UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~June 30, 2021~~March 31, 2022

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

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, ~~INC~~.INC.

(Exact name of registrant as specified in its charter)


Texas		72-1121985
(State of incorporation)		(IRS Employer Identification Number)

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

(713) 626-8525

(Registrant’s telephone number, including area code)

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

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

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


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

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

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

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

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


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

As of ~~July 31, 2021~~April 30, 2022 there were ~~142,367,242~~143,012,124 shares outstanding of the registrant’s common stock, par value $0.00001.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I ~~–FINANCIAL~~– FINANCIAL INFORMATION		1

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021	1
	Condensed Consolidated Statements of Operations for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three ~~and Six~~ Months Ended ~~June 30, 2021~~March 31, 2022 and ~~2020~~2021	3
	Condensed Consolidated Statements of Cash Flows for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2022 and 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	2320
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3733
Item 4.	Controls and Procedures	3733

PART II – OTHER INFORMATION		3834
Item 1.	Legal Proceedings	3834
Item 1A.	Risk Factors	3834
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	35
Item 6.	Exhibits	3935

SIGNATURE		4136

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)


	June 30,		December 31,		March 31,		December 31,
	2021		2020		2022		2021
Assets
Current assets:
Cash and cash equivalents	$	209,148	$	43,726	$	215,475	$	245,799
Restricted cash						4,417		4,417
Receivables:
Oil and natural gas sales		50,220		38,830		92,693		54,919
Joint interest, net		11,750		10,840		14,221		9,745
Total receivables		61,970		49,670		106,914		64,664
Prepaid expenses and other assets (Note 1)		30,705		13,832		103,061		43,379
Total current assets		301,823		107,228		429,867		358,259

Oil and natural gas properties and other, net (Note 1)		657,657		686,878		731,692		665,252

Restricted deposits for asset retirement obligations		29,820		29,675		21,958		16,019
Deferred income taxes		107,337		94,331		103,238		102,505
Other assets (Note 1)		42,395		22,470		63,392		51,172
Total assets	$	1,139,032	$	940,582	$	1,350,147	$	1,193,207
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	54,624	$	48,612	$	69,195	$	67,409
Undistributed oil and natural gas proceeds		28,688		19,167		33,575		36,243
Advances from joint interest partners						6,521		15,072
Asset retirement obligations		23,888		17,188		67,274		56,419
Accrued liabilities (Note 1)		100,363		29,880		209,845		106,140
Current portion of long-term debt		36,771		—		39,881		42,960
Income tax payable		63		153		177		133
Total current liabilities		244,397		115,000		426,468		324,376
Long-term debt (Note 2)
Principal		730,689		632,460
Unamortized debt issuance costs		(12,773)		(7,174)
Long-term debt, net		717,916		625,286

Long-term debt, net (Note 2)						680,436		687,938
Asset retirement obligations, less current portion		380,115		375,516		407,682		368,076
Other liabilities (Note 1)		56,259		32,938		80,338		55,389
Deferred income taxes		128		128		113		113
Commitments and contingencies (Note 11)		—		—
Commitments and contingencies (Note 12)						4,495		4,495
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued at June 30, 2021 and December 31, 2020		—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 145,236 issued and 142,367 outstanding at June 30, 2021; 145,174 issued and 142,305 outstanding at December 31, 2020		1		1
Preferred stock, $0.00001 par value; 20,000 shares authorized; NaN issued at March 31, 2022 and December 31, 2021						—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 145,881 issued and 143,012 outstanding at March 31, 2022; 145,732 issued and 142,863 outstanding at December 31, 2021						1		1
Additional paid-in capital		551,260		550,339		553,175		552,923
Retained deficit		(786,877)		(734,459)		(778,394)		(775,937)
Treasury stock, at cost; 2,869 shares at June 30, 2021 and December 31, 2020		(24,167)		(24,167)
Treasury stock, at cost; 2,869 shares at March 31, 2022 and December 31, 2021						(24,167)		(24,167)
Total shareholders’ deficit		(259,783)		(208,286)		(249,385)		(247,180)
Total liabilities and shareholders’ deficit	$	1,139,032	$	940,582	$	1,350,147	$	1,193,207

See Notes to Condensed Consolidated Financial ~~Statements~~

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 June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2021		2020		2021		2020		2022		2021
Revenues:
Oil	$	88,013	$	30,645	$	166,153	$	115,295	$	122,702	$	78,140
NGLs		8,833		1,917		18,193		8,369		13,820		9,359
Natural gas		32,470		21,364		68,679		50,664		51,366		36,209
Other		3,512		1,315		5,451		5,041		3,116		1,939
Total revenues		132,828		55,241		258,476		179,369		191,004		125,647
Operating costs and expenses:
Operating expenses:
Lease operating expenses		47,552		28,313		89,909		83,088		43,411		42,357
Production taxes		1,956		1,143		3,952		2,059
Gathering and transportation		4,824		3,301		9,143		8,750
Depreciation, depletion, amortization and accretion		30,952		29,483		57,589		68,609
Gathering, transportation and production taxes										5,267		6,315
Depreciation, depletion, and amortization										24,675		20,769
Asset retirement obligations accretion										6,236		5,868
General and administrative expenses		13,986		5,628		24,698		19,591		13,776		10,712
Derivative loss (gain)		81,440		15,414		106,020		(46,498)
Total costs and expenses		180,710		83,282		291,311		135,599
Operating (loss) income		(47,882)		(28,041)		(32,835)		43,770
Total operating expenses										93,365		86,021
Operating income										97,639		39,626

Interest expense, net		16,530		14,816		31,564		31,926		19,883		15,034
Gain on debt transactions		0		(28,968)		0		(47,469)
Derivative loss										79,997		24,578
Other expense, net		—		751		963		1,474		905		963
(Loss) income before income taxes		(64,412)		(14,640)		(65,362)		57,839
Loss before income taxes										(3,146)		(949)
Income tax benefit		(12,740)		(8,736)		(12,944)		(2,237)		(689)		(203)
Net (loss) income	$	(51,672)	$	(5,904)	$	(52,418)	$	60,076
Basic and diluted (loss) earnings per common share	$	(0.36)	$	(0.04)	$	(0.37)	$	0.42
Net loss									$	(2,457)	$	(746)

Net loss per common share:
Basic									$	(0.02)	$	(0.01)
Diluted										(0.02)		(0.01)

Weighted average common shares outstanding
Basic										142,942		142,151
Diluted										142,942		142,151

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)

Common Stock

Additional








Total

Outstanding

Paid-In

Retained

Treasury Stock

Shareholders’


Shares

Value

Capital

Deficit

Shares

Value

Deficit
Balances at March 31, 2020

141,669

$
1

$
548,098

$
(706,269)

2,869

$
(24,167)

$
(182,337)
Share-based compensation

0

0

1,019

0

0

0

1,019
Stock Issued

0

0

0

0

0

0

0
Net loss

—

—

—

(5,904)

—

—

(5,904)
Balances at June 30, 2020

141,669

$
1

$
549,117

$
(712,173)

2,869

$
(24,167)

$
(187,222)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at December 31, 2021	142,863	$	1	$	552,923	$	(775,937)	2,869	$	(24,167)	$	(247,180)
Share-based compensation	0		0		520		0	0		0		520
Stock Issued	149		0		0		0	0		0		0
RSUs surrendered for payroll taxes	—		—		(268)		—	—		—		(268)
Net loss	—		—		—		(2,457)	—		—		(2,457)
Balances at March 31, 2022	143,012	$	1	$	553,175	$	(778,394)	2,869	$	(24,167)	$	(249,385)

Common Stock

Additional








Total

Outstanding

Paid-In

Retained

Treasury Stock

Shareholders’


Shares

Value

Capital

Deficit

Shares

Value

Deficit
Balances at March 31, 2021

142,305

$
1

$
550,793

$
(735,205)

2,869

$
(24,167)

$
(208,578)
Share-based compensation

0

467

0

0

0

467
Stock Issued

62

0

0

0

0

0

0
Net loss

0

0

0

(51,672)

0

0

(51,672)
Balances at June 30, 2021

142,367

$
1

$
551,260

$
(786,877)

2,869

$
(24,167)

$
(259,783)

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

—

—

2,067

—

—

—

2,067
Stock Issued

—

—

—

—

—

—

—
Net income

—

—

—

60,076

—

—

60,076
Balances at June 30, 2020

141,669

$
1

$
549,117

$
(712,173)

2,869

$
(24,167)

$
(187,222)


	Common Stock			Additional							Total		Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’		Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit		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)	142,305	$	1	$	550,339	$	(734,459)	2,869	$	(24,167)	$	(208,286)
Share-based compensation	—		—		921		—	—		—		921	0				454		0	0		0		454
Stock Issued	62		—		—		—	—		—		—
Net loss	—		—		—		(52,418)	—		—		(52,418)	0		0		0		(746)	0		0		(746)
Balances at June 30, 2021	142,367	$	1	$	551,260	$	(786,877)	2,869	$	(24,167)	$	(259,783)
Balances at March 31, 2021													142,305	$	1	$	550,793	$	(735,205)	2,869	$	(24,167)	$	(208,578)

See Notes to Condensed Consolidated Financial ~~Statements~~Statements.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,				Three Months Ended March 31,
	2021		2020		2022		2021
Operating activities:
Net (loss) income	$	(52,418)	$	60,076
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Net loss					$	(2,457)	$	(746)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		57,589		68,609		30,911		26,637
Amortization of debt items and other items		2,967		3,682		2,594		2,019
Share-based compensation		921		2,067		520		454
Derivative loss (gain)		106,020		(46,498)
Derivative cash (payments) receipts, net		(41,130)		37,566
Gain on debt transactions		0		(47,469)
Derivative loss						79,997		24,578
Derivative cash payments, net						(30,515)		(4,604)
Deferred income taxes		(13,006)		(2,207)		(733)		(203)
Changes in operating assets and liabilities:
Oil and natural gas receivables		(11,390)		34,984		(37,774)		(11,101)
Joint interest receivables		(910)		4,743		(4,476)		(4,394)
Prepaid expenses and other assets		(17,605)		3,505		(12,183)		(7,575)
Income tax		(92)		2,008		44		—
Asset retirement obligation settlements		(11,213)		(2,164)		(5,492)		(962)
Cash advances from JV partners		(3,925)		5,850		(8,550)		(1,023)
Accounts payable, accrued liabilities and other		30,386		(31,274)		15,651		21,884
Net cash provided by operating activities		46,194		93,478		27,537		44,964
Investing activities:
Investment in oil and natural gas properties and equipment		(5,856)		(14,138)		(17,439)		(1,575)
Changes in operating assets and liabilities associated with investing activities		(3,078)		(25,811)		2,630		(1,758)
Acquisition of property interests		0		(456)		(30,153)		0
Purchases of furniture, fixtures and other		2		(70)		—		2
Net cash used in investing activities		(8,932)		(40,475)		(44,962)		(3,331)
Financing activities:
Borrowings on credit facility		—		25,000
Repayments on credit facility		(80,000)		(50,000)		—		(32,000)
Purchase of Senior Second Lien Notes		0		(23,930)
Proceeds from Term Loan		215,000		—
Debt issuance costs and other		(6,840)		—
Net cash provided by (used in) financing activities		128,160		(48,930)
Increase in cash and cash equivalents		165,422		4,073
Cash and cash equivalents, beginning of period		43,726		32,433
Cash and cash equivalents, end of period	$	209,148	$	36,506
Repayments on Term Loan						(12,630)		—
Debt issuance costs						(269)		—
Net cash used in financing activities						(12,899)		(32,000)
(Decrease) increase in cash and cash equivalents						(30,324)		9,633
Cash and cash equivalents and restricted cash, beginning of period						250,216		43,726
Cash and cash equivalents and restricted cash, end of period					$	219,892	$	53,359

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

~~1. Basis of Presentation~~NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

~~Operations.~~ Nature of Operations

W&T Offshore, Inc. (with subsidiaries referred to herein as “W~~&T,” “we,” “us,” “our,”~~&T” 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~~Interests in fields, leases, structures and equipment are primarily owned by the Company and its 100% owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC (“A-I, LLC”), and Aquasition II, LLC (“A-II LLC), and through ~~our~~a proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 5.6 – Joint Venture Drilling Program.

~~Interim Financial Statements.~~ Basis of Presentation

The accompanying unaudited ~~condensed consolidated financial statements~~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 2021 Annual Report on Form 10-K ~~for~~(the “2021 Annual Report”).

Reclassification – For presentation purposes, as of March 31, 2021, Derivative loss has been reclassified from “Operating income” on the ~~year ended December~~Condensed Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassification had no effect on our results of operations, financial position or cash flows.

For presentation purposes, as of March 31, ~~2020.~~2021, Gathering and transportation and Production taxes have been combined into one line item within “Operating income” on the Condensed Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassification had no effect on our results of operations, financial position or cash flows.

Use of ~~Estimates.~~ 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.~~periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

~~Accounting Standards Updates effective January 1, 2021~~

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

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

~~Employee Retention Credit.~~ Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the six months ended June 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~~Summary of Significant Accounting Policies

Revenue and ~~Allowance for Credit Losses.~~ Accounts Receivable~~Our revenue has been~~ – Revenue from the sale of crude oil, natural gas liquids (“NGLs”) and natural gas is recognized when performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of crude oil, NGLs and natural gas to the customer. Revenue is concentrated inwith certain major oil and gas companies. ~~For~~There have been no significant changes to the ~~six~~Company’s contracts with customers during the three months ended ~~June 30, 2021, and the year ended December~~March 31, 2020, approximately 64% 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. We2022.

The Company also ~~have~~has 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 10ten 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~~Joint interest receivables ~~related to joint interest billings are reported~~ on the Condensed Consolidated Balance ~~Sheets~~Sheet are presented net of ~~the allowance for credit losses. The~~ allowance for credit losses ~~was $9.1~~of $10.9 million and $10.0 million as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020.~~2021, respectively.

Employee Retention Credit – Under the Consolidated Appropriations Act of 2021 passed by the United States Congress and signed by the President on December 27, 2020, the Company recognized a $2.1 million employee retention credit during the three months ended March 31, 2021 which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations. NaN such credit has been recognized during the three months ended March 31, 2022.

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

June 30, 2021

December 31, 2020
Derivatives – current (1)

$
14,021

$
2,752
Unamortized insurance/bond premiums

6,195

4,717
Prepaid deposits related to royalties

4,544

4,473
Prepayment to vendors

4,775

1,429
Other

1,170

461
Prepaid expenses and other assets

$
30,705

$
13,832


	March 31, 2022		December 31, 2021
Derivatives⁽¹⁾(Note 8)	$	77,658	$	21,086
Unamortized insurance/bond premiums		7,291		5,400
Prepaid deposits related to royalties		9,189		8,441
Prepayment to vendors		4,461		4,522
Prepayments to joint interest partners		2,653		2,808
Debt issue costs		1,763		1,065
Other		46		57
Prepaid expenses and other assets	$	103,061	$	43,379

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

Oil and Natural Gas Properties and Other, ~~Net.~~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):

June 30, 2021

December 31, 2020
Oil and natural gas properties and equipment, at cost

$
8,583,983

$
8,567,509
Furniture, fixtures and other

20,845

20,847
Total property and equipment

8,604,828

8,588,356
Less: Accumulated depreciation, depletion, amortization and impairment

7,947,171

7,901,478
Oil and natural gas properties and other, net

$
657,657

$
686,878

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

June 30, 2021

December 31, 2020
Right-of-Use assets

$
10,783

$
11,509
Unamortized debt issuance costs

1,333

2,094
Investment in White Cap, LLC

2,995

2,699
Unamortized brokerage fee for Monza

0

626
Proportional consolidation of Monza's other assets (Note 5)

4,209

1,782
Derivatives

21,005

2,762
Other

2,070

998
Total other assets (long-term)

$
42,395

$
22,470


	March 31, 2022		December 31, 2021
Oil and natural gas properties and equipment	$	8,727,521	$	8,636,408
Furniture, fixtures and other		20,845		20,844
Total property and equipment		8,748,366		8,657,252
Less: Accumulated depreciation, depletion, amortization and impairment		8,016,674		7,992,000
Oil and natural gas properties and other, net	$	731,692	$	665,252

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

June 30, 2021

December 31, 2020
Accrued interest

$
10,185

$
10,389
Accrued salaries/payroll taxes/benefits

4,218

4,009
Litigation accruals

570

436
Lease liability

673

394
Derivatives

82,832

13,620
Other

1,885

1,032
Total accrued liabilities

$
100,363

$
29,880


	March 31, 2022		December 31, 2021
Right-of-Use assets	$	10,604	$	10,602
Investment in White Cap, LLC		2,740		2,533
Proportional consolidation of Monza (Note 6)		(531)		2,511
Derivatives ⁽¹⁾ (Note 8)		49,550		34,435
Other		1,029		1,091
Total other assets (long-term)	$	63,392	$	51,172

⁽¹⁾	^{Includes open contracts and prepaid premiums paid for purchased put and call options.}

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


	June 30, 2021		December 31, 2020		March 31, 2022		December 31, 2021
Dispute related to royalty deductions	$	5,247	$	5,467
Derivatives		28,122		4,384
Accrued interest					$	25,405	$	10,154
Accrued salaries/payroll taxes/benefits						3,997		9,617
Litigation accruals						500		646
Lease liability		11,062		11,360		1,409		1,115
Black Elk escrow		11,102		11,103
Derivatives ⁽¹⁾(Note 8)						177,298		81,456
Other		726		624		1,236		3,152
Total other liabilities (long-term)	$	56,259	$	32,938
Total accrued liabilities					$	209,845	$	106,140

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

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


	March 31, 2022		December 31, 2021
Dispute related to royalty deductions	$	4,937	$	5,177
Derivatives (Note 8)		63,318		37,989
Lease liability		10,936		11,227
Other		1,147		996
Total other liabilities (long-term)	$	80,338	$	55,389

At-the-Market Equity Offering – On March 17, 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100,000,000 of shares of our common stock under our "at-the-market" equity offering program (the "ATM Program"). The designated sales agents will be entitled to a placement fee of up to 3.0% of the gross sales price per share sold. During the three months ended March 31, 2022, we did not sell any shares in connection with the ATM Program.

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~~2. Debt~~NOTE 2 — DEBT

The components ~~of our~~comprising the Company’s debt are presented in the following table (in thousands):


					March 31,		December 31,
	June 30, 2021		December 31, 2020		2022		2021
Term Loan:
Principal	$	215,000	$	—	$	178,229	$	190,859
Unamortized debt issuance costs		(6,718)		—		(6,108)		(7,545)
Total Term Loan		208,282		—		172,121		183,314

Company Credit Agreement borrowings:		—		80,000
Credit Agreement borrowings:						—		—

Senior Second Lien Notes:
Principal		552,460		552,460		552,460		552,460
Unamortized debt issuance costs		(6,055)		(7,174)		(4,264)		(4,876)
Total Senior Second Lien Notes		546,405		545,286		548,196		547,584

Less current portion		(36,771)		—		(39,881)		(42,960)
Total long-term debt, net	$	717,916	$	625,286	$	680,436	$	687,938

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Current Portion of Long-Term Debt

As of ~~June 30, 2021,~~March 31, 2022, the current portion of long-term debt of ~~$36.8~~$39.9 million represented ~~principle~~principal payments due within one year on the Term Loan (defined below).

Term Loan (Subsidiary Credit Agreement)

On May 19, 2021, ~~Aquasition~~A-I LLC ~~(“A-I LLC”)~~ and ~~Aquasition II~~A-II LLC ~~(“A-II LLC”)~~ (collectively, the ~~“Borrowers”~~“Subsidiary 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 Subsidiary Borrowers and the subsidiary that owns the equity in the Subsidiary Borrowers, and is secured by the first lien security interests in the equity of the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers (the Mobile Bay Properties, defined below).

In exchange for the net cash proceeds received by the Subsidiary 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, in the 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, in the 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~~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 are referred to herein as the “Mobile Bay Transaction”.

For information about the Mobile Bay Transaction refer to Note 4, 5 – Mobile Bay Transaction.

~~Company Credit Agreement~~

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

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Credit Agreement

On November 2, 2021, the Company entered into the Ninth Amendment to the Sixth Amended and Restated Credit Agreement (the “Ninth Amendment”), which establishes a short-term $100.0 million first priority lien secured revolving facility with borrowings limited to a borrowing base of $50.0 million (the “Credit Agreement”) 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 Credit Agreement. A committee of the independent members of the Board of Directors reviewed and approved the amendments given the Chief Executive Officer’s affiliation with Calculus. As of November 2, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate amount of approximately $4.4 million. Alter Domus (US) LLC was appointed to replace Toronto Dominion (Texas) LLC as administrative agent under the Credit Agreement.

On March 8, 2022, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”), which extended the maturity date and Calculus’ commitment to January 3, 2023. The terms of this extension with Calculus were reviewed and approved by the Audit Committee of the Company.

As a result of the Ninth Amendment and Tenth Amendment and related assignments and agreements, the primary terms and covenants associated with the ~~Company~~ Credit Agreement as of ~~June 30, 2021, as amended by the Sixth and Seventh Amendments,~~March 31, 2022, are as ~~follows, with capitalized terms defined under the Company Credit Agreement:~~follows:

The revised borrowing base ~~was $190.0 million, subject to the next redetermination on or about October 1, 2021.~~is $50.0 million.

~~Letters~~The commitment will expire and final maturity of ~~credit may be issued in~~any and all outstanding loans is January 3, 2023. Outstanding borrowings will accrue interest at LIBOR plus 6.0% per annum. The commitment fee for the unused portion of available borrowing amounts ~~up to $30.0 million, provided availability under the Company Credit Agreement exists.~~

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

~~During the Waiver Period, the Company~~ will be ~~required to maintain a 2.00 to 1.00 ratio limit of first lien debt outstanding under the Company Credit Agreement on the last day of the most recent quarter to EBITDAX for the trailing four quarters.~~3.0% per annum.

·The ~~Current Ratio, as~~Company’s ratio of First Lien Debt (as such term is defined in the ~~Company~~Credit Agreement) outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX (as such term is defined in the 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 (as such term is defined in the Credit Agreement) to First Lien Debt as of the last day of any fiscal quarter commencing with the fiscal quarter ending March 31, 2022 must be ~~maintained at~~equal to or greater than ~~1.00~~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 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 revolving credit 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 Credit Agreement.

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In connection with the Tenth Amendment, Calculus was paid arrangement and upfront fees of approximately $1.0 million in the aggregate during the three months ended March 31, 2022.

Availability under the ~~Company~~ Credit Agreement is subject to ~~semi-annual redeterminations~~redetermination of our borrowing base ~~and, the next scheduled redetermination is to occur on or about October 1, 2021. Subsequent to the October 2021 redetermination, additional redeterminations~~that may be requested at the discretion of either the ~~lenders~~lender or the ~~Company.~~Company in accordance with the Credit Agreement. The borrowing base is calculated by ~~our lenders~~the lender based on their evaluation of ~~our~~ proved reserves and their own internal criteria. Any redetermination by ~~our lenders~~the lender to change ~~our~~the borrowing base will result in a similar change in the availability under the ~~Company~~ Credit Agreement. The Company currently has 0 borrowings outstanding under the Company Credit Agreement and has agreed to not to make borrowings under the Company Credit Agreement unless and until the next semi-annual redetermination of our borrowing base occurs and the Company complies with certain revised hedging requirements.

The Company used a portion of the proceeds from Mobile Bay Transaction to repay the $48.0 million outstanding balance on its reserve-based lending facility under the Company Credit Agreement. All liens on the Mobile Bay Properties granted to secure obligations under the Company Credit Agreement were released in connection with the transfer of such assets to Borrowers. ~~The Company~~ Credit Agreement is ~~collateralized~~secured by a first priority lien on ~~properties constituting at least 90%~~substantially all of the ~~total proved reserves~~Company’s and its guarantor subsidiaries’ assets, excluding those assets of the ~~Company as set forth on reserve reports required to be delivered under the Company Credit Agreement and certain personal property, excluding those~~Subsidiary Borrowers, which liens were released in the Mobile Bay Transaction as(as described ~~above.~~in Note 5 – Mobile Bay Transaction).

As of ~~June 30, 2021~~March 31, 2022, we had 0 borrowings outstanding under the Credit Agreement. Separately, as of March 31, 2022 and December 31, ~~2020, we~~2021, the Company had $4.4 million, ofoutstanding in letters of credit issued and outstanding under the Company Credit Agreement. NaN borrowings under the Company Credit Agreement were outstanding as of June 30, 2021 and $80.0 million in borrowings were outstanding under the Company Credit Agreement as of December 31, 2020. The annualized interest rate on borrowings outstanding for the six months ended June 30, 2021 was 3.2%, which ~~excludes debt issuance costs, commitment fees and other fees.~~have been cash collateralized.

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9.75% Senior Second Lien Notes Due 2023

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

During the year ended December 31, 2020, we acquired $72.5 million in principal of our outstanding Senior Second Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million, which included a reduction of $1.1 million related to the write-off of unamortized debt issuance costs. No such transactions were completed during the three ~~and six~~ months ended ~~June 30, 2021.~~March 31, 2022. As a result of these purchases, $552.5 million in principal amount of Senior Second Lien Notes remains issued and outstanding as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020.~~2021.

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

Covenants

As of ~~June 30, 2021~~March 31, 2022 and for all prior measurement periods ~~we were~~presented, the Company was in compliance with all applicable covenants of the ~~Company~~ Credit Agreement and the Indenture. The Seventh Amendment revised certain covenants under the Company Credit Agreement related to hedging our future production and waived compliance with such requirements, including the requirement that certain existing hedge transactions be unwound or terminated, until our next semi-annual borrowing base redetermination occurs.

Fair Value Measurements

For information about fair value measurements of ~~our~~ long-term debt, refer to Note 3.3 – Fair Value Measurements.

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~~3. Fair Value Measurements~~NOTE 3 — FAIR VALUE MEASUREMENTS

Derivative Financial Instruments
~~We measure~~The Company measures 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~~Open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 7 8 – Derivative Financial Instruments, for additional information on ~~our~~ derivative financial instruments.

~~Table of Contents~~

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

June 30, 2021

December 31, 2020

March 31, 2022

December 31, 2021
Assets:








Derivatives instruments - open contracts, current

$
13,111

$
2,705
Derivatives instruments - open contracts, long-term

21,005
��

2,762
Derivative instruments - open contracts, current

$
73,090

$
19,215
Derivative instruments - open contracts, long-term

49,550

34,435

Liabilities:








Derivatives instruments - open contracts, current

74,632

13,291
Derivatives instruments - open contracts, long-term

28,122

4,384
Derivative instruments - open contracts, current

157,348

73,190
Derivative instruments - open contracts, long-term

63,318

37,989

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


June 30, 2021

December 31, 2020

March 31, 2022

December 31, 2021

Net Value

Fair Value

Net Value

Fair Value

Net Value

Fair Value

Net Value

Fair Value
Liabilities:
















Term Loan

$
208,282

$
214,607

$
—

$
—

$
172,121

$
173,210

$
183,314

$
190,579
Company Credit Agreement

—

—

80,000

80,000
Senior Second Lien Notes

546,405

536,660

545,286

393,352

548,196

551,162

547,584

527,715
Total

754,687

751,267

625,286

473,352

720,317

724,372

730,898

718,294

NOTE 4 — ACQUISITIONS

On January 5, 2022, the Company entered into a purchase and sale agreement with ANKOR E&P Holdings Corporation and KOA Energy LP (“ANKOR”) to acquire their interests in and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields for $47.0 million. The transaction closed on February 1, 2022, and after normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date of July 1, 2021 to the close date), cash consideration of approximately $30.2 million was paid to the sellers. The transaction was funded using cash on hand. The Company also assumed the related asset retirement obligations (“ARO”) associated with these assets.

The Company determined that the assets acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition. Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Condensed Consolidated Balance Sheets by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas

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properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired. The amounts recorded on the Condensed Consolidated Balance Sheet for the purchase price allocation and liabilities assumed are presented in the following table (in thousands):

February 1,
2022
Oil and natural gas properties and other, net

$
50,450
Restricted deposits for asset retirement obligations

6,196
Asset retirement obligations

(26,493)
Allocated purchase price

$
30,153

4.NOTE 5 ~~Mobile Bay Transaction~~— 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 Subsidiary 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 Subsidiary 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 78 – Derivative Financial Instruments, of this Quarterly ~~Report.~~Report on Form 10-Q (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)~~i) the Mobile Bay Properties and ~~(II)~~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.

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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

Table of ~~June 30, 2021, the book value of the assets of the SPVs were $292.4 million.~~Contents

Consolidation and Carrying Amounts

As of March 31, 2022, W&T recorded $33.4 million in Cash and cash equivalents, $275.5 million, in Oil and natural gas properties and other, net, $39.9 million in Current portion of long-term debt, $56.0 million in Asset retirement obligations, and $132.2 million in Long-term debt, net in the Condensed Consolidated Balance Sheetrelated to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers. As of December 31, 2021, W&T recorded $38.9 million in Cash and cash equivalents, $272.7 million, in Oil and natural gas properties and other, net, $43.0 million in Current portion of long-term debt, $54.5 million in Asset retirement obligations, and $140.4 million in Long-term debt, net in the Condensed Consolidated Balance Sheet related to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers.

