W&T Offshore 10Q 2022 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2022

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

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


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

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

(713) 626-8525

(Registrant’s telephone number, including area code)

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 31, 2022 there were 143,161,608 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 30, 2022 and December 31, 2021	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2022 and 2021	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended September 30, 2022 and 2021	3
	Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2022 and 2021	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	44

PART II – OTHER INFORMATION		45
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	47

SIGNATURE		48

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

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,
	2022		2021		2022		2021
Revenues:
Oil	$	130,560	$	74,265	$	412,526	$	240,418
NGLs		16,875		12,205		47,430		30,397
Natural gas		113,673		45,137		257,452		113,816
Other		5,377		2,339		13,889		7,790
Total revenues		266,485		133,946		731,297		392,421
Operating expenses:
Lease operating expenses		59,010		39,490		155,397		129,399
Gathering, transportation and production taxes		12,199		6,593		26,647		19,687
Depreciation, