) 72,479
Income tax (benefit) expense
(203 ) 6,499
Net (loss) income
$ (746 ) $ 65,980
Basic and diluted (loss) earnings per common share
$ (0.01 ) $ 0.46

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

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	0				858		0	0		0		858
Stock Issued	0		0		0		0	0		0		0
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 Outstanding

Additional Paid-In

Retained

Treasury Stock

Total 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
— 0 1,048 0 — 0 1,048
Net income
— 0 0 65,980 — 0 65,980
Balances at March 31, 2020
141,669 $ 1 $ 548,098 $ (706,269 ) 2,869 $ (24,167 ) $ (182,337 )


	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	0		0		1,075		0	0		0		1,075
Stock Issued	109		0		0		0	0		0		0
Net loss	0		0		0		(13,339)	0		0		(13,339)
Balances at September 30, 2020	141,778	$	1	$	550,192	$	(725,512)	2,869	$	(24,167)	$	(199,486)

Common Stock Outstanding

Additional Paid-In

Retained

Treasury Stock

Total Shareholders’

Shares

Value

Capital

Deficit

Shares

Value

Deficit

Balances at December 31, 2020
142,305 $ 1 $ 550,339 $ (734,459 ) 2,869 $ (24,167 ) $ (208,286 )
Share-based compensation
— 0 454 0 — 0 454
Stock Issued
0 0 0 0 0 0 0
Net loss
— 0 0 (746 ) — 0 (746 )
Balances at March 31, 2021
142,305 $ 1 $ 550,793 $ (735,205 ) 2,869 $ (24,167 ) $ (208,578 )


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

Table of Contents

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		0		(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		0		(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		0		(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

Three Months Ended March 31,

2021

2020

Operating activities:

Net (loss) income
$ (746 ) $ 65,980
Adjustments to reconcile net (loss) income to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion
26,637 39,126
Amortization of debt items and other items
2,019 1,625
Share-based compensation
454 1,048
Derivative loss (gain)
24,578 (61,912 )
Derivative cash (payments) receipts, net
(4,604 ) 4,404
Gain on debt transactions
0 (18,501 )
Deferred income taxes
(203 ) 6,499
Changes in operating assets and liabilities:

Oil and natural gas receivables
(11,101 ) 21,954
Joint interest receivables
(4,394 ) 7,123
Prepaid expenses and other assets
(7,575 ) 11,011
Asset retirement obligation settlements
(962 ) (249 )
Cash advances from JV partners
(1,023 ) 13,006
Accounts payable, accrued liabilities and other
21,884 (6,790 )
Net cash provided by operating activities
44,964 84,324
Investing activities:

Investment in oil and natural gas properties and equipment
(1,575 ) (9,542 )
Changes in operating assets and liabilities associated with investing activities
(1,758 ) (24,033 )
Acquisition of property interests
0 (2,002 )
Purchases of furniture, fixtures and other
2 (70 )
Net cash used in investing activities
(3,331 ) (35,647 )
Financing activities:

Repayments on credit facility
(32,000 ) (25,000 )
Purchase of Senior Second Lien Notes
0 (8,536 )
Net cash used in financing activities
(32,000 ) (33,536 )
Increase in cash and cash equivalents
9,633 15,141
Cash and cash equivalents, beginning of period
43,726 32,433
Cash and cash equivalents, end of period
$ 53,359 $ 47,574

See Notes to Condensed Consolidated Financial Statements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)1. Basis of Presentation

1.	~~Basis of Presentation~~

Operations.W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Our interests in fields, leases, structures and equipment are primarily owned by the Company and its 100% owned ~~subsidiary,~~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 4.5.

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-K10-K for the year ended December 31, ~~2020~~.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,~~ 2019-12, Income Taxes (Topic ~~740~~)740): Simplifying the Accounting for Income Taxes ("ASU ~~2019~~-~~12"~~2019-12"). ASU ~~2019~~-122019-12 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~~-122019-12 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.

~~Table of Contents~~

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

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"~~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 ~~three~~nine months ended ~~March 31,~~September 30, 2021 which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.

Table of Contents

Credit Risk and Allowance for Credit Losses.Our revenue ~~has been~~is concentrated in certain major oil and gas companies. For the ~~three~~nine months ended ~~March 31,~~September 30, 2021,, and the year ended December 31, 2020,~~, approximately 67%~~ approximately 61% and 62%, respectively, of our revenue was from 3 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~~10 companies. A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and forecasts of future economic conditions. Our maximum exposure at any time would be the receivable balance. The receivables ~~Joint~~related to joint interest ~~and other, net~~,billings are reported on the Condensed Consolidated Balance Sheets ~~are reduced for~~net of the allowance for credit losses. The allowance for credit losses was ~~$9.1~~$9.2 million as of ~~March 31,~~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):

March 31, 2021

December 31, 2020

Derivatives - current (1)
$ 2,701 $ 2,752
Unamortized insurance/bond premiums
5,163 4,717
Prepaid deposits related to royalties
4,536 4,473
Prepayment to vendors
1,966 1,429
Other
984 461
Prepaid expenses and other assets
$ 15,350 $ 13,832

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)⁽¹⁾
^{Includes closed contracts which have not yet settled.}
Oil and Natural Gas Properties and Other, ~~Net~~ ~~– At Cost.~~ 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

March 31, 2021

December 31, 2020

Oil and natural gas properties and equipment, at cost
$ 8,570,371 $ 8,567,509
Furniture, fixtures and other
20,845 20,847
Total property and equipment
8,591,216 8,588,356
Less: Accumulated depreciation, depletion, amortization and impairment
7,922,247 7,901,478
Oil and natural gas properties and other, net
$ 668,969 $ 686,878
6

~~Table of Contents~~
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Other Assets (long-term). The major categories are presented in the following table (in thousands):

September 30, 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

0

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

March 31, 2021

December 31, 2020

Right-of-Use assets
$ 11,218 $ 11,509
Unamortized debt issuance costs
1,591 2,094
Investment in White Cap, LLC
2,872 2,699
Unamortized brokerage fee for Monza
0 626
Proportional consolidation of Monza's other assets (Note 4)
4,073 1,782
Derivatives
1,731 2,762
Other
1,128 998
Total other assets (long-term)
$ 22,613 $ 22,470

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

March 31, 2021

December 31, 2020

September 30, 2021

December 31, 2020
Accrued interest
$ 25,420 $ 10,389

$
25,693

$
10,389
Accrued salaries/payroll taxes/benefits
3,902 4,009

7,604

4,009
Litigation accruals
530 436

530

436
Lease liability
484 394

845

394
Derivatives
32,703 13,620
Derivatives ⁽¹⁾

159,538

13,620
Other
1,381 1,032

2,276

1,032
Total accrued liabilities
$ 64,420 $ 29,880

$
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

March 31, 2021

December 31, 2020

Dispute related to royalty deductions
$ 5,247 $ 5,467
Derivatives
3,514 4,384
Lease liability
11,257 11,360
Black Elk escrow
11,103 11,103
Other
659 624
Total other liabilities (long-term)
$ 31,780 $ 32,938

7

~~Table of Contents~~
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)2.        Debt
2.
~~Long-Term Debt~~
The components of our ~~long-term~~ debt are presented in the following table (in thousands):

March 31, 2021

December 31, 2020

Credit Agreement borrowings
$ 48,000 $ 80,000

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

552,460

552,460
Unamortized debt issuance costs
(6,622 ) (7,174 )

(5,473)

(7,174)
Total Senior Second Lien Notes
545,838 545,286

546,987

545,286

Less current portion

(46,201)

—
Total long-term debt, net
$ 593,838 $ 625,286

$
696,171

$
625,286

Table of Contents

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~~
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 ~~“Credit~~“Company Credit Agreement”), which matures on October 18, 2022. On ~~January 6,~~May 19, 2021, we entered into a Waiver, Consent to Second Amendment to Intercreditor Agreement and ~~Fifth~~Sixth Amendment to Sixth Amended and Restated Credit Agreement (the ~~“Fifth~~“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.

Table of Contents

The primary terms and covenants associated with the Company Credit Agreement as of ~~March 31,~~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.~~ 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~~4 quarters.