During the three months ended March 31, 2022, W&T recognized $47.5 million in Total revenues, $19.6 million in Operating costs and expenses, $96.2 million in Derivative loss, and $4.8 million in Interest expense, net in the Condensed Consolidated Statement of Operationsrelated to the consolidation of the operations of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers. NaN revenues or expenses were recorded in the three months ended March 31, 2021 related to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers as the transaction was effective subsequent to March 31, 2021.

~~5. Joint Venture Drilling Program~~NOTE 6 — JOINT VENTURE DRILLING PROGRAM

In March 2018, W&T and 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 commitment to fund its retained interest in Monza projects held outside of Monza, ~~are~~was $361.4 million. W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our retained working interest in the Monza projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board.

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

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

Through ~~June 30, 2021, 9~~March 31, 2022, 10 wells have been ~~completed. In 2020, 1 well was drilled to target depth, which we expect to be~~ completed insince the ~~fourth quarter~~inception of ~~2021.~~the Joint Venture Drilling Program. W&T is the operator for 78 of the 910 wells completed through ~~June 30, 2021.~~March 31, 2022.

Through ~~June 30, 2021,~~March 31, 2022, members of Monza made partner capital contributions, including our contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling ~~$77.9~~$95.8 million. ~~Our~~W&T’s net contribution to Monza, reduced by distributions received, as of ~~June 30, 2021~~March 31, 2022 was ~~$51.6~~$47.8 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.

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Table of Contents

Consolidation and Carrying Amounts
~~Our~~W&T’s interest in Monza is considered to be a variable interest that we account for using proportional consolidation. Through ~~June 30, 2021,~~March 31, 2022, there have been no events or changes that would cause a redetermination of the variable interest status. ~~We do~~W&T does not fully consolidate Monza because ~~we are~~the Company is not considered the primary beneficiary of Monza.

As of ~~June 30, 2021, in the Condensed Consolidated Balance Sheet, we~~March 31, 2022, W&T recorded ~~$6.6~~$2.1 million, net, in Oil and natural gas properties and other, net, ~~$4.2~~$(0.5) million in Other assets, $0.3 million in Asset ~~Retirement Obligations ("ARO")~~retirement obligations and ~~$1.7~~$11.0 million, net, increase in working capital in the Condensed Consolidated Balance Sheet in connection with ~~our~~the proportional interest in Monza’s assets and liabilities. As of December 31, ~~2020, in the Condensed Consolidated Balance Sheet, we~~2021, W&T recorded ~~$9.9~~$3.5 million ~~net,~~ in Oil and natural gas properties and other, net, ~~$1.8~~$2.5 million in Other assets, ~~$0.2~~$0.3 million in ARO and ~~$1.3~~$4.6 million, net, increase in working capital in the Condensed Consolidated Balance Sheet in connection with ~~our~~the proportional interest in Monza’s assets and liabilities. Additionally, during the ~~six months ended June 30, 2021 and during the~~ year ended December 31, ~~2020, we~~2021, W&T 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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 were ~~$3.4~~$6.5 million and ~~$7.3~~$14.8 million, respectively, which are included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners.

For the ~~six~~three months ended ~~June 30, 2021, in the Condensed Consolidated Statement of Operations, we~~March 31, 2022, W&T recorded ~~$5.5~~$6.5 million in Total revenues and ~~$6.7 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~~$3.3 million in Operating costs and expenses in the Condensed Consolidated Statement of Operations in connection with ~~our~~the proportional interest in Monza’s operations. For three months ended March 31, 2021, W&T recorded $2.5 million in Total revenues and, $3.4 million in Operating costs and expenses in theCondensed Consolidated Statement of Operations in connection with the proportional interest in Monza’s operations.

~~6.        Asset Retirement Obligations~~NOTE 7 — ASSET RETIREMENT OBLIGATIONS

~~Our ARO~~AROs 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):

Three Months Ended March 31,


2022
Asset retirement obligations, beginning of period

$
424,495
Liabilities settled

(5,492)
Accretion of discount

6,236
Liabilities incurred and assumed through acquisition

26,493
Revisions of estimated liabilities ⁽¹⁾

23,224
Asset retirement obligations, end of period

474,956
Less current portion

(67,274)
Long-term

$
407,682

Balances, December 31, 2020

$
392,704
Liabilities settled

(11,213)
Accretion of discount

11,895
Liabilities incurred and assumed through acquisition

417
Revisions of estimated liabilities

10,200
Balances, June 30, 2021

404,003
Less current portion

(23,888)
Long-term

$
380,115

(1) ^{Revisions in 2022 were primarily due to moving additional projects to current term and increases in current pricing.}

~~7.        Derivative Financial Instruments~~
Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our crude oil and natural gas. All of the present derivative counterparties are also lenders or affiliates of lenders participating in our Company Credit Agreement or Term Loan. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations. We are not required to provide additional collateral to the derivative counterparties and we do not require collateral from our derivative counterparties.
We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all current period changes in the fair value of derivative contracts are recognized in earnings during the periods presented. The cash flows of all of our commodity derivative contracts are included in ~~Net cash provided by operating activities~~ ~~on the Condensed Consolidated Statements of Cash Flows.~~

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Table of Contents

~~We entered into~~NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS
W&T’s market risk exposure relates primarily to commodity ~~contracts for crude~~prices. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas ~~which related~~production through the use of oil and natural gas swaps, costless collars, sold calls and purchased puts. The Company is exposed to ~~a portion~~credit loss in the event of ~~our expected future production.~~ nonperformance by the derivative counterparties; however, the Company currently anticipates that the derivative counterparties will be able to fulfill their contractual obligations. The Company is not required to provide additional collateral to the derivative counterparties and does not require collateral from the derivative counterparties.
W&T has elected not to designate commodity derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as Derivative losson the Condensed Consolidated Statements of Operations in each period presented. The cash flows of all commodity derivative contracts are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.
The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices and the natural gas contracts are based off the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).
The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts as of ~~June 30, 2021:~~March 31, 2022:

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)

($/Bbl)(1)

($/Bbl)(1)

($/Bbl)(1)
Jul 2021 - Dec 2021

swap

4,000

736,000

$
42.06

$
—

$
—
Jul 2021 - Dec 2021

collar

200

36,800

$
—

$
40.00

$
54.90
Jul 2021 - Feb 2022

collar

2,024

491,733

$
—

$
38.81

$
57.24
Jan 2022 - Feb 2022

swap

3,000

177,000

$
42.98

$
—

$
—
Mar 2022 - May 2022

swap

2,044

188,006

$
42.33

$
—

$
—
Mar 2022 - May 2022

collar

2,000

184,000

$
—

$
35.00

$
48.50
Mar 2022 - Sept 2022

swap

1,615

345,638

$
54.53

$
—

$
—
Mar 2022 - Sept 2022

collar

1,615

345,638

$
—

$
45.00

$
62.50
Oct 2022

swap

2,172

67,332

$
58.50

$
—

—
Oct 2022

collar

2,172

67,332

$
—

$
46.00

66.50
Nov 2022

swap

2,176

65,280

$
58.25

$
—

—
Nov 2022

collar

2,176

65,280

$
—

$
46.00

66.30

Natural Gas - Henry Hub (NYMEX)

(MMbtu)(2)

(MMbtu)(2)

($/MMbtu)(2)

($/MMbtu)(2)

($/MMbtu)(2)
Jul 2021 - Dec 2021

collar

30,000

5,520,000

$
—

$
2.18

$
3.00
Jul 2021 - Dec 2021

swap

10,000

1,840,000

$
2.62

$
—

$
—
Jul 2021 - Dec 2021

call

40,000

7,360,000

$
—

$
—

$
3.50
Jul 2021 - Dec 2022

collar

40,000

21,960,000

$
—

$
1.83

$
3.00
Jul 2021 - Dec 2022

call

40,000

21,960,000

$
—

$
—

$
3.00
Jan 2022 - Feb 2022

collar

30,000

1,830,000

$
—

$
2.20

$
4.50
Jan 2022 - Dec 2022

call

37,000

13,505,000

$
—

$
—

$
3.50
Jan 2022

swap

20,000

620,000

$
2.79

$
—

$
—
Feb 2022

swap

30,000

840,000

$
2.79

$
—

$
—
Mar 2022 - May 2022

collar

10,000

920,000

$
—

$
2.25

$
3.40
Mar 2022 - May 2022

swap

10,544

970,075

$
2.69

$
—

$
—
Apr 2022 - Sept 2022

swap

12,428

2,274,311

$
2.44

$
—

$
—
Oct 2022

swap

16,129

499,999

$
2.56

$
—

$
—
Nov 2022

swap

17,570

527,100

$
2.63

$
—

$
—
Jan 2023 - Dec 2023

call

70,000

25,550,000

$
—

$
—

$
3.50
Jul 2021 - Mar 2025 (3)

swap

72,920

99,900,000

$
2.63

$
—

$
—
Apr 2025 - Apr 2028 (3)

put

55,684

62,700,000

$
—

$
2.35

$
—

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⁾
Apr 2022 - Nov 2022

swaps

2,410

588,027

$
52.83

$
—

$
—
Apr 2022 - Nov 2022

collars

2,403

586,377

$
—

$
43.15

$
60.47

Natural Gas - Henry Hub (NYMEX)

(MMbtu)⁽²⁾

(MMbtu)⁽²⁾

($/MMbtu)⁽²⁾

($/MMbtu)⁽²⁾

($/MMbtu)⁽²⁾
Apr 2022 - Dec 2022

calls

111,519

30,667,734

$
—

$
—

$
3.78
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
Apr 2022 - Dec 2022

collars

42,218

11,610,000

$
—

$
1.85

$
3.02
Apr 2022 - Nov 2022

swaps

16,224

3,958,540

$
2.52

$
—

$
—
Apr 2022 - Dec 2022 ⁽³⁾

swaps

78,545

21,600,000

$
2.55

$
—

$
—
Jan 2023 - Dec 2023 ⁽³⁾

swaps

72,329

26,400,000

$
2.48

$
—

$
—
Jan 2024 - Dec 2024 ⁽³⁾

swaps

65,574

24,000,000

$
2.46

$
—

$
—
Jan 2025 - Mar 2025 ⁽³⁾

swaps

63,333

5,700,000

$
2.72

$
—

$
—
Apr 2025 - Dec 2025⁽³⁾

puts

62,182

17,100,000

$
—

$
2.27

$
—
Jan 2026 - Dec 2026 ⁽³⁾

puts

55,890

20,400,000

$
—

$
2.35

$
—
Jan 2027 - Dec 2027 ⁽³⁾

puts

52,603

19,200,000

$
—

$
2.37

$
—
Jan 2028 - Apr 2028 ⁽³⁾

puts

49,587

6,000,000

$
—

$
2.50

$
—
⁽¹⁾
^{Bbls =– Barrels}
~~(2) MMbtu = Million British Thermal Units~~
~~(3) These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with the Mobile Bay Transaction (see Note 4~~ ~~Mobile Bay Transaction).~~
⁽²⁾
^{MMbtu – Million British Thermal Units}
⁽³⁾
^{These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with the Mobile Bay Transaction (see}^{Note 5 – Mobile Bay Transaction).}

1415

Table of Contents

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

June 30,

December 31,


2021

2020

March 31, 2022

December 31, 2021
Prepaid expenses and other current assets

$
14,021

$
2,752

$
77,658

$
21,086
Other assets (long-term)

21,005

2,762

49,550

34,435
Accrued liabilities

82,832

13,620

177,298

81,456
Other liabilities (long-term)

28,122

4,384

63,318

37,989

The amounts recorded on the Condensed Consolidated Balance Sheets are on a gross basis.
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 June 30,

Six Months Ended June 30,

Three Months Ended March 31,


2021

2020

2021

2020

2022

2021
Realized loss (gain)

$
15,357

$
(22,578)

$
23,602

$
(31,970)
Unrealized loss (gain)

66,083

37,992

82,418

(14,528)
Derivative loss (gain)

$
81,440

$
15,414

$
106,020

$
(46,498)
Realized loss

$
43,694

$
8,244
Unrealized loss

36,303

16,334
Derivative loss

$
79,997

$
24,578

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):

Six Months Ended June 30,

Three Months Ended March 31,


2021

2020

2022

2021
Derivative loss (gain)

$
106,020

$
(46,498)
Derivative cash (payments) receipts, net

(41,130)

37,566
Derivative loss

$
79,997

$
24,578
Derivative cash payments, net

(30,515)

(4,604)

~~8.        Share-Based Awards and Cash-Based Awards~~NOTE 9
~~Share-Based Awards to Employees~~— SHARE-BASED AWARDS AND CASH BASED AWARDS
The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by ~~our~~the Company’s shareholders in 2010. Under the Plan, the Company may issue, subject to the approval of the Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, performance units or shares, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants.
As of June 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 1-for-one basis when awards are settled in shares of common stock, which shares of common stock are issued net of withholding tax through the withholding of shares. The Company has the option following vestingShare-Based Awards to ~~settle awards in stock or cash, or a combination of stock and cash. The Company expects to settle outstanding awards, discussed below, that vest in the future using shares of common stock.~~Employees

~~Table of Contents~~

Restricted Stock Units (“RSUs”). – RSUs currently outstanding relate to the 2021 ~~and 2019~~ grants. ~~During the six months ended June 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, 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 three months ended ~~June 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

698,301

4.72
Vested

—

—
Forfeited

(19,880)

4.51
Nonvested, June 30, 2021

1,442,109

4.61

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


Restricted

Shares
2021

743,808
2022

232,767
2023

232,767
2024

232,767
Total

1,442,109

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.March 31, 2022.
Performance Share Units (“PSUs”). ~~During the six months ended June 30, 2021, the Company granted PSUs under the plan to certain employees.~~– The PSUs are RSU awards granted subject to performance criteria. PSUs currently outstanding relate to 2021 grants. NaN PSUs were granted during the three months ended March 31, 2022. The 2021 grants were subject to 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~~which ended on ~~the change in the entity’s stock price plus dividends for the applicable performance period. Subsequent to the performance period, the~~December 31, 2021. The PSUs ~~will~~granted during 2021 continue to be subject to service-based criteria with vesting occurring on October 1, 2023.
Share-Based Awards to Non-Employee Directors
There was 0 activity related to Restricted Shares during the three months ended March 31, 2022. Restricted Shares currently outstanding relate to the 2021 grants.

