UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~September~~June 30, ~~2022~~2023

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

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Texas		72-1121985
(State or other jurisdiction of ~~incorporation)~~incorporation or organization)		(~~IRS~~I.R.S. Employer Identification Number)

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

Registrant’s telephone number, including area code:(713) 626-8525

~~(Registrant’s telephone number, including area code)~~

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

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	☐

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 ☑

As of ~~October~~July 31, ~~2022~~2023 there were ~~143,161,608~~146,480,637 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 INFORMATION		1

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~2022	1
	Condensed Consolidated Statements of Operations for the ~~Three and Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022	2
	Condensed Consolidated Statements of Changes in Shareholders’ ~~Deficit~~Equity (Deficit) for the ~~Three and Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023 and ~~202~~20221	3
	Condensed Consolidated Statements of Cash Flows for the ~~Three and Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2522
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4440
Item 4.	Controls and Procedures	4440

PART II – OTHER INFORMATION		4541
Item 1.	Legal Proceedings	4541
Item 1A.	Risk Factors	4541
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4641
Item 3.	Defaults Upon Senior Securities	4641
Item 4.	Mine Safety Disclosures	4641
Item 5.	Other Information	4641
Item 6.	Exhibits	4741

SIGNATURE		4843

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

September 30,

December 31,


2022

2021
Assets




Current assets:




Cash and cash equivalents

$
447,130

$
245,799
Restricted cash

4,417

4,417
Receivables:

Oil and natural gas sales

89,195

54,919
Joint interest, net

16,815

9,745
Total receivables

106,010

64,664
Prepaid expenses and other assets (Note 1)

53,014

43,379
Total current assets

610,571

358,259

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

729,958

665,252

Restricted deposits for asset retirement obligations

21,760

16,019
Deferred income taxes

62,334

102,505
Other assets (Note 1)

65,681

51,172
Total assets

$
1,490,304

$
1,193,207
Liabilities and Shareholders’ Deficit




Current liabilities:




Accounts payable

$
72,051

$
67,409
Undistributed oil and natural gas proceeds

59,518

36,243
Advances from joint interest partners

3,017

15,072
Asset retirement obligations

54,886

56,419
Accrued liabilities (Note 1)

154,236

106,140
Current portion of long-term debt

35,450

42,960
Income tax payable

1,613

133
Total current liabilities

380,771

324,376

Long-term debt, net (Note 2)

665,973

687,938
Asset retirement obligations, less current portion

398,724

368,076
Other liabilities (Note 1)

94,841

55,389
Deferred income taxes

113

113
Commitments and contingencies (Note 12)

4,899

4,495
Shareholders’ deficit:




Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at September 30, 2022 and December 31, 2021

—

—
Common stock, $0.00001 par value; 200,000 shares authorized; 146,031 issued and 143,162 outstanding at September 30, 2022; 145,732 issued and 142,863 outstanding at December 31, 2021

1

1
Additional paid-in capital

557,386

552,923
Retained deficit

(588,237)

(775,937)
Treasury stock, at cost; 2,869 shares at September 30, 2022 and December 31, 2021

(24,167)

(24,167)
Total shareholders’ deficit

(55,017)

(247,180)
Total liabilities and shareholders’ deficit

$
1,490,304

$
1,193,207


	June 30,		December 31,
	2023		2022
Assets
Current assets:
Cash and cash equivalents	$	171,627	$	461,357
Restricted cash		4,417		4,417
Receivables:
Oil and natural gas sales		41,342		66,146
Joint interest, net		13,875		14,000
Income taxes		1,941		—
Total receivables		57,158		80,146
Prepaid expenses and other assets (Note 1)		21,365		24,343
Total current assets		254,567		570,263

Oil and natural gas properties and other, net (Note 1)		737,740		735,215

Restricted deposits for asset retirement obligations		22,092		21,483
Deferred income taxes		45,700		57,280
Other assets (Note 1)		42,118		47,549
Total assets	$	1,102,217	$	1,431,790
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	67,293	$	65,158
Undistributed oil and natural gas proceeds		31,178		41,934
Advances from joint interest partners		3,110		3,181
Asset retirement obligations (Note 7)		37,763		25,359
Accrued liabilities (Note 1)		39,323		74,041
Current portion of long-term debt, net		30,550		582,249
Income tax payable		10		412
Total current liabilities		209,227		792,334
Long-term debt (Note 2)
Principal		382,697		114,158
Unamortized debt issuance costs		(9,676)		(2,970)
Long-term debt, net (Note 2)		373,021		111,188

Asset retirement obligations, less current portion (Note 7)		443,069		441,071
Other liabilities (Note 1)		35,041		59,134
Deferred income taxes		72		72
Commitments and contingencies (Note 11)		16,996		20,357
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at June 30, 2023 and December 31, 2022		—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 149,350 issued and 146,481 outstanding at June 30, 2023; 149,002 issued and 146,133 outstanding at December 31, 2022		1		1
Additional paid-in capital		579,849		576,588
Retained deficit		(530,892)		(544,788)
Treasury stock, at cost; 2,869 shares at June 30, 2023 and December 31, 2022		(24,167)		(24,167)
Total shareholders’ equity		24,791		7,634
Total liabilities and shareholders’ equity	$	1,102,217	$	1,431,790

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021		2023		2022		2023		2022
Revenues:
Oil	$	130,560	$	74,265	$	412,526	$	240,418	$	89,982	$	159,264	$	186,982	$	281,966
NGLs		16,875		12,205		47,430		30,397		10,385		16,735		18,180		30,555
Natural gas		113,673		45,137		257,452		113,816		23,438		92,413		48,242		143,779
Other		5,377		2,339		13,889		7,790		2,376		5,396		4,502		8,512
Total revenues		266,485		133,946		731,297		392,421		126,181		273,808		257,906		464,812
Operating expenses:
Lease operating expenses		59,010		39,490		155,397		129,399		66,021		52,976		131,207		96,387
Gathering, transportation and production taxes		12,199		6,593		26,647		19,687		6,802		9,181		12,938		14,448
Depreciation, depletion, and amortization		27,493		20,818		79,848		66,511		28,177		27,679		50,801		52,354
Asset retirement obligations accretion		6,620		5,473		19,536		17,368		7,717		6,681		15,227		12,917
General and administrative expenses		23,047		13,391		51,790		38,090		17,393		14,967		37,312		28,743
Total operating expenses		128,369		85,765		333,218		271,055		126,110		111,484		247,485		204,849
Operating income		138,116		48,181		398,079		121,366		71		162,324		10,421		259,963

Interest expense, net		16,849		18,910		54,915		50,474		10,323		18,183		25,036		38,066
Derivative loss		38,749		73,137		109,892		179,156
Derivative (gain) loss, net										(829)		(8,854)		(40,069)		71,143
Other (income) expense, net		(600)		—		(1,229)		964		(311)		(1,534)		(78)		(629)
Income (loss) before income taxes		83,118		(43,866)		234,501		(109,228)		(9,112)		154,529		25,532		151,383
Income tax expense (benefit)		16,397		(5,902)		46,801		(18,846)
Net income (loss)	$	66,721	$	(37,964)	$	187,700	$	(90,382)
Income tax expense										2,997		31,093		11,636		30,404
Net (loss) income									$	(12,109)	$	123,436	$	13,896	$	120,979

Net income (loss) per common share:
Net income per common share:
Basic	$	0.46	$	(0.27)	$	1.30	$	(0.64)	$	(0.08)	$	0.86	$	0.09	$	0.85
Diluted	$	0.46	$	(0.27)	$	1.30	$	(0.64)	$	(0.08)	$	0.85	$	0.09	$	0.84

Weighted average common shares outstanding
Weighted average common shares outstanding:
Basic		143,116		142,297		143,026		142,231		146,452		143,020		146,435		142,981
Diluted		145,882		142,297		144,696		142,231		146,452		144,525		149,045		144,094

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ ~~DEFICIT~~EQUITY (DEFICIT)

(In thousands)

(Unaudited)

Common Stock

Additional








Total

Outstanding

Paid-In

Retained

Treasury Stock

Shareholders’


Shares

Value

Capital

Deficit

Shares

Value

Deficit
Balances at June 30, 2022

143,155

$
1

$
554,755

$
(654,958)

2,869

$
(24,167)

$
(124,369)
Share-based compensation

—

—

2,645

—

—

—

2,645
Stock Issued

7

—

—

—

—

—

—
RSUs surrendered for payroll taxes

—

—

(14)

—

—

—

(14)
Net income

—

—

—

66,721

—

—

66,721
Balances at September 30, 2022

143,162

$
1

$
557,386

$
(588,237)

2,869

$
(24,167)

$
(55,017)

Common Stock

Additional








Total

Outstanding

Paid-In

Retained

Treasury Stock

Shareholders’


Shares

Value

Capital

Deficit

Shares

Value

Deficit
Balances at June 30, 2021

142,367

$
1

$
551,260

$
(786,877)

2,869

$
(24,167)

$
(259,783)
Share-based compensation

—

—

858

—

—

—

858
Stock Issued

—

—

—

—

—

—

—
Net loss

—

—

—

(37,964)

—

—

(37,964)
Balances at September 30, 2021

142,367

$
1

$
552,118

$
(824,841)

2,869

$
(24,167)

$
(296,889)


	Common Stock			Additional							Total		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		Equity
Balances at December 31, 2021	142,863	$	1	$	552,923	$	(775,937)	2,869	$	(24,167)	$	(247,180)
Balances at March 31, 2023													146,461	$	1	$	577,787	$	(518,783)	2,869	$	(24,167)	$	34,838
Share-based compensation	—		—		5,179		—	—		—		5,179	—		—		2,087		—	—		—		2,087
Stock Issued	299		—		—		—	—		—		—
Stock issued													20		—		—		—	—		—		—
RSUs surrendered for payroll taxes	—		—		(716)		—	—		—		(716)	—		—		(25)		—	—		—		(25)
Net income	—		—		—		187,700	—		—		187,700
Balances at September 30, 2022	143,162	$	1	$	557,386	$	(588,237)	2,869	$	(24,167)	$	(55,017)
Net loss													—		—		—		(12,109)	—		—		(12,109)
Balances at June 30, 2023													146,481	$	1	$	579,849	$	(530,892)	2,869	$	(24,167)	$	24,791

Common Stock

Additional








Total

Outstanding

Paid-In

Retained

Treasury Stock

Shareholders’


Shares

Value

Capital

Deficit

Shares

Value

Deficit
Balances at December 31, 2020

142,305

$
1

$
550,339

$
(734,459)

2,869

$
(24,167)

$
(208,286)
Share-based compensation

—

—

1,779

—

—

—

1,779
Stock Issued

62

—

—

—

—

—

—
Net loss

—

—

—

(90,382)

—

—

(90,382)
Balances at September 30, 2021

142,367

$
1

$
552,118

$
(824,841)

2,869

$
(24,167)

$
(296,889)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at March 31, 2022	143,012	$	1	$	553,175	$	(778,394)	2,869	$	(24,167)	$	(249,385)
Share-based compensation	—		—		2,014		—	—		—		2,014
Stock issued	143		—		—		—	—		—		—
RSUs surrendered for payroll taxes	—		—		(434)		—	—		—		(434)
Net income	—		—		—		123,436	—		—		123,436
Balances at June 30, 2022	143,155	$	1	$	554,755	$	(654,958)	2,869	$	(24,167)	$	(124,369)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Equity
Balances at December 31, 2022	146,133	$	1	$	576,588	$	(544,788)	2,869	$	(24,167)	$	7,634
Share-based compensation	—		—		4,009		—	—		—		4,009
Stock issued	348		—		—		—	—		—		—
RSUs surrendered for payroll taxes	—		—		(748)		—	—		—		(748)
Net income	—		—		—		13,896	—		—		13,896
Balances at June 30, 2023	146,481	$	1	$	579,849	$	(530,892)	2,869	$	(24,167)	$	24,791


	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	—		—		2,534		—	—		—		2,534
Stock issued	292		—		—		—	—		—		—
RSUs surrendered for payroll taxes	—		—		(702)		—	—		—		(702)
Net income	—		—		—		120,979	—		—		120,979
Balances at June 30, 2022	143,155	$	1	$	554,755	$	(654,958)	2,869	$	(24,167)	$	(124,369)

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

Nine Months Ended September 30,


2022

2021
Operating activities:




Net income (loss)

$
187,700

$
(90,382)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:




Depreciation, depletion, amortization and accretion

99,384

83,879
Amortization of debt items and other items

6,114

4,095
Share-based compensation

5,179

1,779
Derivative loss

109,892

179,156
Derivative cash (payments) receipts, net

(1,022)

(39,554)
Derivative cash premium payments

(46,111)

(32,368)
Deferred income taxes

40,171

(18,826)
Changes in operating assets and liabilities:




Oil and natural gas receivables

(34,276)

504
Joint interest receivables

(7,070)

(2,172)
Prepaid expenses and other assets

(26,816)

(30,473)
Income tax

1,480

(153)
Asset retirement obligation settlements

(61,285)

(19,744)
Cash advances from JV partners

(12,055)

9,999
Accounts payable, accrued liabilities and other

65,566

65,551
Net cash provided by operating activities

326,851

111,291
Investing activities:




Investment in oil and natural gas properties and equipment

(29,966)

(16,025)
Changes in operating assets and liabilities associated with investing activities

(8,237)

3,619
Acquisition of property interests

(51,474)

—
Net cash used in investing activities

(89,677)

(12,406)
Financing activities:




Repayments on credit facility

—

(80,000)
Proceeds from Term Loan

—

215,000
Repayments on Term Loan

(33,837)

(11,778)
Debt issuance costs

(1,290)

(8,249)
Other

(716)

—
Net cash (used in) provided by financing activities

(35,843)

114,973
Increase in cash and cash equivalents

201,331

213,858
Cash and cash equivalents and restricted cash, beginning of period

250,216

43,726
Cash and cash equivalents and restricted cash, end of period

$
451,547

$
257,584


	Six Months Ended June 30,
	2023		2022
Operating activities:
Net income	$	13,896	$	120,979
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		66,028		65,271
Amortization and write off of debt issuance costs		4,363		4,365
Share-based compensation		4,009		2,534
Derivative (gain) loss		(40,069)		71,143
Derivative cash (payments) receipts, net		(4,427)		70,227
Derivative cash premium payments		—		(46,111)
Deferred income taxes		11,580		27,031
Changes in operating assets and liabilities:
Oil and natural gas receivables		24,804		(44,236)
Joint interest receivables		125		(3,625)
Prepaid expenses and other assets		26,992		(30,092)
Income tax		(2,345)		3,223
Asset retirement obligation settlements		(11,841)		(39,775)
Cash advances from JV partners		(71)		(9,813)
Accounts payable, accrued liabilities and other		(43,412)		46,638
Net cash provided by operating activities		49,632		237,759
Investing activities:
Investment in oil and natural gas properties and equipment		(22,999)		(25,489)
Changes in operating assets and liabilities associated with investing activities		(2,338)		(5,786)
Acquisition of property interests		—		(47,625)
Purchase of corporate aircraft (Note 12)		(8,983)		—
Purchases of furniture, fixtures and other		(218)		—
Net cash used in investing activities		(34,538)		(78,900)
Financing activities:
Repayment of Note Payable		(183)		—
Issuance of 11.75% Senior Second Lien Notes		275,000		—
Repayments on 9.75% Second Senior Lien Notes		(552,460)		—
Repayments on Term Loan		(19,181)		(24,941)
Debt issuance costs		(7,252)		(1,290)
Other		(748)		(703)
Net cash used in financing activities		(304,824)		(26,934)
(Decrease) increase in cash and cash equivalents		(289,730)		131,925
Cash and cash equivalents and restricted cash, beginning of period		465,774		250,216
Cash and cash equivalents and restricted cash, end of period	$	176,044	$	382,141

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

W&T Offshore, Inc. (with subsidiaries referred to herein as “W&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. 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 a proportionately consolidated interest in Monza Energy LLC (“Monza”)~~, as described in more detail in~~ ~~Note 6 – Joint Venture Drilling Program~~.

Basis of Presentation

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

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s ~~2021~~2022 Annual Report on Form 10-K (the ~~“2021~~“2022 Annual Report”).

~~Reclassification –~~ ~~For presentation purposes, as of September 30, 2021,~~ ~~Derivative (gain) loss~~ has been reclassified from “Operating income” on the Condensed Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassification had no effect on the Company’s results of operations, financial position or cash flows.

~~For presentation purposes, as of September 30, 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 the Company’s results of operations, financial position or cash flows.

Use of Estimates

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

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Summary of Significant Accounting Policies

Revenue and Accounts Receivable – The Company records revenues from the sale of oil, natural gas liquids (“NGLs”) and natural gas based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. Revenue from the sale of crude oil, ~~natural gas liquids (“NGLs”)~~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~~Each unit of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is ~~concentrated with certain major oil and gas companies. There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2022.~~not required.

The Company also 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 ten companies. A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and forecasts of future economic conditions. The Company’s maximum exposure at any time would be the receivable balance. Joint interest receivables on the Condensed Consolidated Balance Sheets are presented net of allowance for credit losses of ~~$11.6~~$11.3 million and ~~$10.0~~$12.1 million as of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively.