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

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

~~Availability~~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 ~~is subject~~were released in connection with the transfer of such assets to ~~semi-annual redeterminations of our borrowing base and the next scheduled redetermination is in the spring of~~ ~~2021.~~ ~~Additional redeterminations~~ ~~may~~ ~~be requested at the discretion of either the lenders or the Company.~~ Borrowers. The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement.

~~The~~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.~~ property, excluding those liens released in the Mobile Bay Transaction as described above.

As of ~~March 31,~~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 ~~three~~nine months ended ~~March 31,~~September 30, 2021was ~~3.1%~~3.2%, w~~hic~~hwhich excludes debt issuance costs, commitment fees and other fees.

Subsequent to September 30, 2021, the Company entered into 2 amendments of its Company Credit Agreement which significantly revised its first lien secured revolving credit facility. See Note 12 – Subsequent Events for additional information.

~~Table of Contents~~

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

9.75% Senior Second Lien Notes Due 2023

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and mature on November 1, 2023, and are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”). The estimated annual effective interest rate on the Senior Second Lien Notes is ~~9.2%~~ 10.3%, whichwhich includes amortization of debt issuance costs. Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year.

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 ~~March 31, 2021~~.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 ~~March 31,~~September 30, 2021 and December 31, 2020.

Table of Contents

The Senior Second Lien Notes are secured by a ~~second~~~~-priority~~second-priority lien on all of our assets that are secured under the Company Credit ~~Agreement.~~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

~~Covenants~~

As of ~~March 31,~~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.

~~Table of Contents~~

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)3.        Fair Value Measurements

3.
~~Fair Value Measurements~~
Derivative Financial Instruments
We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our open derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. Our open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 6,7 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):

March 31, 2021

December 31, 2020

September 30, 2021

December 31, 2020
Assets:




Derivatives instruments - open contracts, current
$ 2,691 $ 2,705

$
45,901

$
2,705
Derivatives instruments - open contracts, long-term
1,731 2,762

44,920

2,762

Liabilities:




Derivatives instruments - open contracts, current
29,227 13,291

140,601

13,291
Derivatives instruments - open contracts, long-term
3,514 4,384

55,467

4,384

Table of Contents

Debt
~~Long-Term Debt~~
~~We believe~~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 ~~very active~~highly liquid market. The fair value of our ~~long-term~~ debt was classified as Level 2 within the valuation hierarchy. See Note 2 ~~Long-Term~~– Debt for additional information on our ~~long-term~~ debt.
The following table presents the net value and fair value of our long-term debt (in thousands):

March 31, 2021

December 31, 2020

Net Value

Fair Value

Net Value

Fair Value


September 30, 2021

December 31, 2020

Net Value

Fair Value

Net Value

Fair Value
Liabilities:








Credit Agreement
$ 48,000 $ 48,000 $ 80,000 $ 80,000
Term Loan

$
195,385

$
199,615

$
—

$
—
Company Credit Agreement

—

—

80,000

80,000
Senior Second Lien Notes
545,838 490,087 545,286 393,352

546,987

524,997

545,286

393,352
Total 593,838 538,087 625,286 473,352

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.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)5. Joint Venture Drilling Program

4.	~~Joint Venture Drilling Program~~

In March 2018, W&T and ~~two~~2 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~~&T’s commitment to fund its retained interest in Monza projects held outside of Monza, are $361.4 million. W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our retained working interest in the Monza projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board.

The members of Monza are ~~made up of~~ ~~third~~~~-party~~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~~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 ~~March 31,~~September 30, 2021,, ~~nine~~ 9 wells have been ~~completed.~~completed since the inception of the Joint Venture Drilling Program. In 2020,~~one~~ 1 well was drilled to target depth, which we expect to be completed in the ~~second~~fourth quarter of 2021 and we expect production to commence late in the fourth quarter of 2021. W&T is the operator for ~~seven~~7 of the ~~nine~~9 wells completed through ~~March 31, 2021~~.

September 30, 2021.

Through ~~March 31,~~September 30, 2021,, members of Monza made partner capital ~~contributions,~~contributions, including our contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling ~~$71.5~~$85.5 million. Our net contribution to Monza, reduced by distributions received, as of ~~March 31,~~September 30, 2021 was ~~$53.0~~$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 ~~March 31,~~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~~beneficiary of Monza. As of ~~March 31,~~September 30, 2021,, in the Condensed Consolidated Balance Sheet, we recorded ~~$8.0~~$5.1 million, net, in Oil and natural gas properties and other, net, ~~$4.1~~$3.0 million in Other assets, ~~$0.2~~$0.3 million in Asset Retirement Obligations ("ARO") and ~~$1.6~~$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 ~~three~~nine months ended ~~March 31,~~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 ~~March 31,~~September 30, 2021 and December 31, 2020 were ~~$6.3~~$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 ~~three~~nine months ended ~~March 31,~~September 30, 2021,, in the Condensed Consolidated Statement of Operations, we recorded ~~$2.5~~$8.7 million in Total revenues and ~~$3.4~~$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.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)6. Asset Retirement Obligations
5.
~~Asset Retirement Obligations~~

Our ARO represent the estimated present value of the amount incurred to plug, abandon and remediate our properties at the end of their productive lives.
A summary of the changes to our ARO is as follows (in thousands):

Balances, December 31, 2020
$ 392,704

$
392,704
Liabilities settled
(962 )

(19,744)
Accretion of discount
5,868

17,368
Liabilities incurred and assumed through acquisition

417
Revisions of estimated liabilities
1,287

17,129
Balances, March 31, 2021
398,897
Balances, September 30, 2021

407,874
Less current portion
26,402

(27,545)
Long-term
$ 372,495

$
380,329

6.

7. Derivative Financial Instruments
~~Derivative Financial Instruments~~
Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our crude oil and natural gas. All of the ~~present~~current derivative counterparties are also lenders or affiliates of lenders participating in our Company Credit ~~Agreement.~~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”).

Table of Contents

The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts as of ~~March 31, 2021~~ ~~are presented in the following tables:~~September 30, 2021:
Crude Oil: Open Swap Contracts - Priced off WTI (NYMEX)

Period

Average Notional Quantity (Bbls/day) (1)

Notional Quantity (Bbls) (1)

Weighted Strike Price

Apr 2021 - Dec 2021
4,000 1,100,000 $ 42.06
Jan 2022 - Feb 2022
3,000 177,000 $ 42.98
Mar 2022 - May 2022
2,044 188,006 $ 42.33
Mar 2022 - Sept 2022
1,615 345,638 $ 54.53

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

$
—
12

~~Table of Contents~~
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Crude Oil: Open Collar Contracts - Priced off WTI (NYMEX)

Period

Average Notional Quantity (Bbls/day) (1)

Notional Quantity (Bbls) (1)

Put Option Weighted Strike Price (Bought)

Call Option Weighted Strike Price (Sold)

Apr 2021 - Dec 2021
200 55,000 $ 40.00 $ 54.90
Apr 2021 - Feb 2022
2,273 759,237 $ 38.50 $ 56.65
Mar 2022 - May 2022
2,000 184,000 $ 35.00 $ 48.50
Mar 2022 - Sept 2022
1,615 345,638 $ 45.00 $ 62.50
(1)⁽¹⁾
^{Bbls =– Barrels}
Natural Gas: Open Swap Contracts, Bought, Priced off Henry Hub (NYMEX)

Period

Average Notional Quantity (MMBtu/day) (2)

Notional Quantity (MMBtu) (2)

Strike Price

Apr 2021 - Dec 2021
10,000 2,750,000 $ 2.62
Jan 2022
20,000 620,000 $ 2.79
Feb 2022
30,000 840,000 $ 2.79
Mar 2022 - May 2022
10,544 970,075 $ 2.69
Mar 2022 - Sept 2022
10,628 2,274,311 $
2.44

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

Period

Average Notional Quantity (MMBtu/day) (2)

Notional Quantity (MMBtu) (2)

Strike Price

Nov 2020 - Dec. 2022
40,000 25,600,000 $ 3.00
Natural Gas: Open Collar Contracts, Priced off Henry Hub (NYMEX)

Period

Average Notional Quantity (MMBtu/day) (2)

Notional Quantity (MMBtu) (2)

Put Option Weighted Strike Price (Bought)

Call Option Weighted Strike Price (Sold)