Table of Contents

~~A summary of activity related to PSUs during the three months ended June 30, 2021 is as follows:~~

Performance Share Units

Weighted

Average

Grant Date Fair

Units

Value Per Unit
Nonvested, December 31, 2020

—

$
—
Granted

388,908

5.57
Vested

—

—
Forfeited

—

—
Nonvested, June 30, 2021

388,908

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 six months ended June 30 2021, is $2.2 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted:

~~2021 Grant Date~~

~~June 28~~
~~Expected term for performance period (in years)~~

~~0.5~~

~~Expected volatility~~

~~67.9~~
%
~~Risk-free interest rate~~

~~0.1~~
%

~~Share-Based Awards to Non-Employee Directors~~
Under the W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, the “Director Compensation Plan”), shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors. Grants to non-employee directors were made during the six months ended June 30, 2021, and during the year ended December 31, 2020. During the second quarter of 2020, our shareholders approved increasing the shares available under the Director Compensation Plan by 500,000 shares. As of June 30, 2021, there were 410,742 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available are reduced on a 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.

~~Table of Contents~~

~~A summary of activity related to Restricted Shares during the sixmonths ended June 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, June 30, 2021

70,226

3.67

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

Share-Based Compensation Expense
Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations. The tax benefit related to compensation expense recognized under share-based payment arrangements was not meaningful and was minimal due to ~~our~~the Company’s income tax ~~situation.~~position.
The Company did not grant any share-based awards during the three months ended March 31, 2022. As such, all share-bases incentive compensation expense recognized during the three months ended March 31, 2022 relates to awards granted in prior periods. A summary of incentive compensation expense under share-based payment arrangements is as follows (in thousands):

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended March 31,


2021

2020

2021

2020

2022

2021
Share-based compensation expense from:








Restricted stock units

$
339

$
949

$
676

$
1,927

$
251

$
338
Performance share units

205

—
Restricted Shares

128

70

245

140

64

116
Total

$
467

$
1,019

$
921

$
2,067

$
520

$
454

~~Unrecognized Share-Based Compensation Expense~~
As of June 30, 2021, unrecognized share-based compensation expense related to our awards of RSUs, PSUs, and Restricted Shares was $3.9 million, $2.2 million, and $0.2 million, respectively. Unrecognized share-based compensation expense will be recognized through December 2023 for RSUs, September 2023 for PSUs, and April 2022 for Restricted Shares.
Cash-Based Incentive Compensation
In addition to share-based compensation, both short-term and long-term cash-based incentive awards were granted under the Plan to all eligible employees in 2021.

~~Table of Contents~~

~~Short-term Cash-Based Incentive Compensation.There are two components of the~~The short-term cash-based incentive ~~award~~awards granted ~~during the six months ended June 30, 2021.~~
● The first short-term, cash-based award granted in February 2021 was discretionary and subject only to continued employment on the payment dates. The 2021 discretionary bonus award was paid in equal installments on March 15, 2021 and April 15, 2021, to substantially all employees subject to employment on those dates. Incentive compensation expense of $3.8 million and $7.6 million was recognized during the three and six months ended June 30, 2021, respectively, related to these awards.
● The second short-term, cash-based award granted in June 2021 is subject to Company performance-based criteria and individual performance criteria. Incentive compensation expense is based on estimates of Company metrics for full-year 2021 and is being recognized during the 2021 service period. Incentive compensation expense for this award was not material during the six months ended June 30, 2021.
~~NaN~~in 2021 were paid in March 2022. No cash-based incentive awards were granted ~~in 2020,~~during the three months ended March 31, 2022.
Share-Based Awards and ~~therefore, 0~~Cash-Based Awards Compensation Expense
The Company did not grant any share-based awards or cash-based awards during the three months ended March 31, 2022. As such, all incentive compensation expense ~~for 2020 was recorded.~~

~~Long-term Cash-Based Incentive Compensation.~~
~~The 2021 long-term, cash-based~~recognized during the three months ended March 31, 2022 relates to awards ~~(“Cash Awards”) were~~ granted in June 2021 and are subject to the same performance-based criteria as the PSU’s 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 June 30, 2021, is ~~$2.2~~ ~~million. As of June 30, 2021, unrecognized compensation expense related to these awards was~~ ~~$2.2~~ ~~million. The following table summarizes the assumptions used to calculate the fair value of the outstanding long-term Cash Awards as of June 30, 2021:~~

~~2021 Grant Date~~

~~June 28~~
~~Expected term for performance period (in years)~~

~~0.5~~

~~Expected volatility~~

~~67.9~~
%
~~Risk-free interest rate~~

~~0.1~~
%
~~Expected term for cash payment (in years)~~

~~2.3~~

~~Discount rate used to discount expected cash payment~~

~~12.1~~
%

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

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended March 31,


2021

2020

2021

2020

2022

2021
Share-based compensation included in:












General and administrative expenses

$
467

$
1,019

$
921

$
2,067

$
520

$
454
Cash-based incentive compensation included in:












Lease operating expense (1)

816

—

1,655

849

255

839
General and administrative expenses (1)

2,676

159

5,359

3,790

1,957

2,682
Total charged to operating (loss) income

$
3,959

$
1,178

$
7,935

$
6,706

$
2,732

$
3,975
(1) Includes adjustments of accruals to actual payments.

~~9.        Income Taxes~~NOTE 10 — INCOME TAXES
Tax Benefit and Tax ~~Rate.~~Rate – Income tax benefit for the three months ended ~~June 30,~~March 31, 2022 and 2021 was $0.7 and ~~2020 was $12.7 and $8.7~~ ~~million, respectively. For the six months ended June 30, 2021 and 2020, income tax benefit was~~ ~~$12.9 million and $2.2~~$0.2 million, respectively. For the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021, our effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the three and six months ended June 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded as a result of 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 ~~19.8% for both the three~~21.9% and ~~six months ended June 30, 2021 and 59.7% and (3.9%)~~21.4% for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2022 and three months ended March 31, 2021, respectively.
~~Calculation of Interim Provision for Income Tax.~~ Historically, we have calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full year to income (loss) for the interim period. In the second quarter of 2021, we concluded that we could not calculate a reliable estimate of our annual effective tax rate. Accordingly, we computed the effective tax rate for the six-month period ending June 30, 2021 using actual results.

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

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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 ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, our valuation allowance was ~~$22.8~~$25.8 million and ~~$22.4~~$24.4 million, respectively, and relates primarily to state net operating losses and the disallowed interest expense limitation carryover.

~~Table of Contents~~

Income Taxes Receivable, Refunds and ~~Payments.~~Payments – As of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, we did 0tnot have any outstanding current income taxes receivable.During the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and March 31, 2021, we did 0tnot receive any income tax refunds or make any income tax payments of significance. During the three and six months ended June 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~~2021 remain open to examination by the tax jurisdictions to which we are subject.

~~10.        Earnings Per Share~~NOTE 11 — 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 June 30,

Six Months Ended June 30,


2021

2020

2021

2020
Net (loss) income

$
(51,672)

$
(5,904)

$
(52,418)

$
60,076
Less portion allocated to nonvested shares

—

—

0

707
Net (loss) income allocated to common shares

$
(51,672)

$
(5,904)

$
(52,418)

$
59,369
Weighted average common shares outstanding

142,244

141,597

142,197

141,571
Basic and diluted (loss) earnings per common share

$
(0.36)

$
(0.04)

$
(0.37)

$
0.42
Shares excluded due to being anti-dilutive (weighted-average)

880

1,665

899

0

Three Months Ended March 31,


2022

2021
Net loss

$
(2,457)

$
(746)
Less portion allocated to nonvested shares

0

—
Net loss allocated to common shares

$
(2,457)

$
(746)

Weighted average common shares outstanding - basic

142,942

142,151
Dilutive effect of securities

0

—
Weighted average common shares outstanding - diluted

142,942

142,151
Earnings per common share:

Basic

$
(0.02)

$
(0.01)
Diluted

(0.02)

(0.01)

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

717

919

~~11.        Contingencies~~NOTE 12 — 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 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.

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~~Royalties – “Unbundling” Initiative.~~ In 2016, the ONRR publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. While the amounts paid for the three and six months ended June 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 of Proposed Civil Penalty ~~Assessment.~~Assessments – In January 2021, we executed a Settlement Agreement with ~~the Bureau of Safety and Environmental Enforcement (“BSEE”)~~BSEE which resolved 9 pending civil penalties issued by BSEE. The civil penalties pertained to Incidents of ~~Noncompliance (“INCs”)~~Non-Compliance 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~~and second installments were paid in March 2021 and March 2022, respectively. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022, which we are on schedule to complete before the deadline.

Retained Liabilities Related to Divested Property Interests – We may be subject to retained liabilities with respect to certain divested property interests by operation of law. For example, recent historical declines in commodity prices created an environment where there is an increased risk that owners and/or operators of interests purchased from us may no longer be able to satisfy plugging or abandonment obligations that attach to those interests. In that event, due to operation of law, we may be required to assume plugging or abandonment obligations for those interests. During 2021, as a result of the declaration of bankruptcy by a third party that is the indirect successor in title to certain offshore interests that we previously divested, we recorded a loss contingency accrual of $4.5 million related to the anticipated cost to decommission certain wells, pipelines, and production facilities for which we may receive decommissioning orders from BSEE. We no longer own these assets nor are they related to our current operations. We intend to seek contribution from other parties that owned an interest in the facilities. We did not recognize any additional liabilities related to divested property interests during the three months ended ~~June 30, 2021, we did 0t pay any civil penalties to BSEE related to newly issued INCs.~~March 31, 2022.

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.~~NOTE ~~Subsequent Events~~13 — SUBSEQUENT EVENTS

~~As described in more detail in Note 2 –~~ ~~Debt~~~~, on July 15, 2021,~~

On April 1, 2022, the Company entered into a ~~Waiver~~purchase and ~~Seventh Amendment~~sale agreement with an undisclosed private seller to ~~Sixth Amended~~acquire the remaining working interests in certain oil and ~~Restated Credit Agreement dated~~natural gas producing properties in federal shallow waters of the Gulf of Mexico at the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields purchased during the three months ended March 31, 2022 from ANKOR. The transaction had an effective ~~June 30, 2021, which further amended~~date and closing date of April 1, 2022.Cash consideration of approximately $17.5 million was paid to the ~~Company Credit Agreement and waived certain hedging transaction requirements.~~seller.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to those financial statements included in Part I, Item 1 of this Quarterly Report, ~~on Form 10-Q (this “Quarterly Report”),~~ as well as our audited Consolidated Financial Statements and the notes thereto in our ~~2020~~2021 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~~2021 Annual ~~Report on Form 10-K (the “2020 Annual Report”).~~Report.
Forward-Looking Statements
The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
These forward-looking statements are subject risks, uncertainties and assumptions, most of which are difficult to predict and many of which are beyond our control. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, estimates, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Part I, Item 1A, Risk Factors, and market risks are discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our ~~2020~~2021 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the ~~Securities and Exchange Commission.~~SEC.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
Overview
We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of ~~June 2021,~~March 31, 2022, we hold working interests in 4147 offshore fields in federal and state waters ~~(40~~(44 fields producing and ~~1 field~~3 fields capable of producing, ~~with 33~~which include 39 fields in federal waters and 8 in state waters). We currently have under lease approximately ~~621,700~~655,000 gross acres ~~(424,400~~(453,200 net acres) spanning across the outer continental shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama State waters, ~~426,800~~466,000 gross acres on the conventional shelf and approximately ~~186,900~~181,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, W & T Energy VI, LLC, Delaware limited liability companies, and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements – Note 56 – Joint Venture Drilling Program under Part I, Item 1 in this Quarterly Report.

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Recent Events

~~As COVID-19 vaccines have been more widely distributed, global economic activity is improving and~~While the current outlook for commodity prices is favorable and our operations are ~~currently at pre-pandemic levels. However, the energy markets remain subject to heightened levels of uncertainty as responses~~no longer significantly impacted by confinement restrictions related to COVID-19, the potential risk of disruption to our operations continues as the emergence of a new variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels. The ongoing COVID-19 outbreak continues to evolve and, ~~COVID-19 variants continue to evolve. We will continue to monitor~~during the ~~effects of the pandemic on the energy markets in the future.~~

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

~~During the second~~fourth quarter of 2021, a new variant emerged, 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~~Omicron variant. New variants of the ~~Term Loan were used~~virus continue to emerge and it is difficult to assess if such variants will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy because of the ongoing pandemic.

The recent invasion of parts of Ukraine by Russia and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia are world events that can result in potential commodities and securities market disruptions that could affect world oil and natural gas markets and the volatility of oil and gas commodity prices and thus impact the Company’s business, stock trading price and availability of capital. Additionally, while Organization of Petroleum Exporting Countries (“OPEC”) and other major oil producing countries (“OPEC Plus”) remained committed to steady and predictable production increases throughout 2022, it is difficult to determine whether it will change its production output policy or whether its members will remain committed to the production quotas set by the ~~Borrowers to (i) fund the acquisition~~organization as a result 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.these events.

~~This transaction is described in more detail under~~~~Financial Statements~~ –~~Note 4 – Mobile Bay Transaction~~~~, under Part 1, Item 1, of this Quarterly Report.~~
Known Trends and Uncertainties
Volatility in Oil, NGL and Natural Gas ~~Production and Commodity Pricing~~
Prices – Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. Our ~~production volumes~~realized sales prices received for the six months ended June 30, 2021 were comprised of 37.4% crude oil and condensate, 10.0% NGLs and 52.6% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one Boe forour crude oil, NGLs and natural gas has differed significantly in the past. For the six months ended June 30, 2021, our total revenues were 44.1% higher than the six months ended June 30, 2020 due to higher realized prices for crude oil, NGLs and natural gas, which were partially offset by lower volumes. See ~~Results of Operations – Six Months Ended June 30, 2021, Compared to the Six Months Ended June 30, 2020~~ ~~in this Item 2 for additional information.~~
~~Our operating results~~production are ~~strongly influenced by the price of the commodities that we produce and sell. The price of those commodities is~~ affected by ~~both~~many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international ~~factors, including domestic production. During the six months ended June 30, 2021,~~geopolitical and economic events. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our ~~average realized crude oil price was $60.88 per barrel. This is an increase of 71.2% from our average realized crude oil price of $35.57 per barrel during the six months ended June 30, 2020.~~ drilling program, production volumes or revenues.