Employee Retention Credit – Under the Consolidated Appropriations Act of 2021, the Company recognized a ~~$2.1~~$2.2 million employee retention credit during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2023, which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations. ~~No such credit has been recognized during the nine months ended September 30, 2022.~~

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


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Derivatives⁽¹⁾(Note 8)	$	28,747	$	21,086
Derivatives⁽¹⁾(Note 4)					$	1,778	$	4,954
Unamortized insurance/bond premiums		7,475		5,400		8,303		6,046
Prepaid deposits related to royalties		12,978		8,441		6,822		9,139
Prepayment to vendors		1,213		4,522
Prepayments to vendors						1,628		1,767
Prepayments to joint interest partners		1,953		2,808		2,319		1,717
Debt issue costs		604		1,065		427		687
Other		44		57		88		33
Prepaid expenses and other assets	$	53,014	$	43,379	$	21,365	$	24,343

⁽¹⁾

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

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


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Oil and natural gas properties and equipment	$	8,780,961	$	8,636,408	$	8,847,421	$	8,813,404
Furniture, fixtures and other		20,827		20,844		40,224		20,915
Total property and equipment		8,801,788		8,657,252		8,887,645		8,834,319
Less: Accumulated depreciation, depletion, amortization and impairment		(8,071,830)		(7,992,000)		(8,149,905)		(8,099,104)
Oil and natural gas properties and other, net	$	729,958	$	665,252	$	737,740	$	735,215

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

September 30, 2022

December 31, 2021
Right-of-Use assets

$
10,443

$
10,602
Investment in White Cap, LLC

3,193

2,533
Proportional consolidation of Monza (Note 6)

15,409

2,511
Derivatives⁽¹⁾ (Note 8)

35,656

34,435
Other

980

1,091
Total other assets (long-term)

$
65,681

$
51,172


	June 30, 2023		December 31, 2022
Right-of-Use assets	$	10,728	$	10,364
Investment in White Cap, LLC		2,721		2,453
Proportional consolidation of Monza (Note 6)		9,909		9,321
Derivatives⁽¹⁾ (Note 4)		17,184		23,236
Other		1,576		2,175
Total other assets (long-term)	$	42,118	$	47,549

⁽¹⁾

^{Includes open contracts.}

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


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Accrued interest	$	25,423	$	10,154	$	13,848	$	8,967
Accrued salaries/payroll taxes/benefits		9,711		9,617		4,808		15,097
Litigation accruals		524		646		56		396
Lease liability		1,620		1,115		1,045		1,628
Derivatives⁽¹⁾(Note 8)		116,008		81,456
Derivatives⁽¹⁾(Note 4)						18,518		46,595
Other		950		3,152		1,048		1,358
Total accrued liabilities	$	154,236	$	106,140	$	39,323	$	74,041

⁽¹⁾

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

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


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Dispute related to royalty deductions	$	7,564	$	5,177	$	5,250	$	4,937
Derivatives (Note 8)		75,079		37,989
Derivatives (Note 4)						17,417		43,061
Lease liability		10,812		11,227		11,709		10,527
Other		1,386		996		665		609
Total other liabilities (long-term)	$	94,841	$	55,389	$	35,041	$	59,134

At-the-Market Equity Offering – On March 18, 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100,000,000 of shares of common stock under the Company’s ~~"at-the-market"~~“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 ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, the Company did not sell any shares in connection with the ATM Program.

During the year ended December 31, 2022, the Company sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Program and received proceeds, net of commissions and expenses, of $16.5 million.

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NOTE 2 — DEBT

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


					June 30, 2023		December 31, 2022
TVPX Loan:
Principal					$	11,575	$	—
Discount						(1,651)
Unamortized debt issuance costs						(267)		—
Total TVPX Loan						9,657		—
	September 30, 2022		December 31, 2021
Term Loan:
Principal	$	157,021	$	190,859		128,719		147,899
Unamortized debt issuance costs		(5,067)		(7,545)		(3,727)		(4,592)
Total Term Loan		151,954		183,314		124,992		143,307

Credit Agreement borrowings:		—		—		—		—

Senior Second Lien Notes:		—
11.75% Senior Second Lien Notes due 2026:
Principal		552,460		552,460		275,000		—
Unamortized debt issuance costs		(2,991)		(4,876)		(6,078)		—
Total Senior Second Lien Notes		549,469		547,584
Total 11.75% Senior Second Lien Notes due 2026						268,922		—

Less current portion		(35,450)		(42,960)
9.75% Senior Second Lien Notes due 2023:
Principal						—		552,460
Unamortized debt issuance costs						—		(2,330)
Total 9.75% Senior Second Lien Notes due 2023						—		550,130

Less current portion, net						(30,550)		(582,249)
Total long-term debt, net	$	665,973	$	687,938	$	373,021	$	111,188

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Current Portion of Long-Term Debt, Net

As of ~~September~~June 30, ~~2022,~~2023, the current portion of long-term debt of ~~$35.5~~$30.6 million represented principal payments due within one year on the TVPX Loan and Term Loan (defined below), net of current unamortized debt issuance costs.

TVPX Loan

On May 15, 2023, the Company acquired a corporate aircraft from a company affiliated with and controlled by W&T’s Chairman, Chief Executive Officer (“CEO”) and President, Tracy W. Krohn. The terms of the transactions were reviewed and approved by the Audit Committee of the Company’s Board of Directors. See Note 12 – Related Party Transactions.

~~As of September 30, 2022, the Company 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 ~~Company has commenced discussions with potential lenders and institutional investors regarding a potential refinancing of all or a portion~~purchase price of the ~~Senior Second Lien Notes prior to maturity, although there is no assurance as to~~aircraft was $19.1 million, which was paid using $9.0 million of the ~~terms of any such refinancing or whether or when such refinancing will occur.~~

~~The Company believes that~~Company’s cash on hand and ~~cash flows from operations will enable~~through the assumption of an amortizing loan by TVPX Aircraft Solutions Inc. (the “TVPX Loan”), not in its individual capacity but as owner trustee of the trust which holds title to the aircraft, a wholly owned indirect subsidiary of the Company, ~~to satisfy its debt obligations~~ as ~~well as meet its other funding requirements~~the borrower. At the time of the assumption, the TVPX Loan had an aggregate principal amount of approximately $11.8 million outstanding. The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued interest, which began on May 17, 2023, and a balloon payment of $8.0 million at ~~least one year from~~the end of the loan term. The TVPX Loan is guaranteed by the Company on an unsecured basis. Using current market rates, we determined that the fair market value of the TVPX Loan was $10.1 million at the date ~~this Form 10-Q is issued. The Company’s view regarding sufficiency~~ of cash and liquidity is primarily based on the financial forecast, which is impacted by various assumptions including projections for pricing, production volumes and operating costs. Given the assumptions involved, the forecast is subject to uncertainty, therefore cash flows from operations may be lower than projected. assumption.

~~If necessary, there are further actions~~The aircraft was purchased as part of a series of transactions pursuant to which the Company ~~could undertake~~restructured the compensation for its Named Executive Officers. Prior to ~~increase cash flows which include limiting capital expenditures and reducing operating expenditures. Additionally,~~the Company’s purchase of the aircraft, the Company ~~may seek~~used the aircraft for business purposes, and the CEO also used the aircraft for personal purposes. Both the Company’s use for business purposes and the CEO’s unlimited use for personal purposes were paid for by the Company pursuant to ~~raise cash through~~ the ~~sale~~CEO’s prior employment agreement. In connection with the Company’s efforts to significantly reduce overall executive compensation, including perquisite compensation Mr. Krohn was receiving for personal use of upthe aircraft, on April 20, 2023, the Company entered into an amendment to ~~$100~~the employment agreement with the CEO which requires that the Company be reimbursed for personal use of the aircraft in accordance with the Company’s aircraft use policy.

During the six months ended June 30, 2023, the Company repaid $183.3 thousand of principal outstanding. As of June 30, 2023, the Company had $11.6 million of ~~equity available under~~principal amount outstanding related to the ~~ATM program.~~TVPX Loan.

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Term Loan (Subsidiary Credit Agreement)

On May 19, 2021, A-I LLC and A-II LLC (collectively, the “Subsidiary Borrowers”), both Delaware limited liability companies and indirect, wholly-owned subsidiaries of the Company, entered into a credit agreement (the “Subsidiary Credit Agreement”) providing for a term loan (the “Term Loan”) in an aggregate principal amount equal to $215.0 ~~million (the “Term Loan”).~~million. The Term Loan requires quarterly amortization payments which commenced on September 30, 2021. The Term Loan bears interest at a fixed rate of 7%7.0% per annum and will mature on May 19, 2028. The Subsidiary Credit Agreement required the Company to enter into certain natural gas swap and put derivative contracts. See Note 4 – Derivative Financial Instruments.

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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 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. 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 See Note 5 – Subsidiary Borrowers.for additional information.

During the six months ended June 30, 2023, the Company repaid $19.2 million of principal outstanding. As of ~~September~~June 30, ~~2022 and December 31, 2021,~~2023, the Company had ~~$157.0 million and $190.9~~$128.7 million in principal amount of the Term Loan ~~outstanding, respectively.~~outstanding.

Credit Agreement

~~On November 2, 2021, the~~The Company has entered into ~~the Ninth Amendment to the Sixth Amended and Restated~~a Credit Agreement ~~(the “Ninth Amendment”), which establishes a short-term $100.0 million first priority lien secured revolving credit 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 and President, Tracy W. Krohn, as sole lender under the Credit ~~Agreement. A committee~~Agreement (as amended from time to time, the “Credit Agreement”). The Credit Agreement currently has a maturity date 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.January 3, 2024. Alter Domus (US) LLC ~~was appointed to replace Toronto Dominion (Texas) LLC~~serves as the 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. In connection with the Tenth Amendment, Calculus was paid arrangement and upfront fees of approximately $1.0 million in the aggregate during the nine months ended September 30, 2022.

On November 7, 2022, the Company entered into the Eleventh Amendment to the Credit Agreement (the “Eleventh Amendment”), which extended the maturity date and Calculus’ commitment to January 3, 2024, or in certain circumstances as described in more detail below, to August 1, 2023, and shifted the rate at which outstanding borrowings will accrue interest to a SOFR-based rate. The terms of this extension with Calculus were reviewed and approved by the Audit Committee of the Company.

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Pursuant to the Eleventh Amendment, the commitment will expire and final maturity of any and all outstanding loans is January 3, 2024, or in the event the Senior Second Lien Notes are not refinanced or replaced in full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023. Outstanding borrowings will accrue interest at SOFR plus ~~6.0%~~ ~~per annum. The commitment fee for the unused portion of available borrowing amounts will be~~ ~~3.0% per annum. In connection with the Eleventh Amendment, the Company paid to Calculus an extension fee of $100,000.~~

~~As a result of the Ninth Amendment, Tenth Amendment and Eleventh Amendment and related assignments and agreements, the~~ primary terms and covenants associated with the Credit Agreement as of ~~September~~June 30, ~~2022,~~2023, are as follows:

●

~~The revised~~$100 million first priority lien secured revolving credit facility, with borrowings limited to a borrowing base isof $50.0 million;

●

Outstanding borrowings accrue interest at SOFR plus 6.0% per annum;

●

The Company’s ratio of First Lien Debt (as such term is defined in the 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 four quarters must not be greater than 2.50 to 1.00 on the last day of any fiscal quarter commencing with the fiscal quarter ended March 31, 2022;

●

The ~~commitment will expire and final maturity~~Company’s ratio of Total Proved PV-10 to First Lien Debt (as such terms are defined in the Credit Agreement) as of the last day of any fiscal quarter commencing with the fiscal quarter ended March 31, 2022, must be equal to or greater than 2.00 to 1.00;

●

The ratio of the Company and ~~all outstanding loans is January 3, 2024, or~~its restricted subsidiaries’ consolidated current assets to consolidated current liabilities (subject in each case to certain exceptions and adjustments as set forth in the ~~event that~~Credit Agreement) at the ~~Second Lien Notes are not refinanced~~last day of any fiscal quarter must be greater than or ~~replaced in full, on or prior~~equal to ~~August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023.~~

1.00 to 1.00;

·The Company’s ratio of First Lien Debt (as such term is defined in the 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 four quarters must not be greater than 2.50 to 1.00 on the last day of the fiscal quarter ending March 31, 2022 and on the last day of each fiscal quarter thereafter;

·The Company’s ratio of Total Proved PV-10 (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 equal to or greater than 2.00 to 1.00;

·The ratio of the Company and its restricted subsidiaries’ consolidated current assets to Company and its restricted subsidiaries’ consolidated current liabilities (subject in each case to certain exceptions and adjustments as set forth in the 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~~ended 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~~certain future net revenues ~~expected to accrue to~~from the Company’s and its ~~guarantor~~restricted subsidiaries’ ~~interest (and the interest of~~and certain joint ~~ventures) in the~~ventures’ 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~~collateral are sufficient to satisfy the aggregate first lien indebtedness ofunder the ~~Company and its restricted subsidiaries in accordance with the terms of such indebtedness~~Credit Agreement assuming the ~~revolving credit facility~~Borrowing Base is 100% funded or fully utilized; and

●~~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.~~

●

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.

~~In addition, Calculus earned commitment fees of $1,137,500, equal to 3.0% of unborrowed portion of the borrowing base lending commitment, during the nine months ended September 30, 2022.~~

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Availability under the Credit Agreement is subject to redetermination of the borrowing base that may be requested at the discretion of either the lender or the Company in accordance with the Credit Agreement. ~~The borrowing base is calculated by the lender based on their evaluation of proved reserves and their own internal criteria.~~ Any redetermination by the lender to change the borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement is secured by a first priority lien on substantially all of the Company’s and its guarantor subsidiaries’ assets, excluding those assets of the Subsidiary Borrowers, which liens were released in the Mobile Bay Transaction (as described in Note 5 – Subsidiary Borrowers).

As of ~~September~~June 30, ~~2022,~~2023, there were no borrowings outstanding under the Credit Agreement and no borrowings had been incurred under the Credit Agreement during the ~~nine~~six months ended ~~September~~June 30, ~~2022. Separately, as~~2023. As of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the Company had $4.4 million outstanding in letters of credit which have been cash collateralized.

~~9.75% Senior Second Lien Notes Due 2023~~9

~~On October 18, 2018, W&T issued $625.0 million~~Table of ~~9.75%~~Contents

11.75% Senior Second Lien Notes due 2026

On January 27, 2023, ~~(the “Senior~~the Company issued and sold $275 million in aggregate principal amount of its 11.75% Senior Second Lien ~~Notes”), which were issued~~Notes at par with an interest rate of ~~9.75%~~11.75% per annum ~~and mature~~that matures on ~~November~~February 1, ~~2023, and~~2026 (the “11.75% Senior Second Lien Notes”), which are governed under the terms of ~~the Indenture of the Senior Second Lien Notes~~an indenture (the “Indenture”). ~~The estimated annual effective interest rate~~Interest on the ~~Senior Second Lien Notes is 10.3%, which includes amortization of debt issuance costs. Interest on the~~11.75% Senior Second Lien Notes is payable in arrears on ~~May~~February 1 and ~~November~~August 1, ~~of each year. As of September 30, 2022 and December 31, 2021, $552.5 million in principal amount of~~commencing August 1, 2023. The 11.75% Senior Second Lien Notes ~~remained issued~~will be recorded at their carrying value consisting of principal and ~~outstanding.~~

unamortized debt issuance costs. The 11.75% Senior Second Lien Notes are secured by a second-priority ~~lien~~liens on ~~all of~~ the ~~Company’s assets~~same collateral that ~~are~~is secured under the Credit Agreement, which does not include the Mobile Bay Properties and the related Midstream Assets. The estimated annual effective interest rate on the 11.75% Senior Second Lien Notes is 12.6%, which includes amortization of deferred interest costs.

Prior to August 1, 2024, the Company may redeem all or any portion of the 11.75% Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the notes outstanding plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to August 1, 2024, the Company may, at its option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the 11.75% Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 111.750% of the principal amount of the outstanding plus accrued and unpaid interest, if any, to the redemption date.

On and after August 1, 2024, the Company may redeem the 11.75% Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 105.875% for the 12-month period beginning August 1, 2024, and 100.000% on August 1, 2025 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The 11.75% Senior Second Lien Notes are guaranteed by the Guarantors.

The 11.75% Senior Second Lien Notes contain covenants that limit or prohibit the Company’s ability and the ability of certain of its 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 important exceptions and qualifications set forth in the Indenture. In addition, most of the ~~above described~~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 11.75% Senior Second Lien Notes an investment grade rating and no default exists with respect to the 11.75% Senior Second Lien Notes.

Redemption of 9.75% Senior Second Lien Notes due 2023

On October 18, 2018, the Company issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “9.75% Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and would have matured on November 1, 2023.

On February 8, 2023, the Company redeemed all of the $552.5 million of aggregate principle outstanding of the 9.75% Senior Second Lien Notes at a redemption price of 100.0%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes and cash on hand of $296.1 million to fund the redemption.