Apr 2021 - Dec 2021
30,000 8,250,000 $ 2.18 $ 3.00
Apr 2021 - Dec. 2022
40,000 25,600,000 $ 1.83 $ 3.00
Jan 2022 - Feb 2022
30,000 1,770,000 $ 2.20 $ 4.50
Mar 2022 - May 2022
10,000 920,000 $ 2.25 $
3.40

(2)⁽²⁾
~~MMBtu =~~^{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).}
13

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

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

March 31,

December 31,

2021

2020

Prepaid expenses and other assets
$ 2,701 $ 2,752

September 30,

December 31,


2021

2020
Prepaid expenses and other current assets

$
52,327

$
2,752
Other assets (long-term)
1,731 2,762

44,920

2,762
Accrued liabilities
32,703 13,620

159,538

13,620
Other liabilities (long-term)
3,514 4,384

55,467

4,384

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

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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~~Condensed Consolidated Statements of Operations were as follows (in thousands):

Three Months Ended March 31,

2021

2020

Three Months Ended September 30,

Nine Months Ended September 30,


2021

2020

2021

2020
Realized loss (gain) $ 8,244 $ (9,392 )

$
30,026

$
(1,951)

$
53,627

$
(33,921)
Unrealized loss (gain) 16,334 (52,520 )

43,111

13,112

125,529

(1,416)
Derivative loss (gain)
$ 24,578 $ (61,912 )

$
73,137

$
11,161

$
179,156

$
(35,337)

Cash ~~receipts~~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):

Three Months Ended March 31,

2021

2020

Derivative cash (payments) receipts, net
$ (4,604 ) $ 4,404

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 2 natural gas collar contracts for $5.2 million. The following table reflects the contracted volumes and weighted average prices under the terms of these 2 contracts as of September 30, 2021:

14

~~Table~~

��

Average

Instrument

Daily

Total

Weighted

Weighted

Weighted
Period

Type

Volumes

Volumes

Strike Price

Put Price

Call Price

Natural Gas - Henry Hub (NYMEX)

(MMbtu)(2)

(MMbtu)(2)

($/MMbtu)(2)

($/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 ~~Contents~~
the open positions related to the 2 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)8.        Share-Based Awards and Cash-Based Awards
7.
Share-Based ~~Awards and Cash-Based Awards~~
Awards to ~~Employees.~~ 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.  ~~There were~~ no ~~RSUs granted during~~ ~~three~~ ~~months ended~~ ~~March 31, 2021~~ ~~and~~ ~~none~~ ~~were granted in~~ ~~2020.~~ ~~RSUs are a long-term compensation component, and are~~ Under the Plan, the Company may issue, subject to ~~satisfaction of certain predetermined performance criteria and adjustments at~~ the ~~end~~approval of the ~~applicable~~Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, performance ~~period based on the results achieved. In addition to share-based~~units or shares, cash awards, ~~the Company~~ ~~may~~ ~~grant to its employees cash-based incentive~~substitute awards ~~under the Plan, which~~ ~~may~~ ~~be used as short-term and long-term compensation components~~or any combination of the ~~awards,~~foregoing to employees, directors and ~~are subject to satisfaction of certain predetermined performance criteria.~~
consultants.
As of ~~March 31,~~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~~1-for-one basis when ~~RSUs~~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 ~~RSUs~~awards in stock or cash, or a combination of stock and cash. The Company expects to settle ~~RSUs~~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. NaN 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, ~~vesting generally occurs in~~ ~~December~~ ~~of the~~ ~~second~~ ~~year after the grant. Subject~~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 ~~March 31,~~September 30, 2021,~~, are eligible~~ vesting is expected to ~~vest in~~ ~~2021.~~occur as follows (subject to forfeitures):


Restricted

Shares
2021

731,095
2022

231,470
2023

231,470
2024

231,470
Total

1,425,505

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. The fair values for the RSUs granted were determined using the Company’s closing price on the grant date. We also estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.
All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.
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 ~~RSUs~~PSUs during the ~~three~~nine months ended ~~March 31,~~September 30, 2021 is as follows:

Restricted Stock Units

Weighted Average

Grant Date Fair

Units

Value Per Unit

Performance Share Units

Weighted

Average

Grant Date Fair

Units

Value Per Unit
Nonvested, December 31, 2020
763,688 $ 4.51

—

$
—
Granted

391,189

5.57
Vested

—

—
Forfeited
(19,880 ) 4.51

(4,890)

5.57
Nonvested, March 31, 2021
743,808 4.51
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
%

15

~~Table of Contents~~
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 ~~2020,~~the nine months ended September 30, 2021, and ~~0 grants were made~~ during the ~~three~~ ~~months~~year ended ~~March~~December 31, ~~2021~~.2020. During the second quarter of 2020, our shareholders ap~~proved~~approved increasing the shares available under the Director Compensation Plan by 500,000 shares. As of ~~March 31,~~September 30, 2021,, there were ~~473,244~~ 410,742 shares of common s~~tock~~stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available are reduced on a ~~one~~~~-to-~~~~one~~1-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. NaN forfeitures were estimated for the non-employee directors’ awards.
The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless otherwise approved by the Board of Directors. Restricted Shares cannot be sold, transferred or disposed of during the restricted period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such Restricted Shares, including the right to vote and receive dividends or other distributions paid with respect to the Restricted Shares.

~~There was~~ noTable of Contents

A summary of activity related to Restricted Shares during the ~~three~~nine months ended ~~March 31,~~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

~~For~~Subject to the satisfaction of the service conditions, the outstanding Restricted Shares issued to the non-employee directors as of ~~March 31,~~September 30, 2021~~, vesting is expected~~are eligible to ~~occur as follows (subject to any forfeitures):~~vest in 2022.

Restricted Shares

2021

138,676

2022

15,452

Total

154,128

Share-Based ~~Compensation.~~  Compensation Expense
Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations. ~~NaN share-based awards have been granted to date in~~ ~~2021~~ ~~under the Plan, and therefore, share-based compensation expense recorded during the~~ ~~three~~ ~~months ended~~ ~~March 31, 2021~~ ~~related to prior periods' grants.~~ The tax benefit related to compensation expense recognized under share-based payment arrangements was not meaningful and was minimal due to our income tax ~~situation.~~position. A summary of incentive compensation expense under share-based payment arrangements is as follows (in thousands):

Three Months Ended March 31,

2021

2020

Share-based compensation expense from:

Three Months Ended September 30,

Nine Months Ended September 30,


2021

2020

2021

2020
Restricted stock units
$ 338 $ 978

$
587

$
927

$
1,263

$
2,854
Performance share units

207

—

207

Restricted Shares
116 70

64

148

309

288
Total
$ 454 $ 1,048

$
858

$
1,075

$
1,779

$
3,142

16

~~Table of Contents~~
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Unrecognized Share-Based ~~Compensation.~~Compensation Expense
As of ~~March 31,~~September 30, 2021,, unrecognized share-based compensation expense related to our awards of RSUs, PSUs, and Restricted Shares wa~~s $0.9~~was $2.7 million, $1.6 million, and $0.1 million, respectively. Unrecognized share-based compensation expense will be recognized through ~~November 2021~~ December 2023 for RSUs, September 2023 for PSUs, and April 2022 for Restricted Shares.
Cash-Based Incentive ~~Compensation.~~Compensation
In addition to share-based compensation, both short-term and long-term cash-based incentive awards were granted under the Plan to ~~substantially~~ all eligible employees in ~~2019.~~No ~~cash-based incentive awards were granted in~~ ~~2020,~~ ~~and therefore, 0 cash-based incentive compensation expense for~~ ~~2020~~ ~~was recorded. The~~2021.