Per the Energy Information Administration ("EIA"), average crude oil prices using ~~average West Texas Intermediate (“WTI”)~~the WTI daily spot ~~pricing~~price increased to ~~$62.21~~$95.18 per barrel during the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared to ~~$36.58~~$58.09 per barrel during the ~~six~~three months ended ~~June 30, 2020 representing an increase of 70.1%~~March 31, 2021 (63.8% increase). ~~Crude oil prices have recovered~~The NYMEX Henry Hub average daily natural gas spot price increased to ~~pre-pandemic levels from their April 2020 lows~~$4.67 per Mcf for the three months ended March 31, 2022 compared to $3.50 per Mcf during the three months ended March 31, 2021 (33.4% increase). These increases were primarily caused by increased demand related to supply uncertainties due to Russia’s invasion of Ukraine and general expanding economic activity.
Bureau of Ocean Energy Management (“BOEM”) Matters – In order to cover the ~~ongoing COVID-19 pandemic~~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 ~~vaccines~~Department of the Interior, 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 ~~been more widely distributed~~no outstanding BOEM orders related to supplemental financial assurance obligations. We and ~~economic activity has increased.~~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.

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~~Our average realized crude oil sales price differs~~Surety Bond Collateral – Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes or bonds associated with our appeals of Department of the Interior’s orders or demands have historically requested and received collateral from us, and may request additional collateral from us in the ~~WTI benchmark average crude price primarily due~~future, which could be significant and materially impact our liquidity. In addition, pursuant 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~~the terms of our ~~crude oil is produced offshore in~~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 ~~Gulf of Mexico and is characterized~~surety’s discretion. No additional demands were made to us by sureties during 2022 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 six months ended June 30, 2021 averaged ($0.23), $2.06, and $1.60 per barrel, respectively, and each average differential has changed ($0.13), $0.75, and $0.58 per barrel, respectively compared to the six months ended June 30, 2020.

Our average realized price of natural gas of $2.99 per Mcf for the six months ended June 30, 2021 was 61.5% higher than the average realized price of $1.85 per Mcf for the six months ended June 30, 2020. The average Henry Hub ("HH") daily natural gas spot price of $3.27 per Mcf for the six months ended June 30, 2021 was 74.7% higher than the average HH natural gas price of $1.87 per Mcf for the six months ended June 30, 2020. Per the EIA, this increase was caused by increased demand related to the increase in economic activity and is somewhat elevated by the much higher average price in February 2021 caused by much colder-than-normal temperatures across the country.

Our average realized price of NGLs of $24.94 per barrel for the six months ended June 30, 2021 was 169.6% higher than the average realized price of $9.25 per barrel for the six months ended June 30, 2020. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the six months ended June 30, 2021 compared to the six months ended June 30, 2020, average prices for domestic ethane increased by 81.4% and average domestic propane prices increased by 189.0% as measured using a price index for Mount Belvieu. The average prices for other domestic NGLs components increased from 87.5% to 107.3% for the six months ended June 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~~filing date of this Form 10-Q and ~~demand.~~

~~According~~we currently do not have surety bond collateral outstanding. The issuance of any additional surety bonds or other security to ~~Baker Hughes,~~satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third parties may require the ~~number~~posting of ~~working rigs drilling for oil~~cash collateral, which may be significant, and ~~natural gas on land in~~may require the U.S. as reported in their July 23, 2021 report was higher than a year ago, increasing to 491 rigs compared to 253 rigs a year ago. The oil rig count increased to 387 rigs compared to 180 rigs a year ago and the gas and miscellaneous rigs increased to 104 rigs from 73 a year ago. In the Gulfcreation of ~~Mexico, the number of working rigs was 17 rigs compared to 12 a year ago.~~escrow accounts.

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Results of Operations

~~The following tables set forth selected financial and operating data for~~Three Months Ended March 31, 2022 Compared to the ~~periods indicated (all values are net to our interest unless indicated otherwise):~~Three Months Ended March 31, 2021

Three Months Ended June 30,

Six Months Ended June 30,


2021

2020


Change

2021

2020


Change

(In thousands, except percentages and per share data)
Financial:

Revenues:

Oil

$
88,013

$
30,645

$
57,368

$
166,153

$
115,295

$
50,858
NGLs

8,833

1,917

6,916

18,193

8,369

9,824
Natural gas

32,470

21,364

11,106

68,679

50,664

18,015
Other

3,512

1,315

2,197

5,451

5,041

410
Total revenues

132,828

55,241

77,587

258,476

179,369

79,107
Operating costs and expenses:












Lease operating expenses

47,552

28,313

19,239

89,909

83,088

6,821
Production taxes

1,956

1,143

813

3,952

2,059

1,893
Gathering and transportation

4,824

3,301

1,523

9,143

8,750

393
Depreciation, depletion, amortization and accretion

30,952

29,483

1,469

57,589

68,609

(11,020)
General and administrative expenses

13,986

5,628

8,358

24,698

19,591

5,107
Derivative loss (gain)

81,440

15,414

66,026

106,020

(46,498)

152,518
Total costs and expenses

180,710

83,282

97,428

291,311

135,599

155,712
Operating (loss) income

(47,882)

(28,041)

(19,841)

(32,835)

43,770

(76,605)
Interest expense, net

16,530

14,816

1,714

31,564

31,926

(362)
Gain on debt transactions

—

(28,968)

28,968

—

(47,469)

47,469
Other expense, net

—

751

(751)

963

1,474

(511)
(Loss) income before income tax (benefit) expense

(64,412)

(14,640)

(49,772)

(65,362)

57,839

(123,201)
Income tax (benefit) expense

(12,740)

(8,736)

(4,004)

(12,944)

(2,237)

(10,707)
Net (loss) income

$
(51,672)

$
(5,904)

$
(45,768)

$
(52,418)

$
60,076

$
(112,494)
Basic and diluted (loss) earnings per common share

$
(0.36)

$
(0.04)

$
(0.32)

$
(0.37)

$
0.42

$
(0.79)

26Revenues

~~Table~~Our revenues are derived from the sale of ~~Contents~~our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Derivative loss” in our Condensed Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:

Three Months Ended March 31,

2022

2021
Oil
64.2
%

62.2
%
NGLs
7.2
%

7.4
%
Natural gas
26.9
%

28.9
%
Other
1.6
%

1.5
%

Three Months Ended June 30,

Six Months Ended June 30,


2021

2020


Change

2021

2020


Change
Operating: (1) (2)

Net sales:

Oil (MBbls)

1,352

1,414

(62)

2,729

3,241

(512)
NGLs (MBbls)

337

410

(73)

729

905

(176)
Natural gas (MMcf)

12,189

12,006

183

22,988

27,313

(4,325)
Total oil equivalent (MBoe)

3,721

3,826

(106)

7,290

8,699

(1,409)

Average daily equivalent sales (Boe/day)

40,888

42,047

(1,159)

40,278

47,795

(7,517)
Average realized sales prices:












Oil ($/Bbl)

$
65.11

$
21.67

$
43.44

$
60.88

$
35.57

$
25.31
NGLs ($/Bbl)

26.18

4.67

21.51

24.94

9.25

15.69
Natural gas ($/Mcf)

2.66

1.78

0.88

2.99

1.85

1.14
Oil equivalent ($/Boe)

34.75

14.09

20.66

34.71

20.04

14.67
Oil equivalent ($/Boe), including realized commodity derivatives)

38.89

8.19

30.69

37.94

16.36

21.58

Average per Boe ($/Boe):












Lease operating expenses

$
12.78

$
7.40

$
5.38

$
12.33

$
9.55

$
2.78
Gathering and transportation

1.30

0.86

0.44

1.25

1.01

0.24
Production costs

14.08

8.26

5.82

13.58

10.56

3.02
Production taxes

0.52

0.30

0.22

0.54

0.24

0.30
DD&A

8.32

7.71

0.61

7.90

7.89

0.01
G&A expenses

3.76

1.47

2.29

3.39

2.25

1.14
Operating costs

$
26.68

$
17.74

$
8.94

$
25.41

$
20.94

$
4.47
~~(1)~~
The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.
~~(2)~~
~~Some average figures and variance percentages in this table may not compute due to rounding.~~
The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and realized sales prices (which exclude the effect of hedging unless otherwise stated) for the three months ended March 31, 2022 and 2021:

Three Months Ended March 31,

2022

2021


Change


(In thousands, except realized price data)

Revenues:

Oil

$
122,702

$
78,140

$
44,562

NGLs

13,820

9,359

4,461

Natural gas

51,366

36,209

15,157

Other

3,116

1,939

1,177

Total revenues

$
191,004

$
125,647

$
65,357

Production Volumes:







Oil (MBbls)

1,304

1,377

(73)

NGLs (MBbls)

349

392

(43)

Natural gas (MMcf)

10,471

10,799

(328)

Total oil equivalent (MBoe)

3,398

3,569

(171)

Average daily equivalent sales (Boe/day)

37,756

39,657

(1,901)

Average realized sales prices:

Oil ($/Bbl)

$
94.10

$
56.73

$
37.37

NGLs ($/Bbl)

39.60

23.88

15.72

Natural gas ($/Mcf)

4.91

3.35

1.55

Oil equivalent ($/Boe)

55.29

34.66

20.63

Oil equivalent ($/Boe), including realized commodity derivatives

42.43

32.35

10.08

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

2723

Table of Contents

~~Three Months Ended June 30,~~Changes in average sales prices (which does not give effect to hedging) and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2022 and 2021 ~~Compared~~(in thousands):

Price

Volume

Total
Oil
$
48,707

$
(4,145)

$
44,562
NGLs

5,488

(1,028)

4,460
Natural gas

16,256

(1,098)

15,158

$
70,451

$
(6,271)

$
64,180

Realized Prices on the Sale of Oil,NGLs and Natural Gas – Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet (“LLS”), and Heavy Louisiana Sweet (“HLS”). Similar to crude oil prices, the differentials for our offshore crude oil have also been volatile in the past. The monthly average differentials of WTI versus Poseidon and HLS for 2022 declined on average by approximately $0.27 - $1.97 per barrel compared to 2021 for these types of crude oils while LLS increased by an average of $0.14 per barrel with the Poseidon having negative differential and the LLS and HLS having positive differentials as measured on an index basis. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.
Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the three months ended March 31, 2022 compared to the ~~Three Months Ended June 30, 2020~~
~~Revenues~~~~. The increase in oil revenues was attributable to an increase in average realized sales price per Bbl to $65.11 from $21.67 for the~~ three months ended ~~June 30,~~March 31, 2021, average prices for domestic ethane increased by 67.5% and ~~2020, respectively. This was partially offset~~average domestic propane prices increased by 45.0% as measured using a ~~decrease in oil sales volumes of 4.4%~~price index for Mount Belvieu. The average prices for other domestic NGLs components increased from 65.5% to 72.5% for the three months ended ~~June 30, 2021 as~~March 31, 2022 compared to the same period in 2021. We believe the ~~prior year.~~ change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.
The ~~increase in NGLs revenues was attributable~~actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to ~~an increase~~the Henry Hub which creates a minimal differential in the prices we receive for our production versus average ~~realized sales price per Bbl~~Henry Hub prices.
Oil,NGLs, and Natural Gas Volumes – Production volumes decreased by 171 MBoe to ~~$26.18 from $4.67 for~~3,398 MBoe in the ~~three months ended June 30, 2021 and 2020, respectively. This was partially offset by a 17.8% decrease in NGL sales volumes during the three months ended June 30, 2021 as~~first quarter of 2022 compared to the same period in ~~the prior year. The increase in natural gas revenues was attributable to an increase in the average realized price to $2.66 per Mcf from $1.78 per Mcf for the three months ended June 30,~~ 2021, ~~and 2020, respectively, and a 1.5% increase in volumes.~~
~~Overall, sales volumes decreased 2.7% on a Boe per day basis~~ primarily due to natural declines of producing wells and shut-ins related to well maintenance, atwhich were partially offset by the ~~Mahogany field~~acquisition of property interests during the first quarter of 2022 and ~~(to a lesser extent)~~other production deferrals during the ~~Mobile Bay area. We estimate that these shut-ins reduced the produced volumes~~first quarter of 2021. See Financial Statements – Note 4 – Acquisitions under Part I, Item 1 of this Quarterly Report for additional information. Deferred production for 2022 related to maintenance events collectively resulted in deferred production of 0.7 MMBoe, compared to 0.5 MMBoe in 2021.

Table of Contents

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the ~~three months ended June 30, 2021 by approximately 3,198 Boe per day as compared to 4,100 Boe per day for the three months ended June 30, 2020.~~

~~Revenues from oil~~periods presented and NGLs as a percent of our total revenues were 72.9% for the three months ended June 30, 2021 compared to 58.9% for the three months ended June 30, 2020. Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased to 40.2% for the three months ended June 30, 2021 compared to 21.6% for the three months ended June 30, 2020.corresponding changes:

Three Months Ended March 31,

2022

2021


Change

(In thousands, except per Boe data)
Operating expenses:

Lease operating expenses
$
43,411

$
42,357

$
1,054
Gathering, transportation and production taxes

5,267

6,315

(1,048)
Depreciation, depletion, amortization and accretion

30,911

26,637

4,274
General and administrative expenses

13,776

10,712

3,064
Total operating expenses
$
93,365

$
86,021

$
7,344

Average per Boe ($/Boe):






Lease operating expenses
$
12.78

$
11.87

$
0.91
Gathering, transportation and production taxes

1.55

1.77

(0.22)
DD&A

9.10

7.46

1.64
G&A expenses

4.05

3.00

1.05
Operating costs
$
27.48

$
24.10

$
3.38

Lease operating ~~expenses.~~expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased ~~$19.2~~$1.1 million ~~or 68.0%,~~to $43.4 million for the three months ended ~~June 30, 2021~~March 31, 2022 compared to $42.4 million for the three months ended ~~June 30, 2020.~~March 31, 2021. On a component basis, base lease operating expenses ~~increased $14.6~~decreased $0.4 million, workover expenses increased ~~$2.0~~$2.6 million, facilities maintenance expense increased ~~$1.4~~$1.2 million, and hurricane repairs ~~increased $1.2~~decreased $2.3 million.
Base lease operating expenses ~~increased~~decreased primarily due to ~~(i) higher~~decreased contract labor ~~equipment rental,~~ and ~~transportation costs of $3.1 million~~supplies at various ~~fields; (ii)~~fields offset by increased ~~incentive compensation costs~~expenses related to ~~field employees of $2.2 million; (iii) a reduction in credits to expense~~the fields acquired from prior period royalty adjustments of $2.4 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.ANKOR. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period.Lastly, during the three months ended March 31, 2021 we incurred ~~$1.2~~$2.3 million in expenses related to ~~hurricane~~ repairs ~~at various fields during the three months ended June 30, 2021~~associated with hurricanes that we did not incur during the ~~comparable prior year period.~~three months ended March 31, 2022.
~~Production taxes.~~ Gathering, transportation and production taxes~~Production~~ – Gathering, transportation and production taxes ~~increased $0.8~~decreased $1.0 million in the three months ended ~~June 30, 2021~~March 31, 2022 compared to the three months ended ~~June 30, 2020~~March 31, 2021 primarily due to a one-time adjustment of $2.7 million in the current quarter related to the calculation of production taxes payable. This decrease was partially offset by increased costs of $1.7 million due to the increase in realized natural gas prices and increased NGL prices ~~and to a lesser extent increased natural gas production volumes.~~
~~Gathering and transportation.~~ ~~Gathering and transportation expenses increased $1.5 million for~~in the three months ended ~~June 30, 2021~~March 31, 2022 as compared to ~~the three months ended June 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.~~period.
Depreciation, depletion, amortization and accretion (“DD&A”). – DD&A, which includes accretion for ARO, increased to ~~$8.32~~$9.10 per Boe for the three months ended ~~June 30, 2021~~March 31, 2022 from ~~$7.71~~$7.46 per Boe for the three months ended ~~June 30, 2020.~~March 31, 2021. On a nominal basis, DD&A increased ~~5.0%~~20.6%, or ~~$1.5~~$4.3 million for the three months ended ~~June 30, 2021~~March 31, 2022 as compared to the three months ended ~~June 30, 2020.~~March 31, 2021. The rate per Boe increased year-over-year mostly as a result of increases in the future development costs included in the depreciable base associated with an increase in economic proved undeveloped wells due to higher oil and gas prices compared to the ~~relatively~~ smaller increase in proved reserves over the comparable prior year period. This increase was partially offset by the decrease in production volumes.