Covenants

As of ~~September~~June 30, ~~2022~~2023 and for all prior measurement periods presented, the Company was in compliance with all applicable covenants of the Credit Agreement and the Indenture.

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NOTE 3 – FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

Derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 4 – Derivative Financial Instruments for additional information on derivative financial instruments. The Company measures the fair value of derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The income approach converts expected future cash flows to a present value amount based on market expectations. The inputs used for the fair value measurement of 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. ~~Derivative~~

The following table presents the fair value of the Company’s derivative financial instruments ~~are reported~~(in thousands):


	June 30, 2023		December 31, 2022
Assets:
Derivative instruments - current	$	1,778	$	4,954
Derivative instruments - long-term		17,184		23,236

Liabilities:
Derivative instruments - current		18,518		46,595
Derivative instruments - long-term		17,417		43,061

Debt Instruments

The following table presents the net value and fair value of the Company’s debt (in thousands):


	June 30, 2023				December 31, 2022
	Net Value		Fair Value		Net Value		Fair Value
Liabilities:
TVPX Loan	$	9,657	$	9,977	$	—	$	—
Term Loan		124,992		120,965		143,307		139,056
11.75% Senior Second Lien Notes due 2026		268,922		275,303		—		—
9.75% Senior Second Lien Notes due 2023		—		—		550,130		544,902
Total	$	403,571	$	406,245	$	693,437	$	683,958

The fair value of the TVPX Loan and the Term Loan were measured using a discounted cash flows model and current market rates. The fair value of the 11.75% Senior Second Lien Notes and 9.75% Senior Second Lien Notes were measured using quoted prices, although the market is not a highly liquid market. The fair value of debt was classified as Level 2 within the valuation hierarchy.

NOTE 4 — DERIVATIVE FINANCIAL INSTRUMENTS

W&T’s market risk exposure relates primarily to commodity 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 production through the use of oil and natural gas swaps, costless collars, sold calls and purchased puts. The Company is exposed to credit loss in the ~~Condensed Consolidated Balance Sheets using fair value. See~~ ~~Note 8 – Derivative Financial Instruments~~~~, for~~event of 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 ~~information on~~collateral to the derivative ~~financial instruments.~~counterparties and does not require collateral from the derivative counterparties.

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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 (gain) 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 natural gas contracts are based off the Henry Hub prices, which is quoted off the New York Mercantile Exchange (“NYMEX”).

The following table ~~presents~~reflects the ~~fair value~~contracted volumes and weighted average prices under the terms of the Company’s open derivative ~~financial instruments (in thousands):~~contracts as of June 30, 2023:

September 30, 2022

December 31, 2021
Assets:




Derivative instruments - current

$
28,747

$
21,086
Derivative instruments - long-term

35,656

34,435

Liabilities:




Derivative instruments - current

116,008

81,456
Derivative instruments - long-term

75,079

37,989



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

Natural Gas - Henry Hub (NYMEX)		(MMbtu)⁽¹⁾	(MMbtu)⁽¹⁾		($/MMbtu)⁽¹⁾		($/MMbtu)⁽¹⁾		($/MMbtu)⁽¹⁾
July 2023 - Dec 2023	calls	35,288	12,880,000	$	—	$	—	$	7.50
Jan 2024 - Dec 2024	calls	65,000	23,790,000	$	—	$	—	$	6.13
Jan 2025 - Mar 2025	calls	62,000	5,580,000	$	—	$	—	$	5.50
July 2023 - Dec 2023⁽²⁾	swaps	36,164	13,200,000	$	2.43	$	—	$	—
Jan 2024 - Dec 2024⁽²⁾	swaps	65,574	24,000,000	$	2.46	$	—	$	—
Jan 2025 - Mar 2025⁽²⁾	swaps	63,333	5,700,000	$	2.72	$	—	$	—
Apr 2025 - Dec 2025⁽²⁾	puts	62,182	17,100,000	$	—	$	2.27	$	—
Jan 2026 - Dec 2026⁽²⁾	puts	55,890	20,400,000	$	—	$	2.35	$	—
Jan 2027 - Dec 2027⁽²⁾	puts	52,603	19,200,000	$	—	$	2.37	$	—
Jan 2028 - Apr 2028⁽²⁾	puts	49,587	6,000,000	$	—	$	2.50	$	—

~~Debt Instruments~~

⁽¹⁾	^{MMbtu – Million British Thermal Units}

⁽²⁾	^{These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with the Term Loan (see}^{Note 5 – Subsidiary Borrowers).}

Financial Statement Presentation

The following ~~table presents the net value and~~ fair value of derivative financial instruments amounts were recorded in the ~~Company’s debt~~Condensed Consolidated Balance Sheets (in thousands):

September 30, 2022

December 31, 2021

Net Value

Fair Value

Net Value

Fair Value
Liabilities:








Term Loan

$
151,954

$
147,137

$
183,314

$
190,579
Senior Second Lien Notes

549,469

543,206

547,584

527,715
Total

$
701,423

$
690,343

$
730,898

$
718,294


	June 30, 2023		December 31, 2022
Prepaid expenses and other current assets	$	1,778	$	4,954
Other assets (long-term)		17,184		23,236
Accrued liabilities		18,518		46,595
Other liabilities (long-term)		17,417		43,061

The fair value of the Term Loan was measured using a discounted cash flows model and current market rates. The fair value of the Senior Second Lien Notes was measured using quoted prices, although the market is not a highly liquid market. The fair value of debt was classified as Level 2 within the valuation hierarchy.

~~NOTE 4~~ — ~~ACQUISITIONS~~

~~On January 5, 2022,~~Although the Company ~~entered into~~has master netting arrangements with its counterparties, the amounts recorded on the Condensed Consolidated Balance Sheets are on 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 $34.0 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.

Additionally, on April 1, 2022, the Company entered into a purchase and sale agreement with a private seller to acquire the remaining working interests in certain oil and 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 from ANKOR. The transaction had an effective date and closing date of April 1, 2022.~~After normal and customary post-effective date adjustments, cash consideration of $17.5 million was paid to the seller.~~gross basis.

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The Company determined that the assets acquired did not meet the definition of a business; therefore, the transactions were accounted for as asset acquisitions in accordance with ASC 805. An acquisition 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 Sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas 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 measurementsChanges in the fair value ~~hierarchy~~ and ~~include, but~~settlements of contracts 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~~Statements of Operations as Derivative (gain) loss, net. The impact of commodity derivative contracts on the ~~purchase price allocation and liabilities assumed related to the acquisitions described above on February 1, 2022, and April 1, 2022, are presented in the following tables, respectively~~Condensed Consolidated Statements of Operations were as follows (in thousands):

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

$
54,299
Restricted deposits for asset retirement obligations

6,196
Asset retirement obligations

(26,493)
Allocated purchase price

$
34,002

April 1,

2022
Oil and natural gas properties and other, net

$
22,632
Restricted deposits for asset retirement obligations

1,549
Asset retirement obligations

(6,709)
Allocated purchase price

$
17,472


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Realized loss (gain)⁽¹⁾	$	300	$	(79,667)	$	530	$	(35,973)
Unrealized (gain) loss		(1,129)		70,813		(40,599)		107,116
Derivative (gain) loss, net	$	(829)	$	(8,854)	$	(40,069)	$	71,143

(1)

^{The three and six months ended June 30, 2022 includes the effect of the}^$138.0^{million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices.}

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


	Six Months Ended June 30,
	2023		2022
Derivative (gain) loss, net	$	(40,069)	$	71,143
Derivative cash (receipts) payments, net⁽¹⁾		(4,427)		70,227
Derivative cash premium payments, net		—		(46,111)

(1)

^{The six months ended June 30, 2022 includes}^$105.3^{million of net cash receipts related to the monetization of certain natural gas call contracts through restructuring of strike prices.}

NOTE 5 — SUBSIDIARY BORROWERS

On May 19, 2021, ~~the Company’s wholly-owned special purpose vehicles (the “SPVs”),~~ 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 84 – Derivative Financial Instruments, of this Quarterly Report on Form ~~10-Q (this “Quarterly Report”).~~10-Q.

~~As part~~The Subsidiary Borrowers are wholly-owned subsidiaries of the ~~Mobile Bay Transaction,~~Company; however, the ~~SPVs entered into a management services agreement (the “Services Agreement”) with~~assets of the ~~Company, pursuant~~Subsidiary Borrowers are not available to ~~which~~satisfy the Company will provide (a) certain operational and management services for (i) the Mobile Bay Properties and (ii) the Midstream Assets and (b) certain corporate, general and administrative services for A-I LLC and A-II LLC (collectively in this capacity, the “Services Recipient”). Under the Services Agreement, the Company will indemnify the Services Recipient with respect to claims, lossesdebt or ~~liabilities incurred by the Services Agreement parties that relate to personal injury~~contractual obligations of any other entities, including debt securities or ~~death or property damage~~other contractual obligations 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 ofand the Subsidiary ~~Credit Agreement~~Borrowers do not bear any liability for the indebtedness or other contractual obligations of any other entities, and ~~payment and satisfaction of all obligations thereunder or (b)~~vice versa.

During the ~~exercise of certain remedies by the secured parties under~~year ended December 31, 2022, the Subsidiary ~~Credit Agreement and~~Borrowers paid cash distributions to W&T of $30.2 million. During the ~~realization by~~six months ended June 30, 2023, no such ~~secured parties upon any of the collateral under the Subsidiary Credit Agreement.~~distributions were paid.

Table of Contents

~~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 the Company, and the SPVs do not bear any liability for the indebtedness or other contractual obligations of any non-SPVs, and vice versa.

Consolidation and Carrying Amounts

The following table presents the amounts recorded by W&T on the Condensed Consolidated Balance Sheets related to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers (in thousands):


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Assets:
Cash and cash equivalents	$	54,219	$	38,937	$	5,899	$	21,764
Receivables:
Oil and natural gas sales		80,431		34,420		18,411		37,344
Joint interest, net		(5,749)		(10,856)		(27,400)		(5,760)
Prepaid expenses and other assets		614		356		125		417
Oil and natural gas properties and other, net		280,444		272,747		289,959		280,649
Other assets		(19,438)		(19,903)		11,486		8,473
Liabilities:
Accounts payable		49,859		29,678		8,996		27,387
Undistributed oil and natural gas proceeds		22,077		3,144		3,625		7,930
Accrued liabilities		89,431		29,937		19,036		45,102
Current portion of long-term debt		35,450		42,960		30,074		32,119
Long-term debt, net		116,504		140,353		94,918		111,188
Asset retirement obligations		59,107		54,515		66,136		61,138
Other liabilities		79,602		42,615		22,020		47,398

The following table presents the amounts recorded by W&T in the Condensed Consolidated Statement of Operations related to the consolidation of the operations of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers (in thousands):


			The period from
	Nine Months Ended		May 19, 2021 to		Three Months Ended June 30,				Six Months Ended June 30,
	September 30, 2022		September 30, 2021		2023		2022		2023		2022
Total revenues	$	218,625	$	63,053	$	25,437	$	76,846	$	46,560	$	124,361
Total operating expenses		52,961		26,644		30,443		18,385		50,490		33,185
Interest expense, net		11,841		5,930		3,229		3,658		5,411		8,436
Derivative loss		187,896		124,364
Other income		64		—
Derivative (gain) loss, net						(6,012)		35,888		(52,389)		132,046

~~Table of Contents~~

NOTE 6 — JOINT VENTURE DRILLING PROGRAM

In March 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with the Company 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, 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 W&T initially receives an aggregate of 30.0% of the revenues less expenses, through the direct ownership from the retained working interest in the Monza projects and the Company’s indirect interest through ~~the~~its 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 of directors.

Table of Contents

The members of Monza are third-party investors, W&T and an entity owned and controlled by ~~Mr.~~ Tracy W. Krohn, ~~our~~the Company’s Chairman, ~~and~~ Chief Executive ~~Officer.~~Officer and President. The ~~Krohn~~ entity affiliated with the Company’s CEO 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~~Monza, and made a capital commitment to Monza of $14.5 million.

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

Through ~~September~~June 30, ~~2022,~~2023, ten wells have been completed since the inception of the Joint Venture Drilling Program. W&T is the operator for eight of the ten wells completed through ~~September~~June 30, ~~2022.~~2023.

~~Through September~~Since inception through June 30, ~~2022,~~2023, members of Monza made partner capital contributions, including W&T’s contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling ~~$138.4~~$204.7 million. ~~Through September~~Since inception through June 30, ~~2022,~~2023, W&T made total capital contributions, including the contributions of working interest in the drilling projects, to Monza totaling $68.2 million and received cash distributions totaling ~~$31.8~~$48.3 million.

Consolidation and Carrying Amounts

W&T’s interest in Monza is considered to be a variable interest that is proportionally consolidated. Through ~~September~~June 30, ~~2022,~~2023, there have been no events or changes that would cause a redetermination of the variable interest status. W&T does not fully consolidate Monza because the Company is not considered the primary beneficiary of Monza.

The following table presents the amounts recorded by W&T on the Condensed Consolidated Balance Sheets related to the consolidation of the proportional interest in Monza’s operations (in thousands):


	September 30, 2022		December 31, 2021		June 30, 2023		December 31, 2022
Working capital	$	3,583	$	4,648	$	1,191	$	2,515
Oil and natural gas properties and other, net		39,131		45,510		34,516		37,260
Asset retirement obligations		432		375		518		467
Other assets		15,409		2,511		9,909		11,571
Other liabilities		2,627		—

~~Additionally, during the year ended December 31, 2021,~~As required, W&T ~~called~~may call on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~2022 were ~~$2.9~~$2.8 million and ~~$14.8~~$2.9 million, respectively, which are included in the Condensed Consolidated Balance Sheets in Advances from joint interest partners.

~~Table of Contents~~

The following table presents the amounts recorded by W&T in the Condensed Consolidated Statement of Operations related to the consolidation of the proportional interest in Monza’s operations (in thousands):


	Nine Months Ended September 30,				Six Months Ended June 30,
	2022		2021		2023		2022
Total revenues	$	23,681	$	8,730	$	6,018	$	16,615
Total operating expenses		10,805		7,564		4,623		7,368
Derivative loss		—		1,966
Interest income						104		—

Table of Contents

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

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


	Nine Months Ended September 30,		Six Months Ended June 30,
	2022		2023
Asset retirement obligations, beginning of period	$	424,495	$	466,430
Liabilities settled		(61,285)		(11,841)
Accretion expense		19,536		15,227
Liabilities acquired		33,202
Liabilities incurred		138		113
Revisions of estimated liabilities		37,524		10,903
Asset retirement obligations, end of period		453,610		480,832
Less: Current portion		(54,886)		(37,763)
Long-term	$	398,724	$	443,069

NOTE 8 — ~~DERIVATIVE FINANCIAL INSTRUMENTS~~ SHARE-BASED AWARDS AND CASH BASED AWARDS

~~W&T’s market risk exposure relates primarily to commodity 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 production through~~On June 16, 2023, the ~~use of oil and natural gas swaps, costless collars, sold calls and purchased puts.~~ ~~The Company is exposed to credit loss in the event of nonperformance~~2023 Incentive Compensation Plan (the “2023 Plan”) was approved by the ~~derivative counterparties; however,~~Company’s shareholders. The 2023 Plan is effective June 16, 2023, and 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~~no longer grant awards pursuant to the ~~derivative counterparties~~W&T Offshore, Inc. Amended and ~~does not require collateral~~Restated Incentive Compensation Plan, as amended from time to time, (the “Prior Plan”) or the ~~derivative counterparties.~~2004 Directors Compensation Plan, as amended from time to time. Under the 2023 Plan, the Company may issue, subject to the approval of the Board of Directors, stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards, dividend equivalents, other stock-based awards, performance units or shares, cash awards, substitute awards or any combination of the foregoing to eligible employees, non-employee directors, and consultants. Any awards granted prior to the effective date of the 2023 Plan are considered to have been granted under the Prior Plan.

~~W&T has elected not~~Share-Based Awards to ~~designate commodity derivative contracts for hedge accounting.~~ Employees

~~Accordingly, commodity derivatives~~Restricted Stock Units (“RSUs”) – On June 5, 2023, the Company granted RSUs under the Prior Plan to certain employees. RSUs outstanding as of June 30, 2023 relate to the 2023, 2022, and 2021 grants. The 2023 RSUs granted are ~~recorded~~a long-term compensation component, subject to service conditions, with one-third of the award vesting each year on June 5, 2024, 2025 and 2026, respectively.

A summary of activity related to RSUs during the ~~Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in~~six months ended June 30, 2023 is as follows:


		Weighted
		Average
	Restricted	Grant Date Fair
	Stock Units	Value Per Unit
Nonvested, beginning of period	1,221,461	$	5.76
Granted	1,527,221		4.09
Vested	(486,134)		5.62
Forfeited	(80,911)		5.97
Nonvested, end of period	2,181,637		4.61

Performance Share Units (“PSUs”) – On June 5, 2023, the ~~unrealized fair value, recorded as~~Company granted PSUs under the Prior Plan ~~Derivative (gain) loss~~~~on the Condensed Consolidated Statements of Operations in each period presented.~~ ~~The cash flows of all commodity derivative contracts~~that are ~~included in~~ ~~Net cash provided by operating activities~~ ~~on the Condensed Consolidated Statements of Cash Flows.~~

~~The crude oil contracts are~~eligible to vest based on ~~West Texas Intermediate (“WTI”) crude oil prices~~continued employment and the ~~natural gas contracts are based off~~Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR over a three-year performance period, which ends on December 31, 2025. PSUs outstanding as of June 30, 2023 relate to the ~~Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).~~2023, 2022 and 2021 grants.