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Short-term Cash-Based Incentive CompensationThere are two components of the short-term cash-based incentive ~~awards, which are generally a short-term component of~~award granted during the ~~Plan, are typically performance-based awards consisting of~~ ~~one~~ ~~or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. In addition, the~~ ~~2019~~ cash-based incentive awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (terms as defined in the awards) for any fiscal quarter plus the ~~three~~ ~~preceding quarters to exceed defined levels measured over defined time periods for each cash-based incentive award. On~~ ~~February 15,~~ ~~2021~~, the Company received approval from the Compensation Committee of the Board of Directors for the payment of a discretionary cash bonus up to the amount of $7.6 million, subject to employment-based criteria. The Compensation Committee has ~~not~~ ~~yet made any other decisions regarding the potential awarding of incentive compensation under the Plan in~~ nine months ended September 30, 2021. ~~Expense is recognized over the service period once the business criteria, individual performance criteria and financial condition are met.~~
•● 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 ~~is payable~~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 ~~$3.5~~$7.6 million was recognized during the ~~three~~nine months ended ~~March 31,~~September 30, 2021, related to ~~the~~these awards.
●
•
~~For the~~ ~~2019~~The second short-term, cash-based ~~awards, a portion of the business~~award granted in June 2021 is subject to Company performance-based criteria and individual performance ~~criteria were achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over~~ ~~four~~ ~~consecutive quarters was achieved; therefore, incentive~~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 ~~over the~~ ~~January 2019~~ during three and nine months ended September 30, 2021, respectively, related to ~~February 2020~~ these awards.
NaN 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 ~~(the service period of the award). Payments were made in~~ ~~March 2020~~ ~~and are subject to all the terms of the~~ ~~2019~~ ~~Annual Incentive Award Agreement.~~(in 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 March 31,

2021

2020

Share-based compensation included in:

General and administrative expenses
$ 454 $ 1,048
Cash-based incentive compensation included in:

Lease operating expense (1)
839 849
General and administrative expenses (1)
2,682 3,631
Total charged to operating income
$ 3,975 $ 5,528

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)
(1)
Includes adjustments of accruals to actual payments.

17

~~Table of Contents~~

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)9.        Income Taxes
8.
~~Income Taxes~~
Tax ~~(Benefit) Expense~~Benefit and Tax ~~Rate.~~Rate Income tax ~~(benefit) expense~~benefit for the three months ended ~~March 31,~~September 30, 2021 and 2020 was ~~$(0.2) million~~$5.9 and ~~$6.5~~$21.1 million, respectively. For the ~~three~~nine months ended ~~March 31,~~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 ~~by the impact~~as a result of ~~state income taxes.~~adjustments in our valuation allowance on certain deferred tax assets. For the three and nine months ended ~~March 31,~~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)~~163(j). Our effective tax rate was ~~21.4%~~13.5% and 17.3% for the three and nine months ended ~~March 31,~~September 30, 2021, respectively, and ~~9.0%~~not meaningful for the three and nine months ended ~~March 31, 2020.~~  September 30, 2020, respectively.
Valuation ~~Allowance.~~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 ~~March 31,~~September 30, 2021 and December 31, 2020, our valuation allowance was ~~$22.0~~$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.~~Payments As of ~~March 31,~~September 30, 2021 and December 31, 2020, we did not have any material outstanding current income taxes receivable.~~As of~~ ~~March 31, 2020,~~ ~~we had current income taxes receivable of $1.9 million, which was received during the quarter ended~~ ~~June~~ ~~30,~~~~2020.~~ ~~The refund related primarily to a net operating loss carryback claim for~~ ~~2017~~ ~~that was carried back to prior years.~~ During the three months ended ~~March 31,~~September 30, 2021,~~and~~ ~~2020,~~ we did ~~not~~0t 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 ~~2017~~2018 through 2020 remain open to examination by the tax jurisdictions to which we are subject.

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10. Earnings Per Share

~~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 March 31,*
	*2021*			*2020*

						Three Months Ended September 30,				Nine Months Ended September 30,
						2021		2020		2021		2020
Net (loss) income	$	(746	)	$	65,980	$	(37,964)	$	(13,339)	$	(90,382)	$	46,737
Less portion allocated to nonvested shares		0			791		—		—		0		549
Net (loss) income allocated to common shares	$	(746	)	$	65,189	$	(37,964)	$	(13,339)	$	(90,382)	$	46,188
Weighted average common shares outstanding		142,151			141,546		142,297		141,624		142,231		141,589

Basic and diluted (loss) earnings per common share	$	(0.01	)	$	0.46	$	(0.27)	$	(0.09)	$	(0.64)	$	0.33

Shares excluded due to being anti-dilutive (weighted-average)		0			0		1,514		1,677		1,106		0

~~Table of Contents~~

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)11. Contingencies

~~10.~~

~~Contingencies~~

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which ultimately led to our posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the ~~IBLA~~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~~pre- and post-judgement interest, the ~~penal~~ sum of the bond posted is currently $8.2 million.

Royalties – “Unbundling” ~~Initiative.~~ 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,~~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 ~~March 31,~~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.

~~Notices~~Table of ~~Proposed~~ Contents

Civil Penalty ~~Assessment.~~Assessments In January 2021, we executed a Settlement Agreement with the Bureau of Safety and Environmental Enforcement (“BSEE”) which resolved ~~nine~~9 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. ~~During the~~ ~~three~~ ~~months ended~~ ~~March 31,~~In September 2021,, we ~~did~~ ~~not~~ ~~pay any civil penalties to BSEE~~paid $40,200 related to ~~newly~~an INC issued ~~INCs.~~ 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.~~ 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.

Table of Contents

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 4 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.

23
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
~~Forward-Looking Statements~~
The following discussion and analysis should be read in conjunction with our ~~accompanying~~ unaudited ~~condensed consolidated financial statements~~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.~~ 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 ~~following discussion contains forward-looking statements~~information in this report includes “forward-looking statements” within the meaning of ~~the Private Securities Litigation Reform Act of 1995,~~ 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 ~~involve~~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.~~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. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, 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, ~~on Form 10-K for the year ended December 31, 2020 and this Quarterly Report on Form 10-Q, Part II, Item 1A,~~ ~~Risk Factors~~, and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. ~~We assume no obligation, nor do~~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 ~~intend~~or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update ~~these~~any forward-looking ~~statements. Unless~~statements, all of which are expressly qualified by the ~~context requires otherwise, references~~statements in this section, to reflect events or circumstances after the date of this Quarterly ~~Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.~~
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 ~~March~~September 2021, we hold working interests in 42 offshore fields in federal and state waters ~~(40~~(41 fields producing and ~~2 fields~~1 field capable of producing, ~~with~~which include 34 fields in federal waters and 8 in state waters). We currently have under lease approximately ~~709,000~~611,000 gross acres ~~(503,000~~(414,000 net acres) spanning across the outer continental shelf ~~("OCS"~~(“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately ~~500,000~~8,000 gross acres in Alabama State waters, 416,000 gross acres on the conventional shelf and approximately ~~209,000~~186,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our ~~interest~~interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned ~~subsidiary,~~subsidiaries, Aquasition LLC, Aquasition II LLC, W & T Energy VI, LLC, a Delaware limited liability ~~company~~companies, and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements ~~and Supplementary Data~~ – Note ~~4 –~~5 Joint Venture Drilling Program under Part I, Item 1 in this ~~Form 10-Q.~~Quarterly Report.
24
Table of Contents
Recent Events
~~Reduced economic activity related to the ongoing COVID-19 pandemic has caused changes in energy demand and supply over the past year and will continue to affect these patterns in the future.~~ As COVID-19 vaccines have been more widely distributed, global economic activity is improving and commodity prices are currently atabove 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 ~~Form 10-Q~~Quarterly Report for additional information.
During the ~~first~~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 underFinancial Statements –Note 4 – Mobile Bay Transaction, under Part 1, Item 1, of this Quarterly Report.
Commencing in late August 2021, we ~~completed~~experienced a significant temporary shut-in and deferral of as much as approximately 80% of the ~~consolidation~~Company’s production in preparation for, and as a result of, the effects of Hurricane Ida. The majority of our ~~two gas processing plants~~impacted production was brought back online during September 2021. We expect our hurricane impacted production remaining shut in ~~Alabama. We estimate future cost savings~~or reduced on the date of ~~approximately $5 million per year related~~the filing of this report to be online by the ~~plant consolidation efforts.~~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.
20

~~Table of Contents~~
Oil and Natural Gas Production and Commodity Pricing
OurOur financial condition, cashcash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. The price of those commodities is affected by both domestic and international factors, including domestic production. Our production volumes for the ~~three~~nine months ended ~~March 31, 2021were~~September 30, 2021 were comprised of ~~38.6%~~36.3% crude oil and condensate, ~~11.0%~~10.5% NGLs and ~~50.4%~~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 ~~condensate~~ or NGLs. The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past. For the ~~three~~nine months ended March 31, 2021, revenues from the sale of crude oil and NGLs made up 69.6% of our total revenues compared to 73.4% for the three months ended March 31, 2020. For the three months ended March 31, 2021, our combined total production expressed in equivalent volumes on a daily basis was 25.9% lower than for the three months ended March 31, 2020, due to shut-ins of various properties related to well economics, the freeze in February 2021 primarily affecting the Mobile Bay area, and ongoing hurricane repairs; reservoir management of fields; and natural production declines. For the three months ended March 31,September 30, 2021, our total revenues were ~~1.2%~~55.8% higher than the ~~three~~nine months ended ~~March 31,~~September 30, 2020 due to higher realized prices for crude oil, NGLs and natural gas, ~~and~~which were partially offset by lower volumes. See Results of Operations ~~– Three~~–Nine Months Ended ~~March 31,~~September 30, 2021, Compared to the ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2020 in this Item 2 for additional information.