2825

Table of Contents

General and administrative expenses (“G&A”). – G&A expense increased ~~$8.4~~$3.1 million, ~~or 148.5%,~~to $13.8 million for the three months ended ~~June 30, 2021~~March 31, 2022 as compared to $10.7 million for the three months ended ~~June 30, 2020.~~March 31, 2021. The increase was primarily due ~~to (i) increased incentive compensation expenses and payroll expenses of $1.8 million; (ii)~~ a ~~decrease of $5.0~~$2.1 million ~~in G&A credits related to~~employee retention credit recorded during the ~~PPP funds received in~~three months ended March 31, 2021 that did not recur during the ~~prior period; (iii)~~three months ended March 31, 2022 as well as an increase in ~~legal costs~~employee salaries and allowances for credit losses.

Other Income and Expense

The following table presents the components of ~~$0.4 million; (iv) a reduction in overhead allocations to partners (credits to expense) of $0.6 million,~~other income and ~~(v) increases of $0.6 million in other miscellaneous G&A~~ expense ~~items such as software licensing~~for the periods presented and ~~surety bond costs.~~corresponding changes:

Three Months Ended March 31,

2022

2021

Change

(In thousands)
Other income and expenses:

Derivative loss
$
79,997

$
24,578

$
55,419
Interest expense, net

19,883

15,034

4,849
Other expense, net

905

963

(58)
Income tax expense (benefit)

(689)

(203)

(486)

Derivative loss ~~(gain).~~ ~~The~~ – During the three months ended ~~June 30, 2021 includes~~March 31, 2022, an ~~$81.4~~$80.0 million derivative loss was recorded for crude oil and natural gas derivative contracts. Of the total derivative loss, approximately $36.3 million and $43.7 million were associated with the unrealized loss and realized loss, respectively. The realized derivative loss recorded in 2022 includes approximately $4.2 million of derivative premium amortization. The remaining realized derivative loss and unrealized derivative loss were primarily due to ~~increased~~ crude oil and natural gas prices ~~during June 2021~~rising throughout the three months ended March 31, 2022 as compared to prices ~~during March~~as of December 31, 2021, which decreased the estimated fair value of open contracts ~~between~~and decreased the ~~two measurement dates.~~ ~~The~~settlement value of closed contracts. During the three months ended ~~June 30, 2020 reflects~~March 31, 2021, a ~~$15.4~~$24.6 million derivative loss was recorded for crude oil and natural gas derivative contracts. The total derivative loss includes an $8.2 million realized derivative loss and a $16.3 million unrealized derivative loss. The realized derivative loss recorded in 2021 was primarily due to ~~increased~~ crude oil prices rising during ~~June 2020 compared~~the first quarter of 2021 from prior historic lows, which increased the settlement value of closed contracts; the realized derivative loss includes $0.5 million of derivative premium amortization. The unrealized derivative loss in 2021 was primarily due to crude oil prices ~~during March 2020,~~rising in the first quarter of 2021, which decreased the estimated fair value of open ~~crude oil contracts between the two measurement dates. Partially offsetting were realized gains from oil swap contracts where the price was below the contract strike price.~~ contracts.
Interest expense, net. – Interest expense, net, was ~~$16.5~~$19.9 million and ~~$14.8~~$15.0 million for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. The increase of ~~$1.7~~$4.9 million in ~~2021~~2022 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 $29.0 million was recorded related to the purchase of $45.1 million of principal of our outstanding Senior Second Lien Notes during the three months ended June 30, 2020. No such transactions occurred during the three months ended June 30, 2021.Loan.
Income tax ~~benefit.~~benefit – Our income tax benefit was ~~$12.7~~$0.7 million and ~~$8.7~~$0.2 million for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. For the three months ended ~~June 30,~~March 31, 2022 and 2021, our income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the three months ended June 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 ~~19.8%~~21.9% and 21.4% for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 59.7% for the three months ended June 30, 2020.~~respectively.
As of ~~June 30, 2021,~~March 31, 2022, the valuation allowance on our deferred tax assets was ~~$22.8~~$25.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

~~Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020~~
~~Revenues~~~~. The increase in oil revenues was attributable to an increase in the average realized sales price per Bbl to $60.88 from $35.57 for the six~~ months ended June 30, 2021 and 2020, respectively. This was partially offset by a decrease in oil sales volumes of 15.8%. The increase in NGLs revenues was attributable to a 169.6% increase in the average realized sales price for the six months ended June 30, 2021 compared to 2020. This was partially offset by a decrease in NGL sales volumes of 19.4% for the same period. The increase in natural gas revenues was attributable to a 61.5% increase in the average realized sales price for the six months ended June 30, 2021 compared to 2020. This was partially offset by a 15.8% decrease in natural gas sales volumes for the same period.

Overall, sales volumes decreased 15.7% on a Boe per day basis primarily due to shut-ins related to adverse weather events and well maintenance at various fields during the six months ended June 30, 2021. We estimate that these shut-ins reduced the produced volumes for the six months ended June 30, 2021 by approximately 4,200 Boe per day as compared to 3,800 Boe per day for the six months ended June 30, 2020.

2926

Table of Contents

Revenues from oil and NGLs as a percent of our total revenues were 71.3% for the six months ended June 30, 2021 compared to 68.9% for the six months ended June 30, 2020. Our average realized NGLs sales price as a percent of our average realized crude oil sales price increased to 41.0% for the six months ended June 30, 2021 compared to 26.0% for the six months ended June 30, 2020.

~~Lease operating expenses.~~ Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $6.8 million, or 8.2%, in the six months ended June 30, 2021 compared to the six months ended June 30, 2020. On a component basis, base lease operating expenses increased $1.5 million, workover expenses increased $1.0 million, facilities maintenance expense increased $0.5 million, and hurricane repairs increased $3.8 million.

Base lease operating expenses increased during the six months ended June 30, 2021 primarily due to (i) higher contract labor, equipment rental, and transportation costs of $1.3 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 $1.1 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) $4.3 million of reduced expenses related to fields that were no longer producing during the six months ended June 30, 2021. 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 six months ended June 30, 2021 that we did not incur during the prior year period.

~~Production taxes.~~ Production taxes increased $1.9 million during the six months ended June 30, 2021 compared to the three months ended June 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 $0.4 million for the six months ended June 30, 2021 compared to the six months ended June 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 $7.90 per Boe for the six months ended June 30, 2021 from $7.89 per Boe for the six months ended June 30, 2020. On a nominal basis, DD&A decreased 16.1%, or $11.0 million for the six months ended June 30, 2021 as compared to the six months ended June 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.

~~General and administrative expenses~~. G&A increased $5.1 million, or 26.1%, for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. The increase was primarily due to (i) a decrease of $5.0 million in G&A credits related to the PPP funds received in the prior period; (ii) a reduction in overhead allocations to partners (credits to expense) of $1.6 million; and (iii) an increase in legal costs of $1.2 million; partially offset by (i) the $2.1 million employee retention credit recognized during the three months ended March 31, 2021, and (ii) a net decrease of $0.6 million in payroll and incentive compensation expenses. 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.~~

~~Derivative loss (gain).~~ The six months ended June 30, 2021 reflects a $106.0 million derivative loss primarily due to increased crude oil prices and natural gas prices during June 2021 compared to prices during December 2020, which decreased the estimated fair value of open contracts between the two measurement dates. The six months ended June 30, 2020 reflects a $46.5 million derivative gain primarily due to realized gains on oil swap contracts where the price was below the strike price and due to decreased crude oil prices during June 2020 as compared to oil prices during December 2019, which increased the estimated fair value of open crude oil contracts between the two measurement dates.

~~Table of Contents~~

~~Interest expense, net~~. Interest expense, net, was $31.6 million and $31.9 million for the six months ended June 30, 2021 and 2020, respectively. The decrease is primarily due to reductions to outstanding borrowings (lower interest expense) under the Company Credit Agreement during 2021; partially offset by 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.

~~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 six months ended June 30, 2020. No such transactions occurred during the six months ended June 30, 2021.

~~Income tax benefit.~~ Our income tax benefit was $12.9 million and $2.2 million for the six months ended June 30, 2021 and 2020, respectively. For the six months ended June 30, 2021, our income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the six months ended June 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded as a result 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 19.8% for the six months ended June 30, 2021 and (3.9)% for the six months ended June 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.

The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement. As of ~~June 30, 2021,~~March 31, 2022, we had ~~$209.1~~$215.5 million cash on hand ~~no borrowings~~and $50.0 million available under our ~~Company~~ Credit Agreement, ~~and no maturities~~based on a borrowing base of ~~long-term debt until October 2023, other than scheduled quarterly amortization payments under the Term Loan (see~~ ~~Financial Statements – Note 2 – Debt~~~~, under Part I, Item 1 of this Quarterly Report for additional information). We currently~~$50.0 million. At current pricing levels, we expect our cash ~~on hand, net~~flows to cover our liquidity requirements for the foreseeable future and we expect additional financing sources to be available if needed. Additionally, we believe our access to the equity markets from our ATM Program, our reserve based lending currently available under our Credit Agreement, along with our cash ~~provided by operating activities and other available sources of~~position, will provide us with sufficient liquidity to ~~be sufficient~~continue our growth to meet our cash requirements over the next 12 months. We have recently agreed by amendment to our Company Credit Agreement to refrain from borrowing under our bank credit facility unless and until the next redetermination of our borrowing base, which is scheduled to occur on or about October 1, 2021, and the Company complies with certain revised hedging requirements. We expect that our borrowing base under our Company Credit Agreement will be adjusted in the next scheduled redetermination, including adjustments as a resulttake advantage of the ~~elimination of the Mobile Bay assets as collateral under the Company Credit Agreement.~~current commodity environment.

As of March 31, 2022, 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. We ~~are actively monitoring the debt capital markets, and we~~ intend to commence discussions promptly with potential lenders and institutional investors regarding potential refinancing of all or a portion of the Senior Second Lien Notes prior to maturity, although there is no assurance as to the terms of any such refinancing or whether or when such refinancing will occur. We also may seek ~~financing~~financings with longer tenors and market based covenants to continue to provide working and potential acquisition ~~capital.~~capital as well as provide funding for refinancing of all or a portion of our Senior Second Lien Notes. The terms of such ~~financing,~~financings, which may replace or augment our ~~current Company~~ Credit Agreement and refinance all or a portion of our Senior Second Lien Notes, may vary significantly from those under the Credit Agreement and our ~~current Company Credit Agreement.~~Senior Second Lien Notes.

Sources and Uses of Cash

Three Months Ended March 31,

2022

2021

Change

(In thousands)
Operating activities

$
27,537

$
44,964

$
(17,427)
Investing activities

(44,962)

(3,331)

(41,631)
Financing activities

(12,899)

(32,000)

19,101

Operating activities – Net cash provided by operating activities decreased $17.4 million for the three months ended March 31, 2022 compared to the corresponding period in 2021. This was primarily due to (i) an increase in derivative settlements payments, which decreased operating cash flows by $30.5 million, for the three months ended March 31, 2022 compared to $4.6 million in derivative cash settlement payments which decreased operating cash flows for the three months ended March 31, 2021; and (ii) an increase in settlements of AROs which decreased operating cash flows $5.5 million as compared to $1.0 million for the three months ended March 31, 2022 and 2021, respectively. Other items affecting operating cash flows were changes in operating assets and liabilities (excluding ARO settlements) which decreased operating cash flows by $47.3 million as compared a $2.2 million decrease in operating cash flows during the three months ended March 31, 2021, primarily related to higher oil and natural gas receivables balances due to higher realized prices and higher cash advance balances from joint venture partners, partially offset by higher payables and accrued liabilities balances.

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~~Sources and Uses of Cash~~

~~Cash~~ ~~Flow Overview~~

Sources (Uses) of Cash
(in thousands)

Six Months Ended June 30,

2021

2020

Change
Operating activities

$
46,194

$
93,478

$
(47,284)
Investing activities

(8,932)

(40,475)

31,543
Financing activities

128,160

(48,930)

177,090

~~Operating activities.~~ ~~Net~~These decreases in operating cash ~~provided~~flow were partially offset by ~~operating activities decreased $47.3~~the $65.4 million ~~for~~increase in revenue in the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 as compared to the corresponding period in 2020. This was primarily due to (i) cash derivative payments, the net of which decreased operating cash flows $41.1 million for the six months ended June 30, 2021 compared to cash derivative receipts, net, which increased operating cash flows $37.6 million for the six months ended June 30, 2020; and (ii) asset retirement obligation settlements which decreased operating cash flows by $11.2 million for the six months ended June 30, 2020 compared to $2.2 million for the six months ended June 30, 2020.
prior year period. Our combined average realized sales price per Boe increased by ~~73.2%~~59.5% for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared to the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, which caused total revenues to increase ~~$106.6~~ $70.5 million. The increase to revenues was slightly offset by a ~~16.2%~~4.8% decrease in total sales volumes during the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 as compared to the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, which ~~cause~~caused revenues to decrease ~~$27.9~~$6.3 million. Other items affecting operating cash flows were (i) higher receivable balances due to increases in realized prices, which decreased operating cash flows by $12.3 million for the six months ended June 30, 2021 compared to an increase of $39.7 million for the six months ended June 30, 2020; and (ii) decreased cash advance balances from joint venture partners, which decreased operating cash flows by $3.9 million for the six months ended June 30, 2021 compared to an increase of $5.9 million for the six months ended June 30, 2020. Other working capital items and share based compensation expense accounted for the remaining changes in net cash provided by operating activities.
Investing ~~activities.~~activities – Net cash used in investing activities ~~decreased $31.5~~increased $41.6 million for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared to the corresponding period in ~~2020. Our current year~~2021. The increase was primarily due to the acquisition of properties for $30.2 million along with other additional capital ~~budget is weighted toward~~spending during the ~~second half of 2021, therefore, investing activities have been lower in the six~~three months ended ~~June 30, 2021~~March 31, 2022 compared to the same period in ~~2020.~~ 2021.
Financing activities – Net cash used in investing activities for the six months ended June 30, 2021 included $3.1 million in working capital changes associated with capital expenditures incurred in 2020 but paid during the six months ended June 30, 2021.
~~Financing activities.~~ ~~Net cash provided by~~ financing activities ~~increased $177.1~~decreased $19.1 million for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared to the corresponding period in 2020. Net cash provided by financing activities for the six months ended June 30, 2021 was $128.2 million compared to net cash used in financing activities of $48.9 million for the six months ended June 30, 2020.2021. The net cash provided for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 included $12.6 million in repayments of the ~~proceeds from the term loan of $208.2 million, offset by repayment of $80.0 million of borrowings under the Company Credit Agreement.~~Term Loan. The ~~net cash used for the six~~three months ended ~~June 30, 2020 included repayment~~March 31, 2021 consisted of ~~$25.0 million~~repayments of ~~borrowings under~~ the Credit ~~Agreement and $23.9 million to purchase $72.5 million principal~~Facility of ~~Senior Second Lien Notes on the open market.~~$32.0 million.