Table of Contents

~~The following table reflects~~A summary of activity related to PSUs during the ~~contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts~~six months ended June 30, 2023 is as ~~of September 30, 2022:~~follows:

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⁾
Jul 2022 - Nov 2022

swaps

2,174

132,612

$
58.38

$
—

$
—
Jul 2022 - Nov 2022

collars

2,174

132,612

$
—

$
46.00

$
66.40

Natural Gas - Henry Hub (NYMEX)

(MMbtu)⁽²⁾

(MMbtu)⁽²⁾

($/MMbtu)⁽²⁾

($/MMbtu)⁽²⁾

($/MMbtu)⁽²⁾
Jul 2022 - Dec 2022

calls

108,647

9,995,479

$
—

$
—

$
7.42
Jan 2023 - Dec 2023

calls

70,000

25,550,000

$
—

$
—

$
7.50
Jan 2024 - Dec 2024

calls

65,000

23,790,000

$
—

$
—

$
6.13
Jan 2025 - Mar 2025

calls

62,000

5,580,000

$
—

$
—

$
5.50
Jul 2022 - Dec 2022

collars

40,000

3,680,000

$
—

$
1.83

$
3.00
Jul 2022 - Nov 2022

swaps

16,838

1,027,099

$
2.60

$
—

$
—
Jul 2022 - Dec 2022⁽³⁾

swaps

78,261

7,200,000

$
2.63

$
—

$
—
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 Term Loan (see}^{Note 5 – Subsidiary Borrowers).}

~~Financial Statement Presentation~~

~~The following fair value of derivative financial instruments amounts were recorded in the Condensed Consolidated Balance Sheets (in thousands):~~

September 30, 2022

December 31, 2021
Prepaid expenses and other current assets

$
28,747

$
21,086
Other assets (long-term)

35,656

34,435
Accrued liabilities

116,008

81,456
Other liabilities (long-term)

75,079

37,989


		Weighted
		Average
	Performance	Grant Date Fair
	Share Units	Value Per Unit
Nonvested, beginning of period	1,502,239	$	9.78
Granted	1,187,638		4.87
Vested	(10,705)		7.80
Forfeited	(188,307)		10.05
Nonvested, end of period	2,490,865		7.43

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted at the date indicated:


	2023 Grant Date
	June 5, 2023
Expected term for performance period (in years)		2.6
Expected volatility		76.1	%
Risk-free interest rate		4.2	%
Fair value (in thousands)	$	5,694

Share-Based Awards to Non-Employee Directors

The Company may from time-to-time issue awards to non-employee directors pursuant to the 2023 Plan. There were no awards granted to non-employee directors during the six months ended June 30, 2023. Restricted shares vested during the six months ended June 30, 2023 relate to 2022 restricted shares issued to the non-employee directors.

A summary of activity related to restricted shares during the six months ended June 30, 2023 is as follows:


		Weighted
		Average
		Grant Date
	Restricted	Fair Value
	Shares	Per Share
Nonvested, beginning of period	42,426	$	4.95
Vested	(42,426)		4.95
Nonvested, end of period	—	$	—

Share-Based Compensation Expense

Compensation costs for share-based payments are recognized over the requisite service period. A summary of compensation expense under share-based payment arrangements is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Restricted stock units	$	945	$	1,360	$	1,443	$	1,610
Performance share units		1,124		598		2,496		803
Restricted Shares		18		56		70		121
Total	$	2,087	$	2,014	$	4,009	$	2,534

Cash-Based Incentive Compensation

In addition to share-based compensation, short-term cash-based incentive awards were granted under the Plan to all eligible employees during the six months ended June 30, 2023. The short-term cash-based incentive awards granted in 2022 were paid in March 2023.

Table of Contents

~~Although the Company has master netting arrangements with its counterparties, 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 (gain) loss~~~~. The impact of commodity derivative contracts on the Condensed Consolidated Statements of Operations were as follows (in thousands):~~

Three Months Ended September 30,

Nine Months Ended September 30,


2022

2021

2022

2021
Realized loss⁽¹⁾

$
132,289

$
30,026

$
96,315

$
53,627
Unrealized (gain) loss

(93,540)

43,111

13,577

125,529
Derivative loss

$
38,749

$
73,137

$
109,892

$
179,156

~~(1)~~

^{The nine months ended September 30, 2022 includes the effect of the}^$138.0^{million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices which occurred in June 2022.}

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

Nine Months Ended September 30,

2022

2021
Derivative loss

$
109,892

$
179,156
Derivative cash (payments) receipts, net⁽¹⁾

(1,022)

(39,554)
Derivative cash premium payments

(46,111)

(32,368)

~~(1)~~

^{The nine months ended September 30, 2022 includes}^$105.3^{million of net cash receipts related to the monetization of certain natural gas call contracts through restructuring of strike prices which occurred in June 2022.}

~~NOTE 9~~ — ~~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 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.

~~Share-Based Awards to Employees~~

~~Restricted Stock Units (“RSUs”)~~ – ~~During the nine months ended September 30, 2022, the Company granted RSUs under the Plan to certain employees.~~ ~~RSUs outstanding as of September 30, 2022 relate to the 2022 and 2021 grants. The 2022 RSUs granted are a long-term compensation component, subject to service conditions, with~~ ~~one-third~~ ~~of the award vesting each year on January 1, 2023, 2024, and 2025, respectively.~~

~~Table of Contents~~

~~A summary of activity related to RSUs during the nine months ended September 30, 2022 is as follows:~~

Weighted

Average

Restricted

Grant Date Fair

Stock Units

Value Per Unit
Nonvested, beginning of period

698,465

$
4.71
Granted

977,681

6.24
Vested⁽¹⁾

(387,285)

5.20
Forfeited

(66,984)

5.16
Nonvested, end of period

1,221,877

5.75

~~(1)~~

^{During May and June 2022, approximately}^22,000^{outstanding RSUs awarded in 2021 to}^two^{individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original RSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value.}

~~Performance Share Units (“PSUs”)~~ – ~~During the nine months ended September 30, 2022, the Company granted PSUs under the Plan~~ ~~that are eligible to vest based on continued employment and the Company’s total shareholder return (“TSR”)~~ ~~ranking against peer companies’ TSR~~ ~~over a three-year performance period, which ends on December 31, 2024.~~

The 2021 grants were subject to performance criteria against the applicable performance period, which ended on December 31, 2021. The PSUs granted during 2021 are eligible to vest based on continued employment through October 1, 2023.

~~A summary of activity related to PSUs during the nine months ended September 30, 2022 is as follows:~~

Weighted

Average

Performance

Grant Date Fair

Share Units

Value Per Unit
Nonvested, beginning of period

196,918

$
5.55
Granted

1,377,501

10.28
Vested ⁽¹⁾

(15,264)

5.57
Forfeited

(57,065)

8.72
Nonvested, end of period

1,502,090

9.77

~~(1)~~

^{During May and June 2022, approximately}^10,000^{outstanding PSUs awarded in 2021 to}^two^{individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original RSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value.}

~~The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted at the date indicated:~~

May 26, 2022
Expected term for performance period (in years)

2.6

Expected volatility

84.4
%
Risk-free interest rate

2.5
%
Fair value (in thousands)

$
14,163

~~Share-Based Awards to Non-Employee Directors~~

~~During the nine months ended September 30, 2022, the Company granted Restricted Shares under the~~ ~~W&T Offshore, Inc. 2004 Directors Compensation Plan~~ ~~to non-employee directors.~~ ~~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.~~

~~Table of Contents~~

~~A summary of activity related to Restricted Shares during the nine months ended September 30, 2022 is as follows:~~

Weighted

Average

Grant Date

Restricted

Fair Value

Shares

Per Share
Nonvested, beginning of period

70,226

$
3.65
Granted

42,426

4.95
Vested

(70,226)

3.65
Nonvested, end of period

42,426

$
4.95

~~Share-Based Compensation Expense~~

~~Compensation costs for share-based payments is recognized over the requisite service period. A summary of compensation expense under share-based payment arrangements is as follows (in thousands):~~

Three Months Ended September 30,

Nine Months Ended September 30,


2022

2021

2022

2021
Restricted stock units

$
1,240

$
587

$
2,852

$
1,263
Performance share units

1,352

207

2,154

207
Restricted Shares

53

64

173

309
Total

$
2,645

$
858

$
5,179

$
1,779

~~Cash-Based Incentive Compensation~~

In addition to share-based compensation, short-term cash-based incentive awards were granted under the Plan to all eligible employees during the second quarter of 2022 subject to Company performance criteria, individual performance criteria, and continued employment through the payment date. The short-term cash-based incentive awards granted in 2021 were paid in March 2022.

Share-Based Awards and Cash-Based Awards Compensation Expense

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,
	2023		2022		2023		2022
Share-based compensation included in:
General and administrative expenses	$	2,087	$	2,014	$	4,009	$	2,534
Cash-based incentive compensation included in:
Lease operating expense⁽¹⁾		321		206		1,568		462
General and administrative expenses⁽¹⁾		899		646		6,869		2,603
Total charged to operating income (loss)	$	3,307	$	2,866	$	12,446	$	5,599

Three Months Ended September 30,

Nine Months Ended September 30,


2022

2021

2022

2021
Share-based compensation included in:








General and administrative expenses

$
2,645

$
858

$
5,179

$
1,779
Cash-based incentive compensation included in:








Lease operating expense⁽¹⁾

1,532

1,119

1,994

2,774
General and administrative expenses⁽¹⁾

3,559

2,809

6,164

8,167
Total charged to operating income (loss)

$
7,736

$
4,786

$
13,337

$
12,720

(1)

^{Includes adjustments of accruals to actual payments.}

~~Table of Contents~~

NOTE 109 — INCOME TAXES

Tax ~~Benefit~~Expense (Benefit) and Tax Rate

For the three months ended ~~September~~June 30, 2023, the Company recognized income tax expense of $3.0 million. Primarily as a result of changes in our valuation allowance on our deferred tax assets, our effective tax rate for the three months ended June 30, 2023 is not meaningful. For the three months ended June 30, 2022, the Company recognized income tax expense of ~~$16.4~~$31.1 million for an effective tax rate of ~~19.7%~~20.1%.

For the ~~three~~six months ended ~~September~~June 30, ~~2021~~2023, the Company recognized income tax ~~benefit~~expense of ~~$5.9~~$11.6 million for an effective tax rate of ~~13.5%~~45.6%.

For the ~~nine~~six months ended ~~September~~June 30, 2022, the Company recognized income tax expense of ~~$46.8~~$30.4 million for an effective tax rate of ~~20.0%~~20.1%. ~~For the nine months ended September 30, 2021, the Company recognized income tax benefit of $18.8 million for an effective tax rate of 17.3%.~~

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and ~~2021,~~adjustments to the valuation allowance. For the three and six months ended June 30, 2022, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to the valuation allowance.

Calculation of Interim Provision for Income Tax.

Historically, the Company has 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 2023, the Company concluded that it could not calculate a reliable estimate of the annual effective tax rate. Accordingly, the Company computed the effective tax rate for the six-month period ending June 30, 2023 using actual results.

Valuation Allowance

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

As of ~~September~~June 30, ~~2022,~~2023 and December 31, ~~2021,~~2022, the valuation allowance was ~~$15.2~~$19.8 million and ~~$24.4~~$15.3 million, respectively, and relates primarily to state net operating losses and the disallowed interest expense limitation carryover.

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Income Taxes Receivable, Refunds and Payments

As of ~~September~~June 30, ~~2022~~2023, the Company has a federal income tax receivable of $1.7 million and state income tax receivable of $0.2 million. As of December 31, ~~2021,~~2022, the Company did not have any outstanding current income taxes receivable. During the ~~nine~~three and six months ended ~~September~~June 30, ~~2022~~2023, the Company did not receive any income tax refunds and made federal income tax payments of ~~$5.2~~$2.2 million and state income tax payments of $0.3 million. During the ~~nine~~three and six months ended ~~September~~June 30, ~~2021,~~2022, the Company did not receive any income tax refunds or make any income tax payments of significance.

The tax years 2019 through ~~2021~~2022 remain open to examination by the tax jurisdictions to which the Company is subject.

~~Table of Contents~~

NOTE 1110 — EARNINGS PER SHARE

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

								��
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021		2023		2022		2023		2022
Net income (loss)	$	66,721	$	(37,964)	$	187,700	$	(90,382)
Net (loss) income									$	(12,109)	$	123,436	$	13,896	$	120,979
Less portion allocated to nonvested shares		1,265		—		2,166		—		—		—		243		—
Net income (loss) allocated to common shares	$	65,456	$	(37,964)	$	185,534	$	(90,382)
Net (loss) income allocated to common shares									$	(12,109)	$	123,436	$	13,653	$	120,979

Weighted average common shares outstanding - basic		143,116		142,297		143,026		142,231		146,452		143,020		146,435		142,981
Dilutive effect of securities		2,766		—		1,670		—		—		1,505		2,610		1,113
Weighted average common shares outstanding - diluted		145,882		142,297		144,696		142,231		146,452		144,525		149,045		144,094
Earnings per common share:
Basic	$	0.46	$	(0.27)	$	1.30	$	(0.64)	$	(0.08)	$	0.86	$	0.09	$	0.85
Diluted		0.46		(0.27)		1.30		(0.64)		(0.08)		0.85		0.09		0.84

Shares excluded due to being anti-dilutive (weighted average)		—		1,973		—		1,266		2,909		—		—		—

NOTE 1211 — CONTINGENCIES

Appeal with the Office of Natural Resources Revenue (“ONRR”) – In 2009, W&T recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through subsea pipeline systems owned by the Company. In 2010, the ONRR audited calculations and support related to this usage fee, and ~~in 2010~~, ONRR notified the Company that they had disallowed approximately $4.7 million of the reductions taken. The Company recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, the Company disagrees with the position taken by the ONRR. W&T filed an appeal with the ONRR, which ultimately led to the Company posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the Interior Board of Land Appeals decision. The cash collateral held by the surety was subsequently returned to the Company during the first quarter of 2020. The Company has continued to pursue its 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, the Company is waiting for the district court’s ruling on the merits. In compliance with the ONRR’s request for W&T to periodically increase the surety posted in the appeal to cover pre- and post-judgement interest, the sum of the bond posted is ~~$8.2~~$8.9 million as of ~~September~~June 30, ~~2022.~~2023.

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Civil Penalties – In January 2021, W&T executed a Settlement Agreement with the Bureau of Safety and Environmental Enforcement (“BSEE”) which resolved nine pending civil penalties issued by BSEE. The civil penalties pertained to Incidents of Non-Compliance (“INC”) 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~~agreed to pay a total of $720,000 in three annual installments. The first, second and ~~second~~final installments were paid in March 2021, ~~and~~ March 2022 and February 2023, respectively. ~~In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022, which is on schedule to be completed before the deadline~~. ~~Additionally in October 2022, BSEE issued a civil penalty assessment for approximately $24,000 for an INC that occurred at one of the Company’s properties in 2021.~~

~~Table of Contents~~

~~Retained Liabilities Related to Divested Property Interests~~Contingent Decommissioning Obligations – The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. ~~For example, recent historical declines~~Certain counterparties in ~~commodity prices created an environment where there is an increased risk~~past divestiture transactions or third parties in existing leases that ~~owners and/~~have filed for bankruptcy protection or ~~operators of interests purchased from the Company~~undergone associated reorganizations may ~~no longer~~not be able to ~~satisfy plugging or~~perform required abandonment ~~obligations that attach to those interests. In that event, due~~obligations. Due to operation of law, W&T may be required to assume ~~plugging or abandonment~~decommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. W&T no longer owns these assets nor are they related to current operations.

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 were previously divested by the Company, W&T recorded aan initial contingent loss ~~contingency~~ accrual of $4.5 million related to anticipated decommissioning obligations, which was reflected in Other (income) expense, net on the Condensed Consolidated Statements of Operations in the period recorded. The Company reassessed the recorded contingent loss related to the anticipated ~~cost~~decommissioning obligations throughout 2022, and as of December 31, 2022, the total loss contingency recorded was $20.4 million. The additional $15.9 million recorded in 2022 was reflected in Other (income) expense, net on the Condensed Consolidated Statements of Operations in the period recorded. During the six months ended June 30, 2023, the Company incurred $3.4 million in costs related to ~~decommission~~these decommissioning obligations and reduced the liability accordingly. As of June 30, 2023, the remaining loss contingency recorded related to the anticipated decommissioning obligations was $17.0 million.