Our operating results are strongly influenced by the price of the commodities that we produce and sell. The price of those commodities is affected by both domestic and international factors, including domestic production. During the ~~three~~nine months ended ~~March 31,~~September 30, 2021, our average realized crude oil price was ~~$56.73~~$63.07 per barrel. This is an increase of ~~22.4%~~69.7% from our average realized crude oil price of ~~$46.33~~$37.17 per barrel during the ~~three~~nine months ended ~~March 31,~~September 30, 2020. Per the Energy Information Administration ("EIA"), crude oil prices using average ~~WTI~~West Texas Intermediate (“WTI”) daily spot pricing increased to ~~$58.09~~$65.05 per barrel during the ~~three~~nine months ended ~~March 31,~~September 30, 2021 compared to ~~$45.34~~$38.04 per barrel during the ~~three~~nine months ended ~~March 31,~~September 30, 2020 representing an increase of ~~28.1%~~71.0%. Crude oil prices have recovered to pre-pandemic levels from their April 2020 lows caused by the ongoing COVID-19 pandemic as the ~~vaccine has~~vaccines have been more widely distributed and economic activity has increased.
25
Table of Contents
Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary significantly by field. All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of Poseidon, LLS and HLS to WTI for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 averaged ($~~0.01)~~0.90), ~~$2.02,~~$1.70, and ~~$1.65~~$1.08 per barrel, respectively, and each average differential has ~~decreased in the range of $0.10 to $2.00~~changed ($0.68), ($0.68), and ($0.73) per barrel, respectively compared to the ~~three~~nine months ended ~~March 31, 2020.~~
September 30, 2021.
Our average realized price of natural gas of ~~$3.35~~$3.40 per Mcf for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 was ~~75.4%~~80.9% higher than the average realized price of ~~$1.91~~$1.88 per Mcf for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. The average Henry Hub ("HH") daily natural gas spot price of ~~$3.50~~$3.61 per Mcf for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 was ~~84.6%~~89.7% higher than the average HH natural gas price of ~~$1.90~~$1.94 per Mcf for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. Per the EIA, this increase was ~~due to~~caused by increased demand ~~from~~related to the ~~U.S. power sector~~increase in economic activity and is somewhat elevated by the much higher average price in February 2021 caused by much colder-than-normal temperatures across the ~~country during February 2021. Price effects in February 2021 were amplified because the rise in demand occurred amid a drop in natural gas production due to well freeze-offs.~~ country.
Our average realized price of NGLs of ~~$ 23.88~~$27.51 per barrel for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 was ~~83.2%~~181.3% higher than the average realized price of ~~$13.03~~$9.78 per barrel for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the ~~three~~nine months ended ~~March 31,~~September 30, 2021 compared to the ~~three~~nine months ended ~~March 31,~~September 30, 2020, average prices for domestic ethane increased by ~~72%~~53.7% and average domestic propane prices increased by ~~141%~~128.9% as measured using a price index for Mount Belvieu. The average prices for other domestic NGLs components increased from ~~43%~~95.5% to ~~65%~~106.2% for the ~~three~~nine months ended ~~March 31,~~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. ~~Per the EIA, propane prices increased as a result of increased demand during the colder weather in February 2021.~~
According to Baker Hughes, the number of working rigs drilling for oil and natural gas ~~on land~~ in the U.S. as reported in their ~~April 16,~~October 15, 2021 report was ~~lower~~higher than a year ago, ~~decreasing~~increasing to ~~439~~543 rigs compared to ~~529~~282 rigs a year ago. The oil rig count ~~decreased~~increased to ~~344~~445 rigs compared to ~~438~~205 rigs a year ago and the gas and miscellaneous rigs increased ~~slightly~~ to 9598 rigs from 9177 a year ago. In the Gulf of Mexico, the number of working rigs was 12 rigs ~~(all oil)~~ compared to ~~17 (all oil)~~14 a year ago.
26

Table of Contents

Results of Operations

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

Three Months Ended September 30,

Nine Months Ended September 30,


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)

Three Months Ended March 31,

2021

2020

Change

%

(In thousands, except percentages and per share data)

Financial:

Revenues:

Oil
$ 78,140 $ 84,650 $ (6,510 ) (7.7 )%
NGLs
9,359 6,452 2,907 45.1 %
Natural gas
36,209 29,300 6,909 23.6 %
Other
1,939 3,726 (1,787 ) (48.0 )%
Total revenues
125,647 124,128 1,519 1.2 %
Operating costs and expenses:

Lease operating expenses
42,357 54,775 (12,418 ) (22.7 )%
Production taxes
1,996 916 1,080 117.9 %
Gathering and transportation
4,319 5,449 (1,130 ) (20.7 )%
Depreciation, depletion, amortization and accretion
26,637 39,126 (12,489 ) (31.9 )%
General and administrative expenses
10,712 13,963 (3,251 ) (23.3 )%
Derivative loss (gain)
24,578 (61,912 ) 86,490 NM
Total costs and expenses
110,599 52,317 58,282 111.4 %
Operating income
15,048 71,811 (56,763 ) NM
Interest expense, net
15,034 17,110 (2,076 ) (12.1 )%
Gain on debt transactions
— (18,501 ) 18,501 NM
Other expense, net
963 723 240 33.2 %
(Loss) income before income tax (benefit) expense (949 ) 72,479 (73,428 ) (101.3 )%
Income tax (benefit) expense
(203 ) 6,499 (6,702 ) NM
Net (loss) income
$ (746 ) $ 65,980 $ (66,726 ) NM
Basic and diluted (loss) earnings per common share
$ (0.01 ) $ 0.46 $ (0.47 ) NM
~~NM – not meaningful~~

Table of Contents

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

Three Months Ended March 31,

2021

2020

Change

%

Operating: (1) (2)

Net sales:

Oil (MBbls)
1,377 1,827 (450 ) (24.6 )%
NGLs (MBbls)
392 495 (103 ) (20.8 )%
Natural gas (MMcf)
10,799 15,307 (4,508 ) (29.5 )%
Total oil equivalent (MBoe)
3,569 4,873 (1,304 ) (26.8 )%

Average daily equivalent sales (Boe/day)
39,657 53,553 (13,896 ) (25.9 )%
Average realized sales prices:

Oil ($/Bbl) $ 56.73 $ 46.33 $ 10.40 22.4 %
NGLs ($/Bbl) 23.88 13.03 10.85 83.3 %
Natural gas ($/Mcf) 3.35 1.91 1.44 75.4 %
Oil equivalent ($/Boe) 34.66 24.71 9.95 40.3 %
Oil equivalent ($/Boe), including realized commodity derivatives) 32.35 26.63 5.71 21.4 %

Average per Boe ($/Boe):

Lease operating expenses $ 11.87 $ 11.24 $ 0.63 5.6 %
Gathering and transportation 1.21 1.12 0.09 8.0 %
Production costs 13.08 12.36 0.72 5.8 %
Production taxes 0.56 0.19 0.37 194.7 %
DD&A 7.46 8.03 (0.57 ) (7.1 )%
G&A expenses 3.00 2.87 0.13 4.5 %
Operating costs $ 24.10 $ 23.45 $ 0.65 2.8 %
⁽¹⁾
^{The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.}
⁽²⁾
~~(2)~~
^{Some average figures and variance percentages 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

28

Table of Contents

Three Months Ended ~~March~~~~31,~~September 30, 2021Compared to the Three Months Ended ~~March~~~~31,~~September 30, 2020

Due to the volatility in crude oil prices and to a lesser extent, volatility in prices for natural gas and NGL, the results of the three months ended March 31, 2021 may not be indicative of future periods. See “Liquidity and Capital Resources – Liquidity Overview” below for additional information.

Revenues. Total revenues increased $1.5 million, or 1.2%, to $125.6 million for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. Oil revenues decreased $6.5 million, or 7.7%, NGLs revenues increased $2.9 million, or 45.1%, natural gas revenues increased $6.9 million, or 23.6%, and other revenues decreased $1.8 million. The ~~decrease~~increase in oil revenues was attributable to ~~a decrease in sales volumes of 24.6%, partially offset by 22.4%~~an increase in ~~the~~ average realized sales price per Bbl to ~~$56.73 per barrel~~$68.57 from $41.81 for the three months ended ~~March 31,~~September 30, 2021 ~~from $46.33 per barrel~~and 2020, respectively. This was partially offset by a 2.9% decrease in oil sales volumes for the three months ended ~~March 31, 2020~~September 30, 2021 as compared to the same period in the prior year. The increase in NGLs revenues was attributable to ~~a 83.3%~~an increase in the average realized sales price per Bbl to ~~$23.88 per barrel~~$32.46 from $10.99 for the three months ended ~~March 31,~~September 30, 2021 ~~from $13.03 per barrel for~~and 2020, respectively. This was partially offset by a 7.6% decrease in NGL sales volumes during the three months ended ~~March 31, 2020, partially offset by a 20.8% decrease~~September 30, 2021 as compared to the same period in ~~sales volumes.~~the prior year. The increase in natural gas revenues was attributable to ~~a 75.4%~~an increase in the average realized price to ~~$3.35~~$4.31 per Mcf from $1.94 per Mcf for the three months ended ~~March 31,~~September 30, 2021 ~~from $1.91~~and 2020, respectively, and a 5.9% increase in volumes.

Overall sales volumes increased 1.1% on a Boe per ~~Mcf~~day basis for the three months ended ~~March 31, 2020, partially offset by a decrease in sales volumes of 29.5%. Overall, sales volumes decreased 25.9% on a Boe/day basis due~~September 30, 2021 compared to ~~shut-ins of various properties~~the three months ended September 30, 2020. Both periods included hurricane related todowntime as well ~~economics, the freeze in February 2021 primarily affecting the Mobile Bay area, and ongoing hurricane repairs; reservoir management of fields; and natural production declines. Our estimate of~~as other deferred production for various reasons. We estimate that deferred production reduced the produced volumes for the three months ended ~~March 31,~~September 30, 2021 ~~was~~by approximately ~~5,200~~9,400 Boe per day as compared to ~~3,600~~13,500 Boe per day for the three months ended ~~March 31, 2020 due~~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 ~~to the shut-ins at various properties.~~

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 ~~69.6%~~64.6% for the three months ended ~~March 31,~~September 30, 2021 compared to ~~73.4%~~70.4% for the three months ended ~~March 31,~~September 30, 2020. Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased to ~~42.1%~~47.3% for the three months ended ~~March 31,~~September 30, 2021 compared to ~~28.1%~~26.3% for the three months ended ~~March 31,~~September 30, 2020.

Lease operating expenses.Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, ~~decreased $12.4~~increased $3.1 million, or ~~22.7%, to $42.4 million~~8.4% for the three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020. On a component basis, base lease operating expenses decreased ~~$13.1~~$0.4 million, workover expenses ~~decreased $1.0~~increased $0.4 million, facilities maintenance expense ~~decreased $0.9~~increased $2.4 million, and hurricane repairs increased ~~$2.6~~$0.7 million.

Base lease operating expenses decreased primarily due to reduced expenses of $4.8 million at Mobile Bay and Fairway from successful cost cutting efforts; $4.3 million of reduced expenses related to fields that were no longer producing during the three months ended March 31, 2021 as compared to the same period in 2020; $1.8 million of reduceddecreased contract labor and ~~transportation costs and contract processing costs; $0.7 million of reduced insurance expenses; other cost reduction measures at various fields of $0.2 million; and credits to expense~~supplies due to ~~royalty adjustments~~the consolidation of ~~$1.3 million.~~our two gas processing plants in Alabama. The ~~decreases~~increases in workover expenses and facilities maintenance expense were due to ~~fewer~~an increase in projects undertaken. Lastly, we incurred ~~$2.6~~$0.7 million in expenses related to ~~hurricane~~ repairs ~~at various fields~~associated with Hurricane Ida during the three months ended ~~March 31,~~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 ~~$1.1 million to $2.0~~$1.3 million in the three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020 due to the increase in realized natural gas prices, ~~partially offset by decreased~~increased NGL prices, and to a lesser extent increased natural gas production volumes.
Gathering and transportation.Gathering and transportation expenses ~~decreased $1.1 million to $4.3~~increased $0.4 million for the three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020 primarily due to ~~decreased natural gas production volumes.~~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, ~~decreased~~increased to ~~$7.46~~$8.20 per Boe for the three months ended ~~March 31,~~September 30, 2021 from ~~$8.03~~$7.93 per Boe for the three months ended ~~March 31,~~September 30, 2020. On a nominal basis, DD&A ~~decreased 31.9% to $26.6~~increased 4.6%, or $1.2 million for the three months ended ~~March 31,~~September 30, 2021 ~~from $39.1 million for~~as compared to the three months ended ~~March 31,~~September 30, 2020. The ~~decline in the DD&A~~ rate per Boe ~~was driven by the decline in depreciable base~~increased year-over-year mostly as a result of ~~reduced capital spending over~~increases in the ~~past year~~ future development costs included in the depreciable base compared to the ~~relatively small change~~smaller increase in proved reserves over the ~~same~~comparable prior year period.

~~Table of Contents~~

General and administrative expenses (“G&A”). G&A ~~was $10.7~~decreased $1.1 million, or 7.5%, for the three months ended ~~March 31,~~September 30, 2021 ~~decreasing 23.3% from $14.0 million for~~as compared to the three months ended ~~March 31,~~September 30, 2020. The decrease was primarily due to ~~lower incentive compensation expenses and payroll expenses~~(i) a decrease in legal costs of ~~$2.4 million, the $2.1 million employee retention credit, and decreases~~$1.4 million; (ii) a decrease of ~~$1.0~~$0.9 million in other ~~miscellaneous~~ G&A ~~expense items; partially offset by decreased~~expenses, primarily related to lower rent expense; and (iii) an increase in overhead allocations to partners (credits to expense) of ~~$1.0 million, an increase in legal costs~~$0.3 million; partially offset by, (iv) increased incentive compensation expenses of ~~$0.8 million, and an increase in surety bond costs of $0.4 million associated with the additional working interest acquired at Mobile Bay in the fourth quarter of 2020. See~~ ~~Financial Statements~~ – ~~Note 1~~ – ~~Basis of Presentation~~ ~~under Part 1, Item 1~~, ~~and~~ ~~Liquidity and Capital Resources~~ in this Item 2 of this Form 10-Q for additional information on the employee retention credit. G&A on a per Boe basis was $3.00 per Boe for the three months ended March 31, 2021 compared to $2.87 per Boe for the three months ended March 31, 2020.

$1.5 million.

Derivative loss (gain). The three months ended ~~March 31,~~September 30, 2021 includes ~~a $24.6~~an $73.1 million derivative loss primarily due to increased crude oil prices during ~~March~~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 ~~December~~June 2020, which decreased the estimated fair value of open crude oil contracts between the two measurement dates. ~~The three months ended March 31, 2020 includes a $61.9 million derivative gain, primarily due to decreased crude~~Partially offsetting this decrease were realized gains from oil ~~prices during March 2020 as compared to~~collar contracts where the prevailing oil ~~prices during December 2019, which increased~~price was below the ~~estimated fair value of open crude oil contracts between the two measurement dates.~~

contract floor price.

Interest expense, net. Interest expense, net, was ~~$15.0~~$18.9 million and ~~$17.1~~$14.1 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively. The ~~decrease~~increase of $4.8 million in 2021 is primarily due to ~~lower~~interest expense on the principal ~~balances~~balance of the ~~Senior Second Lien Notes~~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 ~~partially offset by lower interest income.~~

during 2021.

Income tax ~~(benefit) expense.~~benefit. Our income tax ~~(benefit) expense~~benefit was ~~$(0.2)~~$5.9 million and ~~$6.5~~$21.1 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively. For the three months ended ~~March 31,~~September 30, 2021, our income tax benefit primarily differed from the statutory Federal tax rate ~~primarily by the impact~~as a result of ~~state income taxes.~~adjustments to our valuation allowance on certain deferred tax assets. For the three months ended ~~March 31,~~September 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the ~~Coronavirus Aid, Relief and Economic Security~~CARES Act ~~(“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 ~~21.4%~~13.5% for the three months ended ~~March 31,~~September 30, 2021 and ~~9.0%~~not meaningful for the three months ended ~~March 31,~~September 30, 2020.

As of ~~March 31,~~September 30, 2021, the valuation allowance on our deferred tax assets wa~~s $22.0~~was $24.1 million. WeWe continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 89 –Income Taxes under Part I, Item 1 of this ~~Form 10-Q~~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 ~~March 31,~~September 30, 2021, we had ~~$53.4~~$257.6 million cash on hand, ~~availability of $137.6 million~~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 ~~2022.~~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 ~~our~~other available sources of liquidity to be sufficient to meet our cash requirements over the next 12 months. ~~In the event~~

Table of ~~long-term market deterioration,~~Contents

On November 2, 2021, the Company ~~may need additional liquidity,~~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 ~~would require us to evaluate alternatives~~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 ~~take appropriate actions. The Company’s next~~establishes, a $100 million first priority lien secured revolving facility with a borrowing base ~~redetermination is scheduled~~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 ~~spring 2021.~~

additional information concerning these two recent amendments to the Company Credit Agreement and the Calculus Lending facility.

~~Given the relative strength in~~

We are actively monitoring the debt capital markets, ~~due~~and we intend to ~~higher oil and natural gas prices, we are looking into alternative financing options that have the possibility of providing~~seek financings with longer tenors ~~less restrictive~~and market based covenants to continue to provide working and ~~more reliable source~~potential acquisition capital as well as provide funding for refinancing of ~~capital for acquisitions without semi-annual redeterminations.~~

~~Table~~some or all of ~~Contents~~

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

~~Cash Flow and Working Capital.~~Operating activities. Net cash provided by operating activities decreased $3.4 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 compared to the corresponding period in 2020. This was primarily due to (i) cash derivative settlements and ~~2020 was $45.0~~premium payments, which decreased operating cash flows by $39.6 million and ~~$84.3~~$32.4 million, ~~respectively. Production volumes~~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 ~~26.8% measured on a Boe per day basis due~~$19.7 million for the nine months ended September 30, 2020 compared to ~~field shut-ins, reservoir management and~~$2.8 million for the nine months ended September 30, 2020; partially offset by (iii) increased oil, natural ~~declines, which caused revenues to decrease by $30.8 million. Oil, Natural~~ gas, and ~~NGLs had higher average realized sales prices per Boe.~~ NGL revenues.
Our combined average realized sales price per Boe increased by ~~40.3%~~77.8% for the ~~three~~nine months ended ~~March 31,~~September 30, 2021 compared to the ~~three~~nine months ended ~~March 31,~~September 30, 2020, which caused total revenues to increase ~~$34.1~~$169.3 million.
~~Other items affecting operating cash flows were higher receivable balances, which decreased operating cash flows~~The increase to revenues was offset by ~~$15.5 million for~~an 11.6% decrease in total sales volumes during the ~~three~~nine months ended ~~March 31,~~September 30, 2021 as compared to ~~a decrease of $29.1 million for~~ the ~~three~~nine months ended ~~March 31, 2020; decreased cash advance balances from joint venture partners,~~September 30, 2020, which ~~decreased operating cash flows by $1.0 million for the three months ended March 31, 2021 compared~~caused revenues to an increase of $13.0 million for the three months ended March 31, 2020; cash derivative payments, net which decreased operating cash flows $4.6 million for the three months ended March 31, 2021 compared to cash derivative receipts, net, which increased operating cash flows $4.4 million for the three months ended March 31, 2020; and a return of collateral related to a bond of $6.9 million which occurred during the three months ended March 31, 2020, with no such return occurring during the three months ended March 31, 2021. Other working capital items accounted for the remaining changes in net cash provided by operatingdecrease $29.3 million.
Investing activities.
Net cash used in investing activities ~~primarily represents our acquisitions~~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 ~~and investments in oil and gas properties and equipment. Net cash used in~~2021. However, investing activities ~~for~~have been lower in the ~~three~~nine months ended ~~March 31,~~September 30, 2021 ~~and~~compared to the same period in 2020 ~~was $3.3 million and $35.6 million, respectively. Net cash used in~~because investing activities ~~for~~in the ~~three months ended March 31, 2021~~prior year included ~~$1.8~~$28.2 million in working capital changes associated with capital expenditures incurred in ~~2020~~2019 but paid during the ~~three~~nine months ended ~~March 31, 2021. During~~September 30, 2020.
Financing activities. Net cash provided by financing activities increased $163.9 million for the ~~three~~nine months ended ~~March 31, 2020,~~September 30, 2021 compared to the ~~purchase~~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 ~~remaining 25% interest in~~nine months ended September 30, 2020. The net cash provided for the ~~Magnolia field was consummated for approximately $2.0 million.~~

~~Net~~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 ~~three~~nine months ended March 31, 2021 and 2020 was $32.0 million and $33.5 million, respectively. The net cash used for the three months ended March 31, 2021 included repayment of $32.0 million of borrowings under the Credit Agreement. The net cash used for the three months ended March 31,September 30, 2020 included repayment of $25.0 million of borrowings under the Credit Agreement and ~~$8.5~~$23.9 million to purchase ~~$27.5~~$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 ~~three~~nine months ended ~~March 31,~~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 67 – Derivative Financial Instruments under Part I, Item 1 of this ~~Form 10-Q~~Quarterly Report for additional ~~information.~~information about our derivative activities. The following table summarizes the historical results of our hedging activities:

	Three Months Ended
	March 31,			December 31,			March 31,
	2021			2020			2020

										Three Months Ended				Nine Months Ended
										September 30,		September 30,		September 30,		September 30,
										2021		2020		2021		2020
Crude Oil ($/Bbl):
Average realized sale price, before the effects of derivative settlements	$	56.73		$	42.84		$	46.33
Average realized sales price, before the effects of derivative settlements										$	68.57	$	41.81	$	63.07	$	37.17
Effects of realized commodity derivatives		(5.58	)		1.39			5.26			(12.55)		2.44		(8.72)		7.97
Average realized sales price, including realized commodity derivative	$	51.15		$	44.23		$	51.59		$	56.02	$	44.25	$	54.35	$	45.14
Natural Gas ($/Mcf)
Average realized sale price, before the effects of derivative settlements	$	3.35		$	2.63		$	1.91
Average realized sales price, before the effects of derivative settlements										$	4.31	$	1.94	$	3.40	$	1.88
Effects of realized commodity derivatives		(0.05	)		(0.17	)		(0.01	)		(1.57)		(0.08)		(0.61)		(0.02)
Average realized sales price, including realized commodity derivative	$	3.30		$	2.46		$	1.90		$	2.74	$	1.86	$	2.79	$	1.86

~~Table of Contents~~

Asset Retirement Obligations. Each quarter, we review and revise our ARO estimates. Our ARO estimates as of ~~March 31,~~September 30, 2021 and December 31, 2020 were ~~$398.9~~$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 ~~on Form 10-K for the year ended December 31, 2020~~ 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 ~~March 31,~~September 30, 2021. See Financial Statements – Note 89 –Income Taxes under Part I, Item 1 of this ~~Form 10-Q~~Quarterly Report for additional information.

~~Capital Expenditures~~

The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.

Our capital expenditures for the three months ended March 31, 2021 were $1.6 million compared to $11.5 million in the three months ended March 31, 2020. Overall capital expenditures decreased by $10.0 million in the current quarter compared to the prior year quarter, largely due to a slowdown in exploration and development spending in the current year. Our exploration and development spending decreased $8.8 million compared to prior year, primarily in the conventional shelf area due to the fact that our current year capital budget is weighted toward the second half of 2021. Other leasehold costs decreased $1.5 million during the three months ended March 31, 2021, compared to the prior year which included Magnolia and Mobile Bay acquisition costs, and seismic costs increased $0.4 million period over period. Excluding acquisitions and plugging and abandonment expenditures, we are currently estimating capital expenditures to range from $30 million to $60 million for 2021 and ARO spending to range from $17 million to $21 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. Net cash used in investing activities for the three months ended March 31, 2021 included $1.8 million in working capital changes associated with capital expenditures incurred in 2020 but paid during the three months ended March 31, 2021. Our capital expenditures for the three months ended March 31, 2021 were financed by cash flow from operations and cash on hand.

~~Drilling Activity~~

We did not drill any wells in the three months ended March 31, 2021. During the three months ended March 31, 2020, we drilled the East Cameron 349 B-1 well (Cota) to target depth. We expect initial production to commence in the fourth quarter of 2021, subject to completion of certain infrastructure and the level of commodity prices. The Cota well is in the Monza Joint Venture Drilling Program. See ~~Financial Statements – Note 4 –Joint Venture Drilling Program~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Table of Contents~~

~~Debt~~

~~Credit Agreement~~. As of March 31, 2021, borrowings outstanding under the Credit Agreement were $48.0 million and letters of credit issued under the Credit Agreement were $4.4 million. During the three months ended March 31, 2021, we repaid $32.0 million of borrowings. Availability under our Credit Agreement as of March 31, 2021 was $137.6 million. The Credit Agreement matures on October 18, 2022.

Availability under our Credit Agreement is subject to semi-annual redeterminations of our borrowing base, which was lowered from $215.0 million to $190.0 million following redetermination on January 6, 2021. The next redetermination is scheduled to occur in the spring of 2021. Generally, we must be in compliance with the covenants in our Credit Agreement in order to access borrowings under the Credit Agreement.

We currently have six lenders under our Credit Agreement. While we do not anticipate any difficulties in obtaining funding from any of these lenders as of the date of the filing of this Quarterly Report, any difficulties in obtaining funding from any of these lenders at this time, and any lack of or delay in funding by members of our banking group could negatively impact our liquidity position. See ~~Financial Statements – Note 2 –Long-Term Debt~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Senior Second Lien Notes.~~ As of March 31, 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 Credit Agreement. See ~~Financial Statements – Note 2 – Long-Term Debt~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Debt Covenants.~~ The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of and for the period ended March 31, 2021. See ~~Financial Statements – Note 2 – Long-Term Debt~~ ~~under Part I, Item 1 of this Form 10-Q 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 management of the Company believes the Company has met all the requirements for forgiveness of the total loan under the PPP. The Company submitted an application to the U.S. Small Business Administration ("SBA") on August 20, 2020, requesting that the PPP funds received be applied to specific covered and non-covered payroll costs. As of the date of this filing, we have not received a response from the SBA regarding the SBA's acceptance of our application. Management believes the Company has met all of the requirements under the PPP and will not be required to repay any portion of the funds received. Accordingly, no debt was recorded on the Consolidated Balance Sheet as of December 31, 2020. Should the SBA reject the Company's application of the PPP funds being applied to specific covered payroll and non-payroll costs, the Company may be required to repay all or a portion of the funds received under the PPP under an amortization schedule through April 2022 with an annual interest rate of 1%.

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 ~~three~~nine months ended ~~March 31,~~September 30, 2021 which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.

Table of Contents
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 ~~$30.0 million.~~$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, ~~2020.~~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 ~~we have bound~~ our Energy Package ~~for the year commencing~~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
~~Updated information on certain contractual obligations is provided in~~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 – ~~Long-Term~~ Debt ~~and~~ ~~Note 5 – Asset Retirement Obligations~~underPart ~~I, Item~~ 1 of this ~~Form 10-Q. As~~Quarterly
37
Table of ~~March 31, 2021, there were no drilling rig commitments. Except for scheduled utilization,~~Contents
Report), other contractual obligations as of ~~March 31,~~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 on Form 10-K for the year ended December 31, 2020.~~
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~~Table of Contents~~
Report.
Critical Accounting Policies and Estimates
~~Our significant~~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 on Form 10-K for the year ended December 31, 2020.~~Report. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1of this ~~Form 10-Q~~Quarterly Report for additional information.
Recent Accounting Pronouncements
See Financial Statements– Note 1– Basis of Presentation under Part 1, Item 1, of this ~~Form 10-Q.~~Quarterly Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about the types of market risks for the ~~three~~nine months ended ~~March 31,~~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 on Form 10-K for the year ended December 31, 2020.~~Report. In addition, the information contained herein should be read in conjunction with the related disclosures in our 2020 Annual ~~Report on Form 10-K for the year ended December 31, 2020.~~Report.

~~Commodity Price Risk.~~  Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines in the past have adversely affected our revenues, net cash provided by operating activities and profitability in the past and sustained current prices would have significant impacts on our business in the future. During the three months ended March 31, 2021, we entered into derivative crude oil and natural gas contracts related to a portion of our estimated future production. We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments. Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements. See ~~Financial Statements – Note 6 – Derivative Financial Instruments~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~
~~Interest Rate Risk.~~ As of March 31, 2021, we had $48.0 million borrowings outstanding under our Credit Agreement and were subject to the variable London Interbank Offered Rate and the Applicable Margin. We did not have any derivative instruments related to interest rates.
Item 4. Controls and Procedures
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO have each concluded that as of ~~March 31,~~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 ~~March 31,~~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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Table of Contents
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
See Financial Statements – Note 1011 –Contingencies under Part I Item 1 of this ~~Form 10-Q~~Quarterly Report for information on various legal proceedings to which we are a party or our properties are subject.

Item 1A. Risk Factors
~~Investors~~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, ~~on Form 10-K for the year ended December 31, 2020,~~ together with all of the other information included in this ~~document, in our Annual~~Quarterly Report, ~~on Form 10-K~~ and in our other public filings, ~~press releases~~which could materially affect our business, financial condition or future results. Additional risks and ~~discussions with~~uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our ~~management.~~
~~The potential effects of crude oil prices are discussed under Part I, Item 1A,~~ ~~Risk Factors,~~ ~~in our Annual Report on Form 10-K for the year ended December 31, 2020 and also discussed in the Part I, Item 2,~~ ~~Management~~’~~s Discussion and Analysis of Financial Condition~~ ~~and~~ ~~Results of Operations~~ ~~in the~~ ~~Overview~~ ~~section of this Form 10-Q.~~
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~~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 ~~Form 10-K~~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 ~~year ended December 31, 2020.~~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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Table of Contents

Item 6. Exhibits
Exhibit
Number
Description
3.1
Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414).)
3.2
~~Second Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed March 22, 2019 (File No. 001-32414))~~
~~3.3~~
Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))
~~3.4~~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))
~~10.1~~
3.4

~~Waiver, Consent to~~ Second ~~Amendment to Intercreditor Agreement and Fifth Amendment to Sixth~~ Amended and Restated ~~Credit Agreement, dated January 6, 2021, by and among~~Bylaws of W&T Offshore, Inc.~~, Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto~~ (Incorporated by reference to ~~exhibit 10.1~~Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed ~~on January 12, 2021~~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.~~Officer
31.2*
Section 302 Certification of Chief Financial ~~Officer.~~Officer
32.1*
Section 906 Certification of Chief Executive Officer and Chief Financial ~~Officer.~~Officer
101.INS*
Inline XBRL Instance ~~Document.~~Document
101.SCH*
Inline XBRL Schema ~~Document.~~Document
101.CAL*
Inline XBRL Calculation Linkbase ~~Document.~~Document
101.DEF*
Inline XBRL Definition Linkbase ~~Document.~~Document
101.LAB*
Inline XBRL Label Linkbase ~~Document.~~Document
101.PRE*
Inline XBRL Presentation Linkbase ~~Document.~~Document
~~104~~*
104*
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*
*Filed or furnished herewith.
~~Filed or furnished herewith.~~

32

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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 ~~May 6,~~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

33
41


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)


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

~~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~~	New York Stock Exchange