~~Table of Contents~~

Derivative Financial ~~Instruments.~~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 six months ended June 30, 2021 we entered into derivative contracts for crude oil and natural gas for a portion of our future production.~~ See Financial Statements – Note 78 – Derivative Financial Instruments under Part I, Item 1 of this 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,

2022

2021
Crude Oil ($/Bbl):




Average realized sales price, before the effects of derivative settlements

$
94.10

$
56.73
Effects of realized commodity derivatives

(16.62)

(5.58)
Average realized sales price, including realized commodity derivatives

$
77.48

$
51.15
Natural Gas ($/Mcf)




Average realized sales price, before the effects of derivative settlements

$
4.91

$
3.35
Effects of realized commodity derivatives

(2.10)

(0.05)
Average realized sales price, including realized commodity derivatives

$
2.81

$
3.30

Income Taxes – For 2022, we expect substantially all of our income taxes to be deferred. We do not have any outstanding current income taxes receivable nor did we make any tax payments during the quarter ended March 31, 2022. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this 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, 2022 were $47.6 million compared to $1.6 million in the three months ended March 31, 2021. Overall capital expenditures increased by $46.0 million in the current quarter compared to the prior year quarter primarily due to the $30.2 million acquisition of property interests as described in Financial Statements – Note 4 – Acquisitions under Part I, Item 1 of this Quarterly Report. Our exploration and development activities increased $13.3 million (approximately $5.3 million of that increase was in the conventional shelf and $8.0 million in the deepwater area) as compared to the prior year, primarily due to the return to normal capital spending activities, which had been lower in the prior year in response to the COVID-19 pandemic and the related economic effects. Other leasehold costs increased $3.0 million, primarily related to seismic spending as compared to the prior year.

Table of Contents


Three Months Ended

Six Months Ended

June 30,

June 30,

June 30,

June 30,

2021

2020

2021

2020
Crude Oil ($/Bbl):








Average realized sales price, before the effects of derivative settlements

$
65.11

$
21.67

$
60.88

$
35.57
Effects of realized commodity derivatives

(8.86)

15.82

(7.20)

9.87
Average realized sales price, including realized commodity derivative

$
56.25

$
37.49

$
53.68

$
45.44
Natural Gas ($/Mcf)








Average realized sales price, before the effects of derivative settlements

$
2.66

$
1.78

$
2.99

$
1.85
Effects of realized commodity derivatives

(0.28)

0.02

(0.17)

—
Average realized sales price, including realized commodity derivative

$
2.38

$
1.80

$
2.82

$
1.85

The capital expenditures are included within Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheets and recorded on an accrual 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, 2022 included $2.6 million in working capital changes associated with capital expenditures incurred during the three months ended March 31, 2022, but not yet paid. Our capital expenditures for the three months ended March 31, 2022 were financed by cash flow from operations and cash on hand.

Acquisitions – As described in Financial Statements – Note 4 – Acquisitions under Part I, Item 1 of this Quarterly Report, on February 1, 2022, the Companyacquired working interest and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields from ANKOR. After normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date of July 1, 2021 to the close date), cash consideration of approximately $30.2 million was paid to the sellers. The transaction was funded using cash on hand.

Asset Retirement Obligations. – Each quarter, we review and revise our ARO estimates. Our ARO estimates as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 were ~~$404.0~~$475.0 million and ~~$392.7~~$424.5 million, respectively. The increase is primarily due to the acquisition of assets from ANKOR, moving additional projects to current term, and an increase in current pricing.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 2021 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 June 30, 2021. See~~ ~~Financial Statements – Note 9 –Income Taxes~~ ~~under Part I, Item 1 of this Quarterly Report for additional information.~~

~~Employee Retention Credit.~~ Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the six months ended June 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):~~

Six Months Ended June 30,


2021

2020

(In thousands)
Exploration (1)

$
1,309

$
1,686
Development (1)

902

10,274
Magnolia and Mobile Bay acquisitions

471

456
Seismic and other

3,174

2,177
Investments in oil and gas property/equipment – accrual basis

$
5,856

$
14,593

~~(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):~~

Six Months Ended June 30,


2021

2020

(In thousands)

Conventional shelf

$
101

$
9,391
Deepwater

2,110

2,569
Exploration and development capital expenditures – accrual basis

$
2,211

$
11,960

Our exploration and development spending decreased $9.7 million compared to prior year, primarily in the conventional shelf area, which includes Alabama state waters, due to the fact that our current year capital budget is weighted toward the second half of 2021. 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. Net cash used in investing activities for the six months ended June 30, 2021 included $3.1 million in working capital changes associated with capital expenditures incurred in 2020 but paid during the six months ended June 30, 2021. Our capital expenditures for the six months ended June 30, 2021 were financed by cash flow from operations and cash on hand.
Drilling Activity
We did not drill any wells in the ~~six~~three months ended ~~June 30, 2021.~~March 31, 2022. During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2022, we ~~drilled~~completed 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 56 –Joint Venture Drilling Program under Part I, Item 1 of this Form 10-Q for additional information.

34Debt

~~Table of Contents~~

~~Debt~~

Term ~~Loan.~~Loan – As of ~~June 30, 2021,~~March 31, 2022, we had ~~$215.0~~$178.2 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 Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers, and is not secured by any assets other than first lien security interests in the equity in the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of Subsidiary Borrowers (the Mobile Bay Properties). See Financial Statements – Note 2 –Debt under Part I, Item 1 of this ~~Form 10-Q~~Quarterly Report for additional information.
~~Company~~ Credit ~~Agreement~~Agreement. ~~. As of June 30, 2021,~~March 31, 2022, 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 six months ended June 30, 2021, we repaid $80.0 million of borrowings. The Company Credit Agreement matures on October 18, 2022.
Availability under our Company 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. As of June 30, 2021, we had no borrowings under our Company Credit Agreement and, in light of our expected near term capital needs and our current cash position, we have agreed not to make borrowings under the Company Credit Agreement unless and until the next scheduled redetermination of our borrowing base on or about October 1, 2021 and the Company complies with certain revised hedging requirements (pursuant to the Seventh Amendment executed on July 15, 2021). Generally, we must be in compliance with the covenants in our Company Credit Agreement in order to access borrowings under the Company Credit Agreement.
We anticipate an adjustment to our borrowing base under the Company Credit Agreement in the next scheduled redetermination primarily as a result of the elimination of the Mobile Bay assets as collateral under the Company Credit Agreement and pledge of such assets under the Subsidiary Credit Agreement.
Senior Second Lien ~~Notes.~~Notes – As of ~~June 30, 2021,~~March 31, 2022, 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.~~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 ~~June 30, 2021.~~March 31, 2022. 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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Table of Contents

~~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.Subsidiary Borrowers

~~Surety Bond Collateral.~~ ~~Some~~On May 19, 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries of W&T Offshore, Inc., through their parent, Aquasition Energy LLC (collectively, the ~~sureties that provide us surety bonds used~~Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for supplemental financial assurance purposes have historically requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. No additional demands were made to us by sureties during 2021 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

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

~~Insurance Coverage~~

~~Insurance Coverage.~~ We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $17.5 million on the conventional shelf properties and $12.5 million on the deepwater properties. Included within the $162.5 million aggregate limit is total loss only coverage on our Mahogany platform, which has no retention. The operational and named windstorm coverages are effective for one year beginning June 1, 2021. Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, 2021 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $35.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

Although we were able to renew our general and excess liability policies effective on May 1, 2021, and our Energy Package on June 1, 2021, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims. We do not carry business interruption insurance.

~~Contractual Obligations~~

~~As of June 30, 2021, there were no long-term drilling rig commitments. Except for scheduled utilization and our quarterly amortization payments under~~ the Term Loan ~~(see~~in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by A-I LLC and A-II LLC to fund the acquisition of the Mobile Bay Properties and the Midstream Assets, respectively, from the Company. The Term Loan is non-recourse to the Company and any subsidiaries other than the Aquasition Entities, and is secured by the first lien security interests in the equity of the Aquasition Entities and a first lien mortgage security interest in the Mobile Bay Properties. The See Financial Statements – Note 5 – Mobile Bay Transaction underPart II, Item 1 in this Quarterly Report for additional information.

At that time, we designated the Aquasition Entities as unrestricted subsidiaries under the Indenture governing our Senior Second Lien Notes (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the Senior Second Lien Notes. Under the Subsidiary Credit Agreement and related instruments, assets of the Aquasition Entities may not be available to mortgage or pledge as security to secure new indebtedness of the Company and its other subsidiaries. See Financial Statements – Note 2 – Debtunder Part I, Item 1 ofin this Quarterly Report for additional information.

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Table of Contents

~~Quarterly Report), other contractual~~Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Balance Sheet as of March 31, 2022 (in thousands):

Consolidated
Balance Sheet

Eliminations of Unrestricted Subsidiaries

Consolidated Balance Sheet of restricted subsidiaries
Assets






Current assets:






Cash and cash equivalents

$
215,475

$
(33,356)

$
182,119
Restricted cash

4,417

—

4,417
Receivables:






Oil and natural gas sales

92,693

(35,946)

56,747
Joint interest, net

14,221

7,159

21,380
Total receivables

106,914

(28,787)

78,127
Prepaid expenses and other assets

103,061

(203)

102,858
Total current assets

429,867

(62,346)

367,521
Oil and natural gas properties and other, net

731,692

(275,497)

456,195
Restricted deposits for asset retirement obligations

21,958

—

21,958
Deferred income taxes

103,238

—

103,238
Other assets

63,392

20,987

84,379
Total assets

$
1,350,147

$
(316,856)

$
1,033,291
Liabilities and Shareholders’ Deficit






Current liabilities:






Accounts payable

$
75,716

$
(22,989)

$
52,727
Undistributed oil and natural gas proceeds

33,575

(7,477)

26,098
Asset retirement obligations

67,274

—

67,274
Accrued liabilities

209,845

(86,217)

123,628
Current portion of long-term debt

39,881

(39,881)

—
Income tax payable

177

—

177
Total current liabilities

426,468

(156,564)

269,904
Long-term debt






Principal

690,808

(138,348)

552,460
Unamortized debt issuance costs

(10,372)

6,108

(4,264)
Long-term debt, net

680,436

(132,240)

548,196
Asset retirement obligations, less current portion

407,682

(56,001)

351,681
Other liabilities

84,833

(67,773)

17,060
Deferred income taxes

113

—

113
Common stock

1

—

1
Additional paid-in capital

553,175

—

553,175
Retained deficit

(778,394)

95,722

(682,672)
Treasury stock, at cost

(24,167)

—

(24,167)
Total shareholders’ deficit

(249,385)

95,722

(153,663)
Total liabilities and shareholders’ deficit

$
1,350,147

$
(316,856)

$
1,033,291

Table of Contents

Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Statement of Operations for the three months ended March 31, 2022 (in thousands):

Consolidated

Eliminations of Unrestricted Subsidiaries

Consolidated restricted subsidiaries
Revenues:

Oil

$
122,702

$
(195)

$
122,507
NGLs

13,820

(8,574)

5,246
Natural gas

51,366

(36,352)

15,014
Other

3,116

(2,394)

722
Total revenues

191,004

(47,515)

143,489
Operating expenses:






Lease operating expenses

43,411

(10,326)

33,085
Gathering, transportation and production taxes

5,267

(3,259)

2,008
Depreciation, depletion, amortization and accretion

30,911

(5,686)

25,225
General and administrative expenses

13,776

(316)

13,460
Total operating expenses

93,365

(19,587)

73,778
Operating (loss) income

97,639

(27,928)

69,711

Interest expense, net

19,883

(4,778)

15,105
Derivative loss (gain)

79,997

(96,158)

(16,161)
Other expense, net

905

—

905
(Loss) income before income taxes

(3,146)

73,008

69,862
Income tax benefit

(689)

—

(689)
Net (loss) income

$
(2,457)

$
73,008

$
70,551

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Subsidiary Borrowers for the three months ended March 31, 2022:

Three Months Ended March 31,
Production Volumes:
2022
Oil (MBbls)
4
NGLs (MBbls)
226
Natural gas (MMcf)
7,330
Total oil equivalent (MBoe)
1,452

Table of Contents

Contractual Obligations

As of March 31, 2022, there were no long-term drilling rig commitments. Contractual obligations as of ~~June 30, 2021~~March 31, 2022 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 2021 Annual ~~Report on Form 10-K for the year ended December 31, 2020.~~Report.

Critical Accounting Policies and Estimates

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

There have been no changes to our critical accounting policies which are summarized in Management’s Discussion and Analysis of Financial ~~Statements~~Condition and ~~Supplementary Data~~Results of Operations under Part II, Item 87 of our ~~2020~~2021 Annual Report. ~~See~~ ~~Financial Statements – Note 1 – Basis of Presentation~~ ~~under Part 1, Item 1 of this Quarterly Report for additional information.~~

Recent Accounting Pronouncements

~~See~~ ~~Financial Statements~~ – ~~Note 1~~ – ~~Basis of Presentation~~ ~~under Part 1, Item 1~~, ~~of this Form 10-Q.~~There was no recently issued accounting standards material to us.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about the types of market risks for the ~~six months ended June 30, 2021~~March 31, 2022 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our ~~2020~~2021 Annual Report. In addition, the information contained herein should be read in conjunction with the related disclosures in our ~~2020~~2021 Annual Report.

Item 4. Controls and Procedures
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO have each concluded that as of ~~June 30, 2021,~~March 31, 2022, 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 ~~June 30, 2021,~~March 31, 2022, 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.

3733

Table of Contents

PART II – OTHER INFORMATION
Item 1. Legal Proceedings
See Financial Statements – Note 1112 – 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
New climate disclosure rules proposed by the SEC may increase our costs of compliance and adversely impact our business.

On March 21, 2022, the U.S. Securities and Exchange Commission proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the proposed rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. The SEC proposes certain phase-in compliance dates under the proposed rule for disclosure of Scope 1, 2, and 3 greenhouse gas (“GHG”) emissions. As initially proposed, accelerated filers such as us would be obligated to disclose Scope 1 and 2 GHG emissions for fiscal year 2024 in the 2025 filing year and disclose Scope 3 GHG emissions for fiscal year 2025 in the 2026 filing year. For more information on our risks related to Environmental, Social and Governance matters and attention to climate change, seeRisk Factors “Increasing attention to Environmental, Social and Governance (“ESG”) matters may impact our business” and “The threat of climate change could result in increased costs and reduced demand for the oil and natural gas we produce, which could have a material adverse effect on our business, results of operations, financial condition and cash flows” included in Part I, Item 1A of our 2021 Annual Report.

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~~2021 Annual Report, together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our ~~2020~~2021 Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.

Item 4. Mine Safety Disclosures
None.

3834

Table of Contents

Item 5. Other Information
None.
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 and Sixth Amendment to Sixth~~Second Amended and Restated ~~Credit Agreement, dated May 19, 2021, by and among~~Bylaws of W&T Offshore, Inc.~~, the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit party thereto and Toronto Dominion (Texas) LLC, individually and as agent.~~ (Incorporated by reference to ~~exhibit 10.1~~Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed ~~on May 25, 2021~~March 22, 2019 (File No. 001-32414).)
10.2*

Waiver and Seventh Amendment to Sixth Amended and Restated Credit Agreement, dated June 30, 2021by and among W&T Offshore, Inc. the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit party thereto and Toronto Dominion (Texas) LLC, individually and as agent.

10.3*10.1

Tenth Amendment to Sixth Amended and Restated Credit Agreement dated ~~May 19, 2021, by and among Aquasition LLC,~~effective as ~~Borrower, Aquasition II LLC, as Co-Borrower, and Munich Re Reserve Risk Financing, as the lenders party thereto.~~of March 8, 2022.

10.4*

~~Management Services Agreement, dated May 19, 2021, by and among A-I, LLC, A-II LLC, and W&T Offshore, Inc.~~

10.5*

~~Restricted Stock Unit Agreement (Service-based Vesting), pursuant to the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.~~

10.6*

~~Restricted Stock Unit Agreement (Performance Vesting), pursuant to the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan~~.

31.1*

Section 302 Certification of Chief Executive Officer

31.2*

Section 302 Certification of Chief Financial Officer

32.1*

Section 906 Certification of Chief Executive Officer and Chief Financial Officer

101.INS*

Inline XBRL Instance Document

101.SCH*

Inline XBRL Schema Document

101.CAL*

Inline XBRL Calculation Linkbase Document

~~Table of Contents~~

101.DEF*		Inline XBRL Definition Linkbase Document

101.LAB*		Inline XBRL Label Linkbase Document

101.PRE*		Inline XBRL Presentation Linkbase Document

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

*	Filed or furnished herewith.

4035

Table of Contents

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 ~~August~~May 4, ~~2021.~~2022.

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

4136


	June 30, 2021		December 31, 2020
Derivatives – current (1)	$	14,021	$	2,752
Unamortized insurance/bond premiums		6,195		4,717
Prepaid deposits related to royalties		4,544		4,473
Prepayment to vendors		4,775		1,429
Other		1,170		461
Prepaid expenses and other assets	$	30,705	$	13,832


	February 1, 2022
Oil and natural gas properties and other, net	$	50,450
Restricted deposits for asset retirement obligations		6,196
Asset retirement obligations		(26,493)
Allocated purchase price	$	30,153


	Three Months Ended March 31,
	2022
Asset retirement obligations, beginning of period	$	424,495
Liabilities settled		(5,492)
Accretion of discount		6,236
Liabilities incurred and assumed through acquisition		26,493
Revisions of estimated liabilities ⁽¹⁾		23,224
Asset retirement obligations, end of period		474,956
Less current portion		(67,274)
Long-term	$	407,682


Balances, December 31, 2020	$	392,704
Liabilities settled		(11,213)
Accretion of discount		11,895
Liabilities incurred and assumed through acquisition		417
Revisions of estimated liabilities		10,200
Balances, June 30, 2021		404,003
Less current portion		(23,888)
Long-term	$	380,115



		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)		($/Bbl)(1)		($/Bbl)(1)		($/Bbl)(1)
Jul 2021 - Dec 2021	swap	4,000	736,000	$	42.06	$	—	$	—
Jul 2021 - Dec 2021	collar	200	36,800	$	—	$	40.00	$	54.90
Jul 2021 - Feb 2022	collar	2,024	491,733	$	—	$	38.81	$	57.24
Jan 2022 - Feb 2022	swap	3,000	177,000	$	42.98	$	—	$	—
Mar 2022 - May 2022	swap	2,044	188,006	$	42.33	$	—	$	—
Mar 2022 - May 2022	collar	2,000	184,000	$	—	$	35.00	$	48.50
Mar 2022 - Sept 2022	swap	1,615	345,638	$	54.53	$	—	$	—
Mar 2022 - Sept 2022	collar	1,615	345,638	$	—	$	45.00	$	62.50
Oct 2022	swap	2,172	67,332	$	58.50	$	—		—
Oct 2022	collar	2,172	67,332	$	—	$	46.00		66.50
Nov 2022	swap	2,176	65,280	$	58.25	$	—		—
Nov 2022	collar	2,176	65,280	$	—	$	46.00		66.30

Natural Gas - Henry Hub (NYMEX)		(MMbtu)(2)	(MMbtu)(2)		($/MMbtu)(2)		($/MMbtu)(2)		($/MMbtu)(2)
Jul 2021 - Dec 2021	collar	30,000	5,520,000	$	—	$	2.18	$	3.00
Jul 2021 - Dec 2021	swap	10,000	1,840,000	$	2.62	$	—	$	—
Jul 2021 - Dec 2021	call	40,000	7,360,000	$	—	$	—	$	3.50
Jul 2021 - Dec 2022	collar	40,000	21,960,000	$	—	$	1.83	$	3.00
Jul 2021 - Dec 2022	call	40,000	21,960,000	$	—	$	—	$	3.00
Jan 2022 - Feb 2022	collar	30,000	1,830,000	$	—	$	2.20	$	4.50
Jan 2022 - Dec 2022	call	37,000	13,505,000	$	—	$	—	$	3.50
Jan 2022	swap	20,000	620,000	$	2.79	$	—	$	—
Feb 2022	swap	30,000	840,000	$	2.79	$	—	$	—
Mar 2022 - May 2022	collar	10,000	920,000	$	—	$	2.25	$	3.40
Mar 2022 - May 2022	swap	10,544	970,075	$	2.69	$	—	$	—
Apr 2022 - Sept 2022	swap	12,428	2,274,311	$	2.44	$	—	$	—
Oct 2022	swap	16,129	499,999	$	2.56	$	—	$	—
Nov 2022	swap	17,570	527,100	$	2.63	$	—	$	—
Jan 2023 - Dec 2023	call	70,000	25,550,000	$	—	$	—	$	3.50
Jul 2021 - Mar 2025 (3)	swap	72,920	99,900,000	$	2.63	$	—	$	—
Apr 2025 - Apr 2028 (3)	put	55,684	62,700,000	$	—	$	2.35	$	—


	Restricted Stock Units
		Weighted
		Average
		Grant Date Fair
	Units	Value Per Unit
Nonvested, December 31, 2020	763,688	$	4.51
Granted	698,301		4.72
Vested	—		—
Forfeited	(19,880)		4.51
Nonvested, June 30, 2021	1,442,109		4.61


		Restricted
		Shares
2021		743,808
2022		232,767
2023		232,767
2024		232,767
Total		1,442,109


	Performance Share Units
		Weighted
		Average
		Grant Date Fair
	Units	Value Per Unit
Nonvested, December 31, 2020	—	$	—
Granted	388,908		5.57
Vested	—		—
Forfeited	—		—
Nonvested, June 30, 2021	388,908		5.57


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


	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, June 30, 2021	70,226		3.67


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


	Price		Volume		Total
Oil	$	48,707	$	(4,145)	$	44,562
NGLs		5,488		(1,028)		4,460
Natural gas		16,256		(1,098)		15,158
	$	70,451	$	(6,271)	$	64,180


	Sources (Uses) of Cash (in thousands)
	Six Months Ended June 30,
	2021		2020			Change
Operating activities	$	46,194	$	93,478	$	(47,284)
Investing activities		(8,932)		(40,475)		31,543
Financing activities		128,160		(48,930)		177,090


	Three Months Ended				Six Months Ended
	June 30,		June 30,		June 30,		June 30,
	2021		2020		2021		2020
Crude Oil ($/Bbl):
Average realized sales price, before the effects of derivative settlements	$	65.11	$	21.67	$	60.88	$	35.57
Effects of realized commodity derivatives		(8.86)		15.82		(7.20)		9.87
Average realized sales price, including realized commodity derivative	$	56.25	$	37.49	$	53.68	$	45.44
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements	$	2.66	$	1.78	$	2.99	$	1.85
Effects of realized commodity derivatives		(0.28)		0.02		(0.17)		—
Average realized sales price, including realized commodity derivative	$	2.38	$	1.80	$	2.82	$	1.85


	Consolidated Balance Sheet		Eliminations of Unrestricted Subsidiaries		Consolidated Balance Sheet of restricted subsidiaries
Assets
Current assets:
Cash and cash equivalents	$	215,475	$	(33,356)	$	182,119
Restricted cash		4,417		—		4,417
Receivables:
Oil and natural gas sales		92,693		(35,946)		56,747
Joint interest, net		14,221		7,159		21,380
Total receivables		106,914		(28,787)		78,127
Prepaid expenses and other assets		103,061		(203)		102,858
Total current assets		429,867		(62,346)		367,521
Oil and natural gas properties and other, net		731,692		(275,497)		456,195
Restricted deposits for asset retirement obligations		21,958		—		21,958
Deferred income taxes		103,238		—		103,238
Other assets		63,392		20,987		84,379
Total assets	$	1,350,147	$	(316,856)	$	1,033,291
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	75,716	$	(22,989)	$	52,727
Undistributed oil and natural gas proceeds		33,575		(7,477)		26,098
Asset retirement obligations		67,274		—		67,274
Accrued liabilities		209,845		(86,217)		123,628
Current portion of long-term debt		39,881		(39,881)		—
Income tax payable		177		—		177
Total current liabilities		426,468		(156,564)		269,904
Long-term debt
Principal		690,808		(138,348)		552,460
Unamortized debt issuance costs		(10,372)		6,108		(4,264)
Long-term debt, net		680,436		(132,240)		548,196
Asset retirement obligations, less current portion		407,682		(56,001)		351,681
Other liabilities		84,833		(67,773)		17,060
Deferred income taxes		113		—		113
Common stock		1		—		1
Additional paid-in capital		553,175		—		553,175
Retained deficit		(778,394)		95,722		(682,672)
Treasury stock, at cost		(24,167)		—		(24,167)
Total shareholders’ deficit		(249,385)		95,722		(153,663)
Total liabilities and shareholders’ deficit	$	1,350,147	$	(316,856)	$	1,033,291


		Consolidated		Eliminations of Unrestricted Subsidiaries		Consolidated restricted subsidiaries
Revenues:
Oil	$	122,702	$	(195)	$	122,507
NGLs		13,820		(8,574)		5,246
Natural gas		51,366		(36,352)		15,014
Other		3,116		(2,394)		722
Total revenues		191,004		(47,515)		143,489
Operating expenses:
Lease operating expenses		43,411		(10,326)		33,085
Gathering, transportation and production taxes		5,267		(3,259)		2,008
Depreciation, depletion, amortization and accretion		30,911		(5,686)		25,225
General and administrative expenses		13,776		(316)		13,460
Total operating expenses		93,365		(19,587)		73,778
Operating (loss) income		97,639		(27,928)		69,711

Interest expense, net		19,883		(4,778)		15,105
Derivative loss (gain)		79,997		(96,158)		(16,161)
Other expense, net		905		—		905
(Loss) income before income taxes		(3,146)		73,008		69,862
Income tax benefit		(689)		—		(689)
Net (loss) income	$	(2,457)	$	73,008	$	70,551


		Three Months Ended March 31,
Production Volumes:	2022
Oil (MBbls)		4
NGLs (MBbls)		226
Natural gas (MMcf)		7,330
Total oil equivalent (MBoe)		1,452


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 and Sixth Amendment to Sixth~~Second Amended and Restated ~~Credit Agreement, dated May 19, 2021, by and among~~Bylaws of W&T Offshore, Inc.~~, the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit party thereto and Toronto Dominion (Texas) LLC, individually and as agent.~~ (Incorporated by reference to ~~exhibit 10.1~~Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed ~~on May 25, 2021~~March 22, 2019 (File No. 001-32414).)

10.2*		Waiver and Seventh Amendment to Sixth Amended and Restated Credit Agreement, dated June 30, 2021by and among W&T Offshore, Inc. the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit party thereto and Toronto Dominion (Texas) LLC, individually and as agent.

10.3*10.1		Tenth Amendment to Sixth Amended and Restated Credit Agreement dated ~~May 19, 2021, by and among Aquasition LLC,~~effective as ~~Borrower, Aquasition II LLC, as Co-Borrower, and Munich Re Reserve Risk Financing, as the lenders party thereto.~~of March 8, 2022.

10.4*		~~Management Services Agreement, dated May 19, 2021, by and among A-I, LLC, A-II LLC, and W&T Offshore, Inc.~~

10.5*		~~Restricted Stock Unit Agreement (Service-based Vesting), pursuant to the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.~~

10.6*		~~Restricted Stock Unit Agreement (Performance Vesting), pursuant to the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan~~.

31.1*		Section 302 Certification of Chief Executive Officer

31.2*		Section 302 Certification of Chief Financial Officer

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

101.INS*		Inline XBRL Instance Document

101.SCH*		Inline XBRL Schema Document

101.CAL*		Inline XBRL Calculation Linkbase Document


	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