Although it is reasonably possible that the Company could receive additional state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise the Company’s opinion regarding the outcome of certain ~~wells, pipelines,~~notices or matters, and ~~production facilities for~~such developments could have a material adverse effect on the Company’s results of operations in the period in which the amounts are accrued and the Company’s cash flows in the period in which the amounts are paid. To the extent that the Company ~~may receive decommissioning orders from BSEE. W&T no longer owns~~does incur costs associated with these ~~assets nor are they related to current operations.~~properties in future periods, W&T intends to seek contribution from other parties that owned an interest in the facilities. As of September 30, 2022, W&T estimates that the Company’s potential liability to fund decommissioning of previously divested property interests is $4.9 million, which has been accrued as a loss contingency.

~~AAIT Litigation –~~ In August 2022, the Company’s primary information technology service provider, All About IT, Inc. (“AAIT”), notified the Company of its intention to cease providing services to the Company by September 2, 2022. The Company has begun the process of moving certain of these services within the Company and transitioning the remaining services to new service providers (the “transition process”). On August 19, 2022, the Company filed in the District Court of Harris County, Texas a petition for a temporary restraining order, temporary injunction, and permanent injunction seeking, among other things, to restrain AAIT from ceasing to provide services to the Company until the transition process is complete. On September 14, 2022, AAIT removed the matter to the United States District Court for the Southern District of Texas. On September 16, 2022, the Company and AAIT mutually agreed to the terms of an agreed order of the court providing for a temporary injunction for a period of a minimum of 60 days from the date of the order and up to a maximum of 120 days at the Company’s option, during which AAIT would continue to provide information technology services to the Company and assist with the transition process. By agreement of the parties, the agreed order also provided for the appointment of Hon. Gregg J. Costa (Ret.) as an independent adjudicator to assist in adjudicating ongoing disputes between the parties.

Other Claims – W&T is a party to various pending or threatened claims and complaints seeking damages or other remedies concerning commercial operations and other matters in the ordinary course of its business. In addition, claims or contingencies may arise related to matters occurring prior to the Company’s acquisition of properties or related to matters occurring subsequent to the Company’s sale of properties. In certain cases, W&T has indemnified the sellers of properties acquired, and in other cases, W&T has indemnified the buyers of properties sold. The Company is 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 W&T can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have, the Company believes 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 the consolidated financial position, results of operations or liquidity of the Company.

2320

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NOTE 13 12 — ~~SUBSEQUENT EVENTS~~ RELATED PARTY TRANSACTIONS

On ~~November 1, 2022,~~May 15, 2023, the ~~$552.5 million principal~~Company acquired a corporate aircraft from a company affiliated with and controlled by W&T’s CEO. The purchase price of the ~~Senior Second Lien Notes were reclassified from long-term debt to current debt as~~aircraft was $19.1 million, which was paid using $9.0 million of cash on hand and through the assumption of the TVPX Loan, which had a ~~result~~fair market value of ~~their November 1, 2023 maturity date. See~~ ~~Note 2 – Debt~~ ~~for additional information.~~

~~On November 7, 2022,~~$10.1 million on the ~~Company entered into the Eleventh Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity~~ date and Lender commitment to January 3, 2024, or in the event the Senior Second Lien Notes are not refinanced or replaced in full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023. Outstanding borrowings will accrue interest at SOFR plus ~~6.0%~~ ~~per annum. The commitment fee for the unused portion~~ of ~~available borrowing amounts will be~~ ~~3.0% per annum. In connection with the Eleventh Amendment, the Company paid to Calculus an extension fee of $100,000.~~assumption. The terms of ~~the Eleventh Amendment~~this transaction were reviewed and approved by the Audit Committee of the Company’s Board of ~~Directors~~Directors. See Note 2 – Debt for additional information.

The aircraft was purchased as part of a series of transactions pursuant to which the Company restructured the compensation for its Named Executive Officers. Prior to the Company’s purchase of the ~~Company.~~aircraft, the Company used the aircraft for business purposes, and the CEO also used the aircraft for personal purposes. Both the Company’s use for business purposes and the CEO’s unlimited use for personal purposes were paid for by the Company pursuant to the CEO’s prior employment agreement. In connection with the Company’s efforts to significantly reduce overall executive compensation, including perquisite compensation Mr. Krohn was receiving for personal use of the aircraft, on April 20, 2023, the Company entered into an amendment to the employment agreement with the CEO which requires that the Company be reimbursed for personal use of the aircraft in accordance with the Company’s aircraft use policy.

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Table of Contents

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, as well as our audited Consolidated Financial Statements and the notes thereto in ~~our 2021~~2022 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 ~~2021~~2022 Annual Report. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “W&T” or the “Company” are to W&T Offshore, Inc. and its wholly owned subsidiaries.

Cautionary Note Regarding Forward-Looking Statements

The information in this Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, 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 Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These forward-looking statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Although we believe that these forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. 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. When used in this Quarterly 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~~Readers are cautioned not to place undue reliance on forward-looking statements, ~~are based on~~which speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.

The information included in this Quarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our ~~current~~expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations ~~and assumptions about future events and are based on currently available information~~ as to ~~the outcome~~our future financial position, liquidity, cash flows, results of operations and ~~timing~~business strategy, potential acquisition opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and operating costs, reserves, hedging activities, capital expenditures, return of ~~future events.~~

~~These forward-looking statements are subject to risks, uncertainties~~capital, improvement of recovery factors 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~~other guidance. Actual results may differ from anticipated results, sometimes materially, ~~from those expressed or implied by~~and reported results should not be considered an indication of future performance. For any such forward-looking ~~statements and assumptions. These statements are based on certain~~statement that includes a statement of the 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~~or bases underlying such forward-looking statement, we caution that, while we believe ~~are appropriate~~such assumptions or bases to be reasonable and make them in ~~the circumstances.~~ good faith, assumed facts or bases almost always vary from actual results, sometimes materially. 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 ~~2021~~2022 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the SEC.

Reserve engineering is a process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGLs and natural gas that are ultimately recovered.

~~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 Quarterly 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.

2522

Table of Contents

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of ~~September~~June 30, ~~2022,~~2023, we hold working interests in 4746 producing offshore fields in federal and state waters ~~(45 fields producing and 2 fields capable of producing, which~~(which include 3938 fields in federal waters and 8 in state waters). We currently have under lease approximately ~~622,000~~578,000 gross acres ~~(449,500~~(419,000 net acres) spanning across the outer continental shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama state waters, ~~449,000~~416,500 gross acres on the conventional shelf and approximately ~~165,000~~153,500 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 and, W ~~& T~~&T Energy VI, LLC, each of which are Delaware limited liability companies, and through our proportionately consolidated interest in ~~Monza, as described in more detail in~~ ~~Financial Statements – Note 6 – Joint Venture Drilling Program~~ ~~under Part I, Item 1 in this Quarterly Report.~~Monza.

Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas 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 realized sales prices received for our crude oil, NGLs and natural gas production are affected by 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 geopolitical and economic events.

In addition to such industry-specific risks, the global public health crisis associated with COVID-19 has created uncertainty for global economic activity since March 2020. Since 2021, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. However, new variants of the 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.

However, a high level of uncertainty remains regarding the volatility of energy supply and demand as a result of Russia’s full-scale invasion of Ukraine in February 2022. As a result of the war, several countries imposed sanctions on imports of crude oil and petroleum products from Russia. In addition, many international oil companies and other firms ended operations in Russia and limited or stopped trading Russia’s crude oil and petroleum products. These actions have reduced Russia’s oil production and caused crude oil prices to rise. Most recently, Russia has increased strikes on Ukraine which may result in further sanctions against Russia. Additionally in early October 2022 the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) announced a production cut of approximately two million barrels per day which has put additional upward pressure on oil prices. As a result, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves.

~~The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on October 12, 2022.~~ WTI crude oil prices and NYMEX Henry Hub natural gas prices have decreased following the surge in prices during ~~the first half of~~ 2022, closing the ~~third~~second quarter at ~~approximately $80.00~~$70.66 per barrel and ~~$6.50~~$2.48 per Mcf, respectively. ~~Prior to the OPEC+ announcement, crude oil prices were generally decreasing in response to the overall indications of slowing global economic growth. While oil spot prices increased in the immediate aftermath of OPEC+’s announcement, t~~heThe U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on July 11, 2023. The EIA expects the WTI spot price average to ~~decrease to $85.98~~remain relatively flat in the third quarter of 2023 at $73.32 per barrel ~~during the fourth quarter of 2022~~ as compared to the ~~third~~second quarter ~~2022~~2023 average of ~~$93.07~~$73.49 per barrel. The EIA ~~also~~ expects the average Henry Hub spot price to ~~average $7.70 per Mcf during the fourth quarter of 2022 as compared to $8.30~~increase during the third quarter of ~~2022.~~

~~Table of Contents~~

As2023 to $2.74 per Mcf as compared to the second quarter 2023 average of $2.25 per Mcf.

In June 2023 the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC Plus”) announced that prior ~~year, spot prices remain high, likely as a result~~production cuts of ~~low inventories~~over 3.6 million barrels per day, which were valid until the end of 2023, had been extended until the end of 2024. OPEC also announced plans to further reduce production targets by an additional 1.4 million barrels per day beginning in January 2024. Saudi Arabia also announced plans in June to reduce the country’s output by over 1.0 million barrels per day beginning in July 2023. Despite these OPEC Plus production cuts, the EIA expects that the global oil markets will see an overall increase in oil supply during 2023 primarily because of growth from non-OPEC producers. In addition, increasing risk in the U.S. and ~~continued~~global banking sectors creates uncertainty ~~surrounding the Russia-Ukraine conflict~~about macroeconomic conditions and ~~the related~~their potential effects on ~~future~~ oil demand growth, which has the potential to result in lower oil prices. These shifts in OPEC Plus production levels as well as the Russia-Ukraine war and ~~gas supply. Per the EIA, average crude oil prices using the WTI daily spot price increased~~related sanctions, and overall indicators of slowing global economic growth, continue to ~~$98.96 per barrel during the nine months ended September 30, 2022 compared~~contribute to $65.05 per barrel during the nine months ended September 30, 2021 (52.1% increase). The NYMEX Henry Hub average daily natural gas spot price increased to $6.74 per Mcf for the nine months ended September 30, 2022 compared to $3.61 per Mcf during the nine months ended September 30, 2021 (87.0% increase).a high level of uncertainty surrounding energy supply and demand, putting additional pressure on commodity prices.

Rising Interest Rates and Inflation of Cost of Goods, Services and Personnel – Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. Continued inflationary pressures and increased commodity may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

T23

~~he annual rate~~Table of ~~inflation in the~~Contents

The United States ~~was measured~~has experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at ~~8.2% in September~~9.1% but has been gradually declining since the second half of 2022 byaccording to the Consumer Price ~~Index,~~Index. As of June 2023, the ~~highest in more than four decades. In addition,~~annual inflation rate had slowed to 3.0% according to the Consumer Price Index. Though inflation is currently on the decline, these inflationary pressures have caused the Federal Reserve ~~has tightened~~to tighten monetary policy by approving a series of increases to the Federal Funds Rate. On July 26, 2023, the Federal Reserve increased the Federal Funds Rate ~~and signaled that~~by another 0.25 percentage points, its eleventh hike since March 2022. This latest rate hike brought the Federal Reserve benchmark rate range to 5.25% to 5.50%. If inflation were to continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary ~~action~~ to bring inflation down and to ensure price stability, including further rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could ~~hurt~~negatively impact our business.

As a result of these factors, 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 drilling program, production volumes or revenues.

~~Inflation Reduction Act of 2022 (the “IRA”)~~Planned and Unplanned Downtime –~~On August 16, 2022, President Biden signed the IRA into law. Several provisions in the IRA~~We are ~~expected~~subject to apply to our business. For instance, the IRA specifically directs the Department of the Interior (”DOI”) to accept the highest bids received for Lease Sale 257, which was vacated by US District Court for the District of Columbia in January 2022 and move forward with Lease Sales 259 and 261 in the Gulf of Mexico by March 31, 2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.

The IRA ties the issuance of offshore leases for wind development by the federal government to requirements to offer for sale federal oil and gas leases for a 10-year period of time. The IRA requires the federal government to offer for sale a minimum of 60 million acres for offshore oil and gas leases during the one-year period immediately preceding granting an offshore wind lease on the U.S. Outer Continental Shelf.

The IRA also increases the minimum oil and gas royalty rate for new offshore leases from the current 12.50% to 16.67% and caps the royalty rate at 18.75% for 10 years. The 18.75% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters. This provision does not affect existing offshore leases.

Furthermore, the IRA imposes a methane emissions charge. The IRA amends the federal Clean Air Act to impose a fee on emissions of methane from sources required to report their greenhouse gas emissions to the U.S. Environmental Protection Agency (“EPA”), including sources in the offshore and onshore oil and gasdowntime events impacting production, ~~and onshore processing, transmission and compression,~~transportation, gathering and ~~boosting station source categories. For~~processing of our production.Unplanned or planned downtime may be caused, for example, by certain regulatory requirements and inspections or third-party pipeline maintenance. During such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024. In 2025, the charge increases to $1,200 per metric ton of methane. For calendar year 2026 and thereafter, the fee will be $1,500 per metric ton of methane. Calculation of the chargedowntime, our operating income is ~~based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and~~negatively impacted. During the first ~~fee payment will be in 2025 based on 2024 data. The methane emissions charge may increase~~quarter of 2023, our ~~operating costs~~production was temporarily impacted by planned maintenance at Mobile Bay and ~~adversely affect~~unplanned downtime at other non-operated fields. During the second quarter of 2023, our ~~business.~~production was negatively impacted by unplanned downtime due to third-party pipeline maintenance and production downtime at non-operated fields.

~~Table of Contents~~

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. AsThe Department of Interior is reviewing many BOEM regulations and proposed a rule in June 2023 that would revise BOEM’s criteria for determining whether lessees are ~~being reviewed by the Department of the Interior,~~required to provide supplemental financial insurance. Accordingly, we may be subject to additional financial assurance requirements in the future. As of the filing date of this Quarterly Report, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to supplemental financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.

Surety Bond Collateral – Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes or bonds associated with our appeals of Department of the Interior’s orders or demands have on occasion 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 ~~2022~~the six months ended June 30, 2023 and we do not have surety bond collateral outstanding as of the filing date of this Quarterly ~~Report and we currently do not have surety bond collateral outstanding.~~Report. 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.

Table of Contents

Results of Operations

Three Months Ended ~~September~~June 30, ~~2022~~2023 Compared to the Three Months Ended ~~September~~June 30, ~~2021~~2022

Revenues

Our revenues are derived from the sale of 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 (gain) loss, net in our Condensed Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:


	Three Months Ended September 30,				Three Months Ended June 30,
	2022		2021		2023		2022
Oil	49.0	%	55.4	%	71.3	%	58.1	%
NGLs	6.3	%	9.1	%	8.2	%	6.1	%
Natural gas	42.7	%	33.7	%	18.6	%	33.8	%
Other	2.0	%	1.8	%	1.9	%	2.0	%

~~Table of Contents~~

The information below provides a discussion of, and an analysis of significant ~~variance~~variances 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 ~~September~~June 30, ~~2022~~2023 and ~~2021:~~2022:


	Three Months Ended September 30,						Three Months Ended June 30,
	2022		2021			Change	2023		2022			Change










	(In thousands, except realized sales price data)						(In thousands, except realized sales price data)
Revenues:
Oil	$	130,560	$	74,265	$	56,295	$	89,982	$	159,264	$	(69,282)
NGLs		16,875		12,205		4,670		10,385		16,735		(6,350)
Natural gas		113,673		45,137		68,536		23,438		92,413		(68,975)
Other		5,377		2,339		3,038		2,376		5,396		(3,020)
Total revenues		266,485		133,946		132,539		126,181		273,808		(147,627)

Production Volumes:
Oil (MBbls)		1,447		1,083		364		1,254		1,476		(222)
NGLs (MBbls)		454		376		78		443		384		59
Natural gas (MMcf)		11,499		10,481		1,018		10,023		11,995		(1,972)
Total oil equivalent (MBoe)		3,818		3,206		612		3,368		3,859		(491)

Average daily equivalent sales (Boe/day)		41,500		34,848		6,652		37,011		42,407		(5,396)

Average realized sales prices:
Oil ($/Bbl)	$	90.23	$	68.57		21.66	$	71.76	$	107.90		(36.14)
NGLs ($/Bbl)		37.17		32.46		4.71		23.44		43.58		(20.14)
Natural gas ($/Mcf)		9.89		4.31		5.58		2.34		7.70		(5.36)
Oil equivalent ($/Boe)		68.39		41.05		27.34		36.76		69.55		(32.79)
Oil equivalent ($/Boe), including realized commodity derivatives⁽¹⁾		50.86		31.95		18.91		36.67		94.20		(57.53)

(1)

^{Excludes the effects of premium amortization and write-offs.amortization.}


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

Table of Contents

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 ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022 (in thousands):


	Price		Volume		Total		Price		Volume		Total
Oil	$	31,321	$	24,975	$	56,296	$	(45,386)	$	(23,896)	$	(69,282)
NGLs		2,124		2,546		4,670		(9,152)		2,802		(6,350)
Natural gas		64,150		4,385		68,535		(53,782)		(15,193)		(68,975)
	$	97,595	$	31,906	$	129,501	$	(108,320)	$	(36,287)	$	(144,607)

~~Table of Contents~~

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~~differential of WTI versus ~~HLS~~LLS and ~~LLS~~HLS for the three months ended ~~September~~June 30, ~~2022~~2023 was favorable to the Company and increased on average by approximately ~~$0.27~~$0.35 and ~~$1.00~~$1.30 per barrel, ~~respectively.~~respectively, compared to the same period in 2022. The ~~monthly~~ average differential for WTI versus Poseidon for the three months ended June 30, 2023 was unfavorable to the Company and declined on average by approximately ~~$2.74~~$1.12 per barrel compared to the same period in ~~2021.~~2022.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the three months ended ~~September~~June 30, ~~2022~~2023 compared to the three months ended ~~September~~June 30, ~~2021,~~2022, average prices for domestic ethane ~~increased~~decreased by ~~58.0%~~64.0% and average domestic propane prices ~~increased~~decreased by ~~61.8%~~68.6% as measured using a price index for Mount Belvieu. The average prices for normal butane ~~increased~~decreased by ~~7.8%~~49.8% while other domestic NGL components decreased between ~~7.2%~~46.1% and ~~11.5%~~48.1% for the three months ended ~~September~~June 30, ~~2022~~2023 compared to the same period in ~~2021.~~2022. The change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.

The 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. The sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

Oil, NGLs, and Natural Gas Volumes – Production volumes ~~increased~~decreased by ~~612~~491 MBoe to ~~3,818~~3,368 MBoe induring the three months ended ~~September~~June 30, ~~2022~~2023 compared to the same period in ~~2021,~~2022, primarily due to ~~the acquisition~~third party deepwater pipeline maintenance and production downtime at non-operated fields.

Table of ~~the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields during the first and second quarters of 2022. See~~ ~~Financial Statements – Note 4 – Acquisitions~~ under Part I, Item 1 of this Quarterly Report for additional information. These increases were partially offset by shut-ins related to field and well maintenance primarily at Mobile Bay and Shelf fields.Contents

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes:


							Three Months Ended June 30,
							2023		2022			Change








	Three Months Ended September 30,
	2022		2021			Change
								(In thousands, except per Boe data)
Operating expenses:
Lease operating expenses	$	59,010	$	39,490	$	19,520	$	66,021	$	52,976	$	13,045
Gathering, transportation and production taxes		12,199		6,593		5,606		6,802		9,181		(2,379)
Depreciation, depletion, amortization and accretion		34,113		26,291		7,822		35,894		34,360		1,534
General and administrative expenses		23,047		13,391		9,656		17,393		14,967		2,426
Total operating expenses	$	128,369	$	85,765	$	42,604	$	126,110	$	111,484	$	14,626

Average per Boe ($/Boe):
Lease operating expenses	$	15.46	$	12.32	$	3.14	$	19.60	$	13.73	$	5.87
Gathering, transportation and production taxes		3.20		2.06		1.14		2.02		2.38		(0.36)
DD&A		8.93		8.20		0.73		10.66		8.90		1.76
G&A expenses		6.04		4.18		1.86		5.16		3.88		1.28
Operating expenses	$	33.63	$	26.76	$	6.87	$	37.44	$	28.89	$	8.55

~~Table of Contents~~

Lease operating expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased ~~$19.5~~$13.0 million to ~~$59.0~~$66.0 million for the three months ended ~~September~~June 30, ~~2022~~2023 compared to ~~$39.5~~$53.0 million for the three months ended ~~September~~June 30, ~~2021.~~2022. On a component basis, base lease operating expenses increased ~~$15.0~~ $4.7 million, workover expenses increased ~~$1.0~~$6.3 million, and facilities maintenance expense increased ~~$4.3 million, and hurricane repairs decreased $0.8~~$2.0 million.

Base lease operating expenses increased primarily due to increased ~~expenses related to the fields acquired during the first two quarters of 2022, increased~~ contract labor, equipment rental, and transportation costs at various fields, and increased insurance expense. The increases in workover expenses and facilities maintenance ~~expense~~expenses 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 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 September 30, 2021 we incurred $0.8 million in expenses related to repairs associated with hurricanes that we did not incur during the three months ended September 30, 2022.

Gathering, transportation and production taxes – Gathering, transportation and production taxes ~~increased $5.6~~decreased $2.4 million infor the three months ended ~~September~~June 30, ~~2022~~2023 compared to the three months ended ~~September~~June 30, ~~2021 p~~2022 ~~rimarily~~ due to ~~a new transportation contract related to the properties acquired~~decreases in ~~the first half of 2022. Additionally, the increase~~production volumes and decreases in realized natural gas and NGL prices along with an increase in oil, NGL and natural gas production during the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 caused gathering, transportation and production taxes to increase.prices.

Depreciation, depletion, amortization and accretion (“DD&A”) – DD&A, which includes accretion for ARO, increased $1.5 million for the three months ended June 30, 2023 as compared to the three months ended June 30, 2022. The DD&A rate increased to ~~$8.93~~$10.66 per Boe for the three months ended ~~September~~June 30, ~~2022~~2023 from ~~$8.20~~$8.90 per Boe for the three months ended ~~September~~June 30, ~~2021. On a nominal basis, DD&A~~2022. The increased ~~$7.8 million for the three months ended September 30, 2022 as compared to the three months ended September 30, 2021~~expense was primarily due to ~~an increased DD&A per Boe rate and, to a lesser extent, the increase in production volumes. The DD&A rate per Boe increased~~ ~~mostly as a result of~~ increases ~~in capital expenditures and future development costs included~~ in the depreciable base ~~associated with an increase in economic proved undeveloped wells~~ due to ~~higher oil~~increased capital spending and ~~gas prices~~ ~~compared to~~increased future development costs since the ~~smaller increase in proved reserves over the comparable prior year period.~~second quarter of 2022, partially offset by lower production volumes.

General and administrative expenses (“G&A”) – G&A increased ~~$9.7~~$2.4 million, to ~~$23.0~~$17.4 million for the three months ended ~~September~~June 30, ~~2022~~2023 as compared to ~~$13.4~~$15.0 million for the three months ended ~~September~~June 30, ~~2021.~~ 2022. The increase is primarily due to ~~non-recurring professional services incurred during the third quarter of 2022 after a review of processes~~increased payroll costs, incentive compensation expense and controls within our information technology department, including additional non-recurring expenses associated with the process of transitioning substantially all of our information technology infrastructure and related services internally or to other providers. Further, we have incurred additional legal ~~expenses in conjunction therewith. Additionally, we~~expenses. We incurred increased incentive compensation costs related to ~~the higher grant date fair value of RSU and PSU~~share-based compensation awards granted during ~~2022 as compared to~~ the ~~value~~second quarter of ~~awards granted in 2021.~~2023.

Table of Contents

Other Income and Expense

The following table presents the components of other income and expense for the periods presented and corresponding changes:


							Three Months Ended June 30,
							2023		2022			Change








	Three Months Ended September 30,
	2022		2021			Change
							(In thousands)
Other income and expenses:
Derivative loss	$	38,749	$	73,137	$	(34,388)
Derivative (gain) loss, net							$	(829)	$	(8,854)	$	8,025
Interest expense, net		16,849		18,910		(2,061)		10,323		18,183		(7,860)
Other (income) expense, net		(600)		—		(600)		(311)		(1,534)		1,223
Income tax expense (benefit)		16,397		(5,902)		22,299
Income tax expense								2,997		31,093		(28,096)

~~Table of Contents~~

Derivative (gain) loss, net – During the three months ended ~~September~~June 30, ~~2022,~~2023, the ~~$38.7~~$0.8 million derivative ~~loss~~gain recorded for crude oil and natural gas derivative contracts consists of ~~$132.3 million of realized losses on settled contracts and premium amortization and $93.5~~$1.1 million of unrealized gain ~~net~~ from the increase in the fair value of open ~~contracts.~~contracts, partially offset by $0.3 million of realized losses. During the three months ended ~~September~~June 30, ~~2021,~~2022, the ~~$73.1~~$8.9 million derivative ~~loss~~gain recorded for crude oil and natural gas derivative contracts consisted of ~~$30.0~~$79.7 million in realized ~~losses~~gains and ~~$43.1~~$70.8 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.

In the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of certain outstanding purchased calls covering the second half of 2022 through the first quarter of 2025 by increasing the weighted-average strike prices. These transactions resulted in net cash proceeds of $105.3 million.

Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value ~~of all~~ of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through April 2028, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for ~~oil and~~ natural gas. See Financial Statements – Note ~~8 –Derivative~~4 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information.

Interest expense, net – Interest expense, net, was ~~$16.8~~$10.3 million and ~~$18.9~~$18.2 million for the three months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, respectively. The decrease of ~~$2.1~~$7.9 million in ~~2022~~2023 is ~~primarily~~ due to the redemption of the 9.75% Senior Second Lien Notes which occurred in February 2023, lower interest expense on the lower outstanding principal balance of the Term Loan and increased interest income. These decreases were partially offset by interest expense incurred on the 11.75% Senior Second Lien Notes issued in late January 2023.

Income tax expense (benefit) – Income tax expense for the three months ended ~~September~~June 30, 2023 and June 30, 2022 was ~~$16.4~~$3.0 million ~~compared to an income tax benefit of $5.9~~and $31.1 million, ~~during the three months ended September 30, 2021.~~respectively. For the three months ended ~~September~~June 30, 2023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and adjustments to the valuation allowance. For the three months ended June 30, 2022, ~~and 2021, our income~~the Company’s effective tax ~~benefit~~rate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to the valuation allowance. Primarily as a result of changes in our valuation ~~allowance. Our~~allowance on our deferred tax assets, our effective tax rate ~~was 19.7% and 13.5%~~ for the three months ended ~~September~~June 30, ~~2022 and 2021, respectively.~~2023 is not meaningful. The company’s effective tax rate was 20.1% for the three months ended June 30 2022.

As of ~~September~~June 30, ~~2022,~~2023, the valuation allowance on our deferred tax assets was ~~$15.2~~$19.8 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 ~~10 –Income~~9 – Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

~~Nine~~28

Table of Contents

Six Months Ended ~~September~~June 30, ~~2022~~2023 Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022

Revenues


	Nine Months Ended September 30,				Six Months Ended June 30,
	2022		2021		2023		2022
Oil	56.4	%	61.3	%	72.6	%	60.7	%
NGLs	6.5	%	7.7	%	7.0	%	6.6	%
Natural gas	35.2	%	29.0	%	18.7	%	30.9	%
Other	1.9	%	2.0	%	1.7	%	1.8	%

~~Table of Contents~~

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 ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021:~~2022:


							Six Months Ended June 30,
							2023		2022			Change








	Nine Months Ended September 30,
	2022		2021			Change
								(In thousands, except realized sales price data)
Revenues:
Oil	$	412,526	$	240,418	$	172,108	$	186,982	$	281,966	$	(94,984)
NGLs		47,430		30,397		17,033		18,180		30,555		(12,375)
Natural gas		257,452		113,816		143,636		48,242		143,779		(95,537)
Other		13,889		7,790		6,099		4,502		8,512		(4,010)
Total revenues	$	731,297	$	392,421	$	338,876	$	257,906	$	464,812	$	(206,906)

Production Volumes:
Oil (MBbls)		4,227		3,812		415		2,604		2,780		(176)
NGLs (MBbls)		1,187		1,105		82		738		733		5
Natural gas (MMcf)		33,965		33,469		496		17,699		22,466		(4,767)
Total oil equivalent (MBoe)		11,075		10,495		580		6,292		7,257		(965)

Average daily equivalent sales (Boe/day)		40,568		38,444		2,124		34,762		40,094		(5,332)

Average realized sales prices:
Oil ($/Bbl)	$	97.59	$	63.07	$	34.52	$	71.81	$	101.43	$	(29.62)
NGLs ($/Bbl)		39.96		27.51		12.45		24.63		41.68		(17.05)
Natural gas ($/Mcf)		7.58		3.40		4.18		2.73		6.40		(3.67)
Oil equivalent ($/Boe)		64.78		36.65		28.13		40.27		62.88		(22.61)
Oil equivalent ($/Boe), including realized commodity derivatives⁽¹⁾		63.76		31.71		32.05		40.19		70.53		(30.34)

(1)

^{Excludes the effects of premium amortization and write-offs.}

Table of Contents

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 ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022 (in thousands):


	Price		Volume		Total		Price		Volume		Total
Oil	$	145,927	$	26,181	$	172,108	$	(77,129)	$	(17,855)	$	(94,984)
NGLs		14,897		2,136		17,033		(12,751)	$	376		(12,375)
Natural gas		141,950		1,686		143,636		(65,032)		(30,505)		(95,537)
	$	302,774	$	30,003	$	332,777	$	(154,912)	$	(47,984)	$	(202,896)

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, LLS, and HLS. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The ~~monthly~~ average ~~differentials~~differential of WTI versus ~~Poseidon~~LLS for the six months ended June 30, 2023 was favorable to the Company and increased on average by approximately $0.31 per barrel, compared to the same period in 2022. The average differential of WTI versus HLS for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 was favorable to the Company and remained flat compared to the same period in 2022. The average differential for WTI versus Poseidon for the six months ended June 30, 2023 was unfavorable to the Company and declined on average by approximately ~~$2.30 and $0.26 per barrel, respectively. The monthly average differential for WTI versus LLS increased on average by approximately $0.32~~$0.86 per barrel compared to ~~2021.~~the same period in 2022.

~~Table of Contents~~

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, average prices for domestic ethane ~~increased~~decreased by ~~65.5%~~53.3% and average domestic propane prices ~~increased~~decreased by ~~15.5%~~58.4% as measured using a price index for Mount Belvieu. The average prices for normal butane decreased by 39.0% while other domestic NGLs components ~~increased~~decreased between ~~21.1%~~38.9% and ~~34.0%~~41.3% for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the same period in ~~2021.~~2022. The change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.

Oil, NGLs, and Natural Gas Volumes – Production volumes ~~increased~~decreased by ~~580~~965 MBoe to ~~11,075~~6,292 MBoe during the ~~nine~~six months ended ~~September~~June 30, ~~2022 as~~2023 compared to ~~production volumes during~~ the ~~nine months ended September 30, 2021.~~same period in 2022 primarily due to shut-ins related to field and well maintenance at Mobile Bay during the ~~acquisition~~first quarter of ~~the Ship Shoal 230, South Marsh Island 27/Vermilion 191,~~2023 as well as third party deepwater pipeline maintenance and ~~South Marsh Island 73~~production downtime at non-operated fields during the first and second quarters of ~~2022. See~~ ~~Financial Statements – Note 4 – Acquisitions~~ ~~under Part I, Item 1~~2023.

Table of ~~this Quarterly Report for additional information. These increases were partially offset by shut-ins related to field and well maintenance primarily at Mobile Bay and Shelf fields.~~Contents

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes:


	Nine Months Ended September 30,						Six Months Ended June 30,
	2022		2021			Change	2023		2022			Change










	(In thousands, except per Boe data)						(In thousands, except per Boe data)
Operating expenses:
Lease operating expenses	$	155,397	$	129,399	$	25,998	$	131,207	$	96,387	$	34,820
Gathering, transportation and production taxes		26,647		19,687		6,960		12,938		14,448		(1,510)
Depreciation, depletion, amortization and accretion		99,384		83,879		15,505		66,028		65,271		757
General and administrative expenses		51,790		38,090		13,700		37,312		28,743		8,569
Total operating expenses	$	333,218	$	271,055	$	62,163	$	247,485	$	204,849	$	42,636

Average per Boe ($/Boe):
Lease operating expenses	$	14.03	$	12.33	$	1.70	$	20.85	$	13.28	$	7.57
Gathering, transportation and production taxes		2.41		1.88		0.53		2.06		1.99		0.07
DD&A		8.97		7.99		0.98		10.49		8.99		1.50
G&A expenses		4.68		3.63		1.05		5.93		3.96		1.97
Operating expenses	$	30.09	$	25.83	$	4.26	$	39.33	$	28.22	$	11.11

Lease operating expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased ~~$26.0~~$34.8 million to ~~$155.4~~$131.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to ~~$129.4~~$96.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. On a component basis, base lease operating expenses increased ~~$16.8~~$16.0 million, workover expenses increased ~~$4.3~~$8.4 million, facilities maintenance expense increased ~~$9.1~~$10.7 million, and hurricane repairs decreased ~~$4.2~~$0.3 million.

~~Table of Contents~~

Base lease operating expenses increased ~~primarily~~ due to increased expenses related to a full six months of expenses at the ~~Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73~~ fields acquired during ~~the first half of~~February 2022 as well as increased contract labor, equipment rental, and transportation costs at various fields, and increased insurance expense. The increases in workover expenses and facilities maintenance ~~expense~~expenses 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 production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. Lastly, during the nine months ended September 30, 2021 we incurred $4.2 million in expenses related to repairs associated with hurricanes that we did not incur during the nine months ended September 30, 2022.

Gathering, transportation and production taxes – Gathering, transportation and production taxes ~~increased $7.0~~decreased $1.5 million infor the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 primarily due to ~~a new~~decreases in production volumes and decreases in realized prices partially offset by the transportation contract related to the properties acquired in ~~the first half of~~February 2022. Additionally, the increase in realized natural gas and NGL prices along with an increase in oil, NGL and natural gas production during the nine months ended September 30, 2022 as compared to the comparable prior year period caused gathering, transportation and production taxes to increase.

Depreciation, depletion, amortization and accretion – DD&A, which includes accretion for ~~AROs,~~ARO, increased $0.8 million for the six months ended June 30, 2023 as compared to the six months ended June 30, 2022. The DD&A rate increased to ~~$8.97~~$10.49 per Boe for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 from ~~$7.99~~$8.99 per Boe for the ~~nine~~six months ended ~~September~~June 30, ~~2021. On a nominal basis,~~2022. The slight increase in DD&A ~~increased $15.5 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021~~expense was primarily due to ~~a higher DD&A per Boe rate. The DD&A rate per Boe increased mostly as a result of~~ increases ~~in the capital expenditures and future development costs included~~ in the depreciable base ~~associated with an increase in economic proved undeveloped wells~~ due to ~~higher oil~~ increased capital spending and ~~gas prices~~ ~~compared to~~increased future development costs since the ~~smaller increase in proved reserves over the comparable prior year period.~~second quarter of 2022, partially offset by lower production volumes.

Table of Contents

General and administrative expenses – G&A increased ~~$13.7~~$8.6 million to ~~$51.8~~$37.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 as compared to ~~$38.1~~$28.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. The increase is primarily due to ~~non-recurring professional services~~increased payroll costs, ~~incurred~~incentive compensation expense, and legal expenses. The increase was partially offset by a $2.2 million employee retention credit recorded during the third quarter of 2022 after a review of processes and controls within our information technology department, including additional non-recurring expenses associated with the process of transitioning substantially all of our information technology infrastructure and related services internally or to other providers. Further, we have incurred additional legal expenses in conjunction therewith. Additionally, wesix months ended June 30, 2023. We incurred increased incentive compensation costs related to the higher value of the short-term cash-based incentive compensation awards granted in 2022 as compared to the value of awards granted in 2021, the higher grant date fair value of RSU and PSU awards granted during 2022 as compared to the value of awards granted in ~~2021.~~2021, as well as share-based compensation awards granted during the second quarter of 2023.

Other Income and Expense

The following table presents the components of other income and expense for the periods presented and corresponding changes:


							Six Months Ended June 30,
							2023		2022			Change








	Nine Months Ended September 30,
	2022		2021			Change
							(In thousands)
Other income and expenses:
Derivative loss	$	109,892	$	179,156	$	(69,264)
Derivative (gain) loss, net							$	(40,069)	$	71,143	$	(111,212)
Interest expense, net		54,915		50,474		4,441		25,036		38,066		(13,030)
Other (income) expense, net		(1,229)		964		(2,193)		(78)		(629)		551
Income tax expense (benefit)		46,801		(18,846)		65,647
Income tax expense								11,636		30,404		(18,768)

~~Derivative~~Derivative(gain) loss, net – During the ~~nine~~six months ended ~~September~~June 30, 2023, the $40.1 million derivative gain recorded for crude oil and natural gas derivative contracts consists of $0.5 million of realized losses on settled contracts and $40.6 million of unrealized gains from the increase in the fair value of open contracts. During the six months ended June 30, 2022, the ~~$109.9~~$71.1 million derivative loss recorded for crude oil and natural gas derivative contracts ~~consists~~consisted of ~~$96.3~~$36.0 million ofin realized ~~losses~~gains on settled contracts and premium amortization and $13.6 million of unrealized losses, net from the decrease in the fair value of open contracts. During the nine months ended September 30, 2021, the $179.2 million derivative loss recorded for crude oil and natural gas derivative contracts consists of $53.6 million in realized losses on settled contracts and $125.5$107.1 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.

~~Table of Contents~~

In the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of ~~strike prices on~~ certain outstanding purchased calls covering the second half of 2022 through the first quarter of ~~2025. This transaction~~2025 by increasing the weighted-average strike prices. These transactions resulted in net cash proceeds of $105.3 million, through restriking exercise prices of outstanding purchased call options. As part of this monetization, the Company restructured its purchased call options on natural gas to increase the weighted-average strike price to $7.48 per Mmbtu from $3.78 per Mmbtu for the remainder of 2022, $7.50 per Mmbtu from $3.50 per Mmbtu for 2023, $6.13 per Mmbtu from $3.50 per Mmbtu for 2024, and $5.50 per Mmbtu from $3.50 per Mmbtu for the first quarter of 2025.million.

Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through April 2028, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for ~~oil and~~ natural gas. See Financial Statements – Note ~~8 –Derivative~~4 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information.

Interest expense, net – Interest expense, net was ~~$54.9~~$25.0 million and ~~$50.5~~$38.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, respectively. The ~~increase~~decrease of ~~$4.4~~$13.0 million in ~~2022~~2023 is ~~primarily~~ due to the redemption of the 9.75% Senior Second Lien Notes which occurred in February 2023, lower interest expense on the lower outstanding principal balance of the Term Loan, and increased interest income.

~~Other (income) expense, net –~~ ~~During the nine months ended September 30, 2022, other income net, consists of non-recurring adjustments~~ These decreases were partially offset by interest expense incurred on the 11.75% Senior Second Lien Notes issued in late January 2023.

~~expenses for additional contingent abandonment obligations pertaining to certain~~Table of ~~legacy Gulf of Mexico properties. See~~Contents ~~Financial Statements– Note 12 – Contingencies~~ ~~under Part I, Item 1 of this Quarterly Report for additional information. During the nine months ended September 30, 2022,~~ ~~the amount primarily consisted of expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program.~~

Income tax expense (benefit) – Income tax expense for the ~~nine~~six months ended ~~September~~June 30, 2023 and June 30, 2022 was ~~$46.8~~$11.6 million ~~compared to an income tax benefit of $18.8~~and $30.4 million, ~~during~~respectively. For the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2023, the Company’s effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes, nondeductible compensation, and adjustments to the valuation allowance. For the ~~nine~~six months ended ~~September~~June 30, 2022, ~~and 2021, income~~the Company’s effective tax ~~benefit~~rate differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to ~~our~~the valuation allowance. ~~Our~~The Company’s effective tax rate was ~~20.0%~~45.6% and ~~17.3%~~20.1% for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, respectively.

As of ~~September~~June 30, ~~2022,~~2023, the valuation allowance on our deferred tax assets was ~~$15.2~~$19.8 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 109 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

~~Table of Contents~~

Liquidity and Capital Resources

Liquidity Overview

Our primary liquidity needs are to ~~refinance existing debt,~~ 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 ~~September~~June 30, ~~2022,~~2023, we had ~~$447.1~~$171.6 million cash on hand, and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. ~~Additionally,~~We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares or our common stock from time to time. We believe our access to the equity markets from our “at-the-market” equity offering program, our reserve based lending currently available under our Credit Agreement, along with our cash position, will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment.

As of September 30, 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 have commenced discussions with potential lenders and institutional investors regarding a 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 financings with longer tenors and market-based covenants to continue to provide working and potential acquisition capital as well as provide funding for refinancing of all or a portion of our Senior Second Lien Notes. The terms of such financings, which may replace or augment our 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 Senior Second Lien Notes. We may also consider using a portion of our cash balances to reduce the amount required to be refinanced. While the nearing maturity of the Senior Second Lien Notes creates risk with respect to our future liquidity, management believes that the actions being taken to fully repay the Senior Second Lien Notes, including from cash on hand of approximately $447 million, cash to be generated through operations, a refinancing transaction and from the proceeds of a potential equity sale of up to $100 million available under the ATM program, would allow us to repay the Senior Second Lien Notes prior to their maturity. However, there is no guarantee the Company will be successful in achieving these objectives.

Sources and Uses of Cash


	Nine Months Ended September 30,						Six Months Ended June 30,
	2022		2021			Change	2023		2022			Change

	(In thousands)











							(In thousands)
Operating activities	$	326,851	$	111,291	$	215,560	$	49,632	$	237,759	$	(188,127)
Investing activities		(89,677)		(12,406)		(77,271)		(34,538)		(78,900)		44,362
Financing activities		(35,843)		114,973		(150,816)		(304,824)		(26,934)		(277,890)

Operating activities – Net cash provided by operating activities ~~increased $215.6~~decreased $188.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the corresponding period in ~~2021.~~2022. This was primarily due to (i) the $206.9 million decrease in revenues, (ii) the ~~$332.8~~$42.6 million increase in operating expenses, and (iii) derivative cash settlements payments of $4.4 million during the six months ended June 30, 2023 as compared to net derivative cash settlement receipts of $70.2 million during the six months ended June 30, 2022. The decrease in revenues was due to a decrease in realized prices for oil, ~~NGL,~~NGLs and natural gas, ~~revenues during~~and to a lesser extent the ~~nine~~decrease in production volumes. During the six months ended ~~September~~June 30, 2022 ~~as compared~~derivative cash settlement receipts were due to the ~~prior year period, and (ii) $105.3~~$105.3 million of net cash proceeds received related to the monetization of certain natural gas call ~~contracts through restructuring of strike prices which occurred during the second quarter of 2022~~contracts.. The increase in revenue was primarily due to the increase in realized prices for oil, NGLs, and natural gas, and to a lesser extent, the increase in production volumes. Our combined average realized sales price per Boe increased by 76.8% for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021, which caused total revenues to increase $302.8 million.

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These ~~increases~~decreases in operating cash flow were partially offset by (i) ~~an increase in settlements of AROs which decreased operating cash flows $61.3 million as compared to $19.7 million for~~ the ~~nine months ended September 30, 2022 and 2021, respectively, and (ii)~~ changes in operating assets and liabilities (excluding ARO settlements) which ~~decreased~~increased operating cash flows by ~~$13.2~~$6.1 million as compared to ~~$43.3~~a decrease of $37.9 million for the ~~nine~~six months ended ~~September~~June 30, 2022, ~~and 2021, respectively,~~ primarily related to ~~higher~~lower oil and natural gas receivables balances due to ~~higher~~decreased realized prices ~~combined with higher payables~~ and lower accounts payable and accrued liabilities ~~balances.~~in the current period and (ii) decreased ARO settlements of $11.8 million during the six months ended June 30, 2023 as compared to $39.8 million during the six months ended June 30, 2022.

Investing activities – Net cash used in investing activities ~~increased $77.3~~decreased $44.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the corresponding period in ~~2021.~~2022. The ~~increase~~decrease was primarily due to the acquisition of properties for ~~$51.5~~$47.6 million ~~along with other increases in capital spending~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2022 compared to the same period in 2021.~~2022.

Financing activities– During the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, cash used in financing activities ~~was $35.8 million, primarily due to principal payments on the Term Loan. Net cash provided~~increased by ~~financing activities was $115.0~~$277.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2023 compared to the corresponding period in 2022. This was due to the redemption of the $552.5 million principal amount outstanding 9.75% Senior Second Lien Notes on February 8, 2023, which ~~included~~was partially offset by the net cash proceeds of $270.8 million received from the ~~Term Loan~~issuance of ~~$206.8 million, offset by $11.8 million of~~the 11.75% Senior Second Lien Notes. Additionally, the principal ~~payments~~repayments on the Term Loan ~~and repayment of $80.0 million of borrowings under the Credit Agreement.~~decreased by $5.8 million.

Derivative Financial Instruments – From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas. See Financial Statements – Note 84 – Derivative Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information about our derivative activities. The following table summarizes the historical results of our hedging activities:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021		2023		2022		2023		2022
Crude Oil ($/Bbl):	��
Average realized sales price, before the effects of derivative settlements	$	90.23	$	68.57	$	97.59	$	63.07	$	71.76	$	107.90	$	71.81	$	101.43
Effects of realized commodity derivatives		(9.97)		(12.55)		(14.90)		(8.72)		—		(18.22)		—		(17.47)
Average realized sales price, including realized commodity derivatives	$	80.26	$	56.02	$	82.69	$	54.35	$	71.76	$	89.68	$	71.81	$	83.96
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements	$	9.89	$	4.31	$	7.58	$	3.40	$	2.34	$	7.70	$	2.73	$	6.40
Effects of realized commodity derivatives⁽²⁾⁽¹⁾		(4.56)		(1.49)		1.52		(0.55)		(0.03)		10.17		(0.03)		4.63
Average realized sales price, including realized commodity derivatives	$	5.33	$	2.82	$	9.10	$	2.85	$	2.31	$	17.87	$	2.70	$	11.03

(1)

^{The nine months ended September 30, 2022 includes the effect of the $138.0 million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices.}

~~(2)~~

^{Excludes the effects of premium amortization and write-offs.amortization.}

Income Taxes – For ~~2022, we~~2023, the Company does not expect ~~10%~~ to ~~15% of our~~owe any cash taxes. The Company made income tax ~~expense to be cash taxes. We do not have any outstanding current~~payments of $2.2 million for federal and $0.3 million for state purposes, and has income taxes receivable of $1.7 million for federal and ~~made $5.2~~$0.2 million ~~in income tax payments during~~for state for the ~~nine~~six months ended ~~September~~June 30, ~~2022.~~2023. See Financial Statements – Note 109 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

Employee Retention Credit – Under the Consolidated Appropriations Act of 2021, the Company recognized a $2.2 million Employee Retention Credit during the six months ended June 30, 2023, which is included as a credit to General and administrative expenses in the Condensed Consolidated Statement of Operations.

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Capital Expenditures

The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities. The following table presents our capital expenditures for exploration, development and other leasehold costs:


	Nine Months Ended September 30,				Six Months Ended June 30,
	2022		2021		2023		2022







	(In thousands)				(In thousands)
Exploration⁽¹⁾	$	10,065	$	5,850	$	2,660	$	9,854
Development⁽¹⁾		12,743		5,660		18,360		9,186
Acquisitions of interests		51,474		754		—		47,625
Seismic and other		7,158		3,761		1,979		6,449
Investments in oil and gas property/equipment – accrual basis	$	81,440	$	16,025	$	22,999	$	73,114

(1)

^{Reported geographically in the subsequent table.}

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


	Nine Months Ended September 30,				Six Months Ended June 30,
	2022		2021		2023		2022

	(In thousands)





					(In thousands)

Conventional shelf ⁽¹⁾	$	10,473	$	4,469	$	6,898	$	7,849
Deepwater		12,335		7,041		14,122		11,191
Exploration and development capital expenditures – accrual basis	$	22,808	$	11,510	$	21,020	$	19,040

(1)

^{Includes exploration and development capital expenditures in Alabama state waters.}

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 activities section of the Condensed Consolidated Statements of Cash Flows include adjustments to report cash payments related to capital expenditures. Our capital expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 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,~~There were no acquisitions during the six months ended June 30, 2023. During the six months ended June 30, 2022, the Company acquired the 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 on February 1, 2022 and April 1, 2022. After normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date to the respective close date), cash consideration of approximately $34.0 ~~million~~ and $17.5 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 ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021~~2022 were ~~$453.6~~$480.8 million and ~~$424.5~~$466.4 million, respectively. The increase is primarily due to ~~the acquisition~~ARO accretion and upward revisions of ~~assets as described above.These increases were~~estimates, partially offset by ~~$61.3 million related to~~ liabilities settled. 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~~2022 Annual Report for additional information.

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TVPX Transaction – On May 15, 2023, we acquired a corporate aircraft from a company affiliated with and controlled by our CEO. The purchase price of the aircraft was $19.1 million, which was paid using $9.0 million of cash on hand and through the assumption of the TVPX Loan, which had a fair market value of $10.1 million on the date of assumption. A valuation prepared by an independent third-party appraiser was one of the components used in determining the purchase price value. Factors considered for purchasing the aircraft were the primary use of making business travel efficient as well as our intent to charter out the aircraft to defray a portion of the operating costs and certain tax considerations and benefits. The terms of this transaction were reviewed and approved by the Audit Committee of the Company’s Board of Directors. See Note 2 – Debt and Note 12 – Related Party Transactions for additional information.

Drilling Activity

We did not drill any wells induring the ~~nine~~six months ended ~~September~~June 30, ~~2022.~~2023. During the ~~nine~~six months ended ~~September~~June 30, 2022, we completed the East Cameron 349 B-1 well (Cota). The Cota well is in the Monza Joint Venture Drilling Program. See Financial Statements – Note 6 –Joint Venture Drilling Program under Part I, Item 1 of this Quarterly Report for additional information.

Debt

TVPX Loan – On May 15, 2023, we acquired a corporate aircraft. In connection with the acquisition, the TVPX Loan was assumed by TVPX Aircraft Solutions Inc., not in its individual capacity but as owner trustee of the trust which holds title to the aircraft, a wholly owned indirect subsidiary of the Company, as the borrower. At the time of the assumption, the TVPX Loan had an aggregate principal amount of $11.8 million outstanding. The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued interest, which began on May 17, 2023, and a balloon payment of $8.0 million at the end of the loan term. The TVPX Loan is guaranteed by the Company on an unsecured basis. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

Term Loan – As of ~~September~~June 30, ~~2022,~~2023, we had ~~$157.0~~$128.7 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, ~~which began 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~~– Debt under Part I, Item 1 of this Quarterly Report for additional information.

Credit Agreement – During the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, we had no borrowings incurred or outstanding under the Credit Agreement. On November 7, 2022, the Company entered into the Eleventh Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, , which extended the maturity date and Lender commitment to January 3, 2024, or in the event the

11.75% Senior Second Lien Notes ~~are not refinanced or replaced~~due 2026 – On January 27, 2023, we issued and sold $275 million in ~~full, on or prior to August 1, 2023, with other indebtedness that matures on or after April 3, 2024 or are not otherwise discharged, defeased or repaid in full, August 1, 2023~~

aggregate principal amount of our 11.75% Senior Second Lien Notes – ~~As of September 30, 2022, we had outstanding $552.5 million principal of Senior Second Lien Notes~~ at par with an interest rate of ~~9.75%~~11.75% per annum that ~~mature~~matures on ~~November~~February 1, ~~2023.~~2026. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. As of June 30, 2023, we had outstanding $275.0 million principal of 11.75% Senior Second Lien Notes. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

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9.75% Senior Second Lien Notes due 2023 – On February 8, 2023, we redeemed all of the 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes due 2026 and cash on hand of $296.1 million to fund the redemption. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

Debt Covenants – The ~~Term Loan,~~ Credit Agreement ~~and Senior Second Lien Notes contain~~contains financial covenants calculated as of the last day of each fiscal quarter, which ~~include~~includes thresholds on financial ratios, as defined in the respective ~~Subsidiary~~ Credit ~~Agreement, Credit Agreement and the Indenture.~~Agreement. We were in compliance with all applicable covenants of ~~the Term Loan,~~ Credit Agreement ~~and the Indenture~~ as of and for the period ended ~~September~~June 30, ~~2022.~~2023. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

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The Subsidiary Borrowers

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 “Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for the Term Loan 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.Loan. See Financial Statements – Note 5 – Subsidiary Borrowers under Part ~~II,~~I, Item 1 in this Quarterly Report for additional information.

~~At that time, we~~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 11.75% 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 Indenture. 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 – Debt under Part I, Item 1 in this Quarterly Report for additional information.

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Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Condensed Consolidated Balance Sheet as of ~~September~~June 30, ~~2022~~2023 (in thousands):


	Consolidated Balance Sheet		Eliminations of Unrestricted Subsidiaries		Consolidated Balance Sheet of restricted subsidiaries		Consolidated Balance Sheet		Eliminations of Unrestricted Subsidiaries		Consolidated Balance Sheet of restricted subsidiaries
Assets
Current assets:
Cash and cash equivalents	$	447,130	$	(54,219)	$	392,911	$	171,627	$	(5,899)	$	165,728
Restricted cash		4,417		—		4,417		4,417		—		4,417
Receivables:
Oil and natural gas sales		89,195		(80,431)		8,764		41,342		(18,411)		22,931
Joint interest, net		16,815		5,749		22,564		13,875		27,400		41,275
Income taxes								1,941		—		1,941
Total receivables		106,010		(74,682)		31,328		57,158		8,989		66,147
Prepaid expenses and other assets		53,014		(614)		52,400		21,365		(125)		21,240
Total current assets		610,571		(129,515)		481,056		254,567		2,965		257,532

Oil and natural gas properties and other, net		729,958		(280,444)		449,514		737,740		(289,959)		447,781

Restricted deposits for asset retirement obligations		21,760		—		21,760		22,092		—		22,092
Deferred income taxes		62,334		—		62,334		45,700		—		45,700
Other assets		65,681		19,438		85,119		42,118		(11,486)		30,632
Total assets	$	1,490,304	$	(390,521)	$	1,099,783	$	1,102,217	$	(298,480)	$	803,737
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	75,068	$	(49,859)	$	25,209	$	70,403	$	(8,996)	$	61,407
Undistributed oil and natural gas proceeds		59,518		(22,077)		37,441		31,178		(3,625)		27,553
Asset retirement obligations		54,886		—		54,886		37,763		—		37,763
Accrued liabilities		154,236		(89,431)		64,805		39,323		(19,036)		20,287
Current portion of long-term debt		35,450		(35,450)		—		30,550		(30,074)		476
Income tax payable		1,613		—		1,613		10		—		10
Total current liabilities		380,771		(196,817)		183,954		209,227		(61,731)		147,496
Long-term debt
Principal		674,031		(121,571)		552,460		382,697		(97,222)		285,475
Unamortized debt issuance costs		(8,058)		5,067		(2,991)		(9,676)		2,304		(7,372)
Long-term debt, net		665,973		(116,504)		549,469		373,021		(94,918)		278,103

Asset retirement obligations, less current portion		398,724		(59,107)		339,617		443,069		(66,136)		376,933
Other liabilities		99,740		(79,602)		20,138		52,037		(22,020)		30,017
Deferred income taxes		113		—		113		72		—		72
Common stock		1		—		1		1		—		1
Shareholders' equity (deficit):
Additional paid-in capital		557,386		—		557,386		579,849		—		579,849
Retained deficit		(588,237)		61,509		(526,728)		(530,892)		(53,675)		(584,567)
Treasury stock, at cost		(24,167)		—		(24,167)		(24,167)		—		(24,167)
Total shareholders’ equity (deficit)		(55,017)		61,509		6,492		24,791		(53,675)		(28,884)
Total liabilities and shareholders’ equity (deficit)	$	1,490,304	$	(390,521)	$	1,099,783	$	1,102,217	$	(298,480)	$	803,737

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Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Condensed Consolidated Statement of Operations for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 (in thousands):


		Consolidated		Eliminations of Unrestricted Subsidiaries		Consolidated restricted subsidiaries		Consolidated Statement of Operations		Eliminations of Unrestricted Subsidiaries		Consolidated Statement of Operations of restricted subsidiaries
Revenues:
Oil	$	412,526	$	(710)	$	411,816	$	186,982	$	(288)	$	186,694
NGLs		47,430		(28,541)		18,889		18,180		(11,660)		6,520
Natural gas		257,452		(180,109)		77,343		48,242		(32,354)		15,888
Other		13,889		(9,265)		4,624		4,502		(2,258)		2,244
Total revenues		731,297		(218,625)		512,672		257,906		(46,560)		211,346
Operating expenses:
Lease operating expenses		155,397		(37,350)		118,047		131,207		(48,157)		83,050
Gathering, transportation and production taxes		26,647		(13,910)		12,737		12,938		(4,054)		8,884
Depreciation, depletion, amortization and accretion		99,384		(619)		98,765		66,028		2,375		68,403
General and administrative expenses		51,790		(1,082)		50,708		37,312		(654)		36,658
Total operating expenses		333,218		(52,961)		280,257		247,485		(50,490)		196,995
Operating income		398,079		(165,664)		232,415		10,421		3,930		14,351

Interest expense, net		54,915		(11,841)		43,074		25,036		(5,411)		19,625
Derivative loss (gain)		109,892		(187,896)		(78,004)
Derivative (gain) loss, net								(40,069)		52,389		12,320
Other income, net		(1,229)		(64)		(1,293)		(78)		—		(78)
Income before income taxes		234,501		34,009		268,638
Income tax benefit		46,801		—		46,801
Net income	$	187,700	$	34,009	$	221,837
Income (loss) before income taxes								25,532		(43,048)		(17,516)
Income tax expense								11,636		—		11,636
Net (loss) income							$	13,896	$	(43,048)	$	(29,152)

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Subsidiary Borrowers for the ~~nine months ended September 30, 2022:~~periods indicated:


		~~Nine Months Ended September 30,~~
~~Production Volumes:~~	~~2022~~
~~Oil (MBbls)~~		13
~~NGLs (MBbls)~~		~~729~~
~~Natural gas (MMcf)~~		~~22,919~~
~~Total oil equivalent (MBoe)~~		~~4,562~~


	Six Months Ended June 30,
Production Volumes:	2023	2022
Oil (MBbls)	7	7
NGLs (MBbls)	465	468
Natural gas (MMcf)	11,570	15,166
Total oil equivalent (MBoe)	2,400	3,003

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Contractual Obligations

As of ~~September~~June 30, ~~2022,~~2023, there were no long-term drilling rig commitments. Except as disclosed herein, contractual obligations as of ~~September~~June 30, ~~2022~~2023 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~~2022 Annual Report.

Critical Accounting Policies and Estimates

We consider accounting policies related to revenue recognition, full cost accounting, impairment of oil and natural gas properties, ~~proved~~oil and natural gas reserve ~~estimates, fair value measure of financial instruments,~~quantities, 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 Condition and Results of Operations under Part II, Item 7 of our ~~2021~~2022 Annual Report.

Recent Accounting Pronouncements

There ~~was~~were 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 ~~September~~six months ended June 30, ~~2022~~2023 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our ~~2021~~2022 Annual Report. In addition, the information contained herein should be read in conjunction with the related disclosures in our ~~2021~~2022 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 CEO and ~~CFO,~~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), our CEO and CFO performed an evaluation 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 Quarterly Report. Based on that evaluation, our CEO and CFO have each concluded that as of ~~September~~June 30, ~~2022,~~2023, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended ~~September~~June 30, ~~2022,~~2023, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Financial Statements – Note 1211 – Contingencies under Part I Item 1 of this Quarterly Report for information on various legal proceedings to which we are a party or our properties are subject.

Item 1A. Risk Factors

~~As of~~In addition to the ~~date of~~information set forth in this Quarterly Report, ~~except as described below,~~investors should carefully consider the risk factors and other cautionary statements included under Part I, Item 1A, Risk Factors, in our 2022 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 toin our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our ~~2021~~2022 Annual Report and in Part II, Item 1A, Risk Factors, in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2022 and June 30, 2022. The information presented below updates, and should be read in conjunction with, the risk factors referenced above.Report.

We outsource substantially all of our information technology infrastructure and the management and servicing of such infrastructure, which makes us more dependent upon third parties and exposed to related risks. We are in the process of transitioning substantially all of such infrastructure, which subjects us to increased costs and risks.

We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of such infrastructure to a limited number of third-party service providers. As a result, we rely on third parties that we do not control to ensure that our technology needs are sufficiently met, and cyber risks are effectively managed. This reliance has subjected us to certain cybersecurity risks arising from the loss of control over certain processes, including the potential misappropriation, destruction, corruption or unavailability of certain data and systems, such as confidential or proprietary information. As such, a failure of any of our information technology service providers to perform its management and operational duties securely and effectively may have a material adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run our business. We also have not had written agreements with our primary service provider, which exposed us to additional risks with respect to the systems and data outsourced to such provider.

In August 2022, our primary information technology service provider, AAIT, notified us of its intention to cease providing services to us by September 2, 2022. In response, we began the transition of these services and infrastructure to inside the Company or to other providers. In addition, we filed an action in state district court against AAIT and an affiliated service provider for a temporary restraining order, temporary injunction, and permanent injunction seeking, among other things, to restrain AAIT from ceasing to provide services to us until the transition process is complete. On September 14, 2022, a notice was filed to remove that state court action in District Court of Harris County, Texas to United States District Court for the Southern District of Texas. In connection with the foregoing, on September 16, 2022, we and AAIT mutually agreed to the terms of an agreed order issued by the court providing for a temporary injunction for a period of a minimum of 60 days from the date of the order and up to a maximum of 120 days at our option, during which AAIT would continue to provide information technology services to us and assist with the transition process. The agreed order also provided for the appointment by mutual agreement of the parties of Hon. Gregg J. Costa (Ret.) as an independent adjudicator to assist in adjudicating ongoing disputes between the parties. This transition process has, and may continue to, disrupt certain of our business operations. Any difficulties in completing such transition could impair our ability to monitor our production and accurately prepare our results of operations in a timely fashion. Although we have moved and are continuing to move certain services within the Company and are transitioning to new service providers and implementing agreements with such providers, such transition exposes us to additional risks, including increased costs, focus of management’s attention, disruptions to certain of our business operations and loss, damage to or unavailability of data or systems, which could have an adverse effect on our business and results of operations.

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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.

Item 5. Other Information

~~None.~~

~~Table~~During the three months ended June 30, 2023, none of ~~Contents~~our directors or “officers” (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408(a) of Regulation S-K).

Item 6. Exhibits


Exhibit Number		Description

~~3.1~~3.1*		Second Amended and Restated Articles of Incorporation of W&T Offshore, Inc.

3.2		Fourth 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 ~~February 24, 2006 (File No. 001-32414))~~

~~3.2~~		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))

~~3.3~~		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc., dated as of September 6, 2016. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed September 6, 2016 (File No. 001-32414))

~~3.4~~		~~Third Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q, filed August 8, 2022~~April 26, 2023 (File No. 001-32414))

~~10.1†~~4.1		~~Eleventh~~First Supplemental Indenture, dated as of May 25, 2023, among Falcon Aero Holdings LLC, Falcon Aero Holdco LLC, W&T Offshore, Inc., the other Guarantors party thereto and Wilmington Trust, National Association, as trustee.

10.1		W&T Offshore, Inc. 2023 Incentive Compensation Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed June 20, 2023 (File No. 001-32414))

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10.2*		W&T Offshore, Inc. Change in Control Severance Plan

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

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

10.5*		Form of 2023 Executive Annual Incentive Award Agreement

10.6		Amended and Restated Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 26, 2023 (File No. 001-32414))

10.7†		Twelfth Amendment to the Sixth Amended and Restated Credit Agreement, dated ~~effective~~ as of ~~November 7, 2022~~May 15, 2023, by and among W&T Offshore, Inc., the guarantor subsidiaries party thereto, Alter Domus (US) LLC, and the various agents and lenders and other parties thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8 K, filed May 19, 2023 (File No. 001 32414))

31.1*		Section 302 Certification of Chief Executive Officer

31.2*		Section 302 Certification of Chief Financial Officer

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

101.INS*		Inline XBRL Instance Document

101.SCH*		Inline XBRL Schema Document

101.CAL*		Inline XBRL Calculation Linkbase Document

101.DEF*		Inline XBRL Definition Linkbase Document

101.LAB*		Inline XBRL Label Linkbase Document

101.PRE*		Inline XBRL Presentation Linkbase Document

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

*	Filed herewith.

**	Furnished herewith.

†	Certain schedules and similar attachments to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to furnish a supplemental copy of each such omitted schedule or similar attachment to the SEC upon request.

4742

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on ~~November 9, 2022.~~August 2, 2023.


	W&T OFFSHORE, INC.

	By:	/s/ ~~Janet Yang~~Sameer Parasnis
		~~Janet Yang~~Sameer Parasnis
		Executive Vice President and Chief Financial Officer (Principal Financial Officer), duly authorized to sign on behalf of the registrant

4843


	September 30,		December 31,
	2022		2021
Assets
Current assets:
Cash and cash equivalents	$	447,130	$	245,799
Restricted cash		4,417		4,417
Receivables:
Oil and natural gas sales		89,195		54,919
Joint interest, net		16,815		9,745
Total receivables		106,010		64,664
Prepaid expenses and other assets (Note 1)		53,014		43,379
Total current assets		610,571		358,259

Oil and natural gas properties and other, net (Note 1)		729,958		665,252

Restricted deposits for asset retirement obligations		21,760		16,019
Deferred income taxes		62,334		102,505
Other assets (Note 1)		65,681		51,172
Total assets	$	1,490,304	$	1,193,207
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	72,051	$	67,409
Undistributed oil and natural gas proceeds		59,518		36,243
Advances from joint interest partners		3,017		15,072
Asset retirement obligations		54,886		56,419
Accrued liabilities (Note 1)		154,236		106,140
Current portion of long-term debt		35,450		42,960
Income tax payable		1,613		133
Total current liabilities		380,771		324,376

Long-term debt, net (Note 2)		665,973		687,938
Asset retirement obligations, less current portion		398,724		368,076
Other liabilities (Note 1)		94,841		55,389
Deferred income taxes		113		113
Commitments and contingencies (Note 12)		4,899		4,495
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at September 30, 2022 and December 31, 2021		—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 146,031 issued and 143,162 outstanding at September 30, 2022; 145,732 issued and 142,863 outstanding at December 31, 2021		1		1
Additional paid-in capital		557,386		552,923
Retained deficit		(588,237)		(775,937)
Treasury stock, at cost; 2,869 shares at September 30, 2022 and December 31, 2021		(24,167)		(24,167)
Total shareholders’ deficit		(55,017)		(247,180)
Total liabilities and shareholders’ deficit	$	1,490,304	$	1,193,207


	February 1, 2022
Oil and natural gas properties and other, net	$	54,299
Restricted deposits for asset retirement obligations		6,196
Asset retirement obligations		(26,493)
Allocated purchase price	$	34,002


	April 1,
	2022
Oil and natural gas properties and other, net	$	22,632
Restricted deposits for asset retirement obligations		1,549
Asset retirement obligations		(6,709)
Allocated purchase price	$	17,472


	May 26, 2022
Expected term for performance period (in years)		2.6
Expected volatility		84.4	%
Risk-free interest rate		2.5	%
Fair value (in thousands)	$	14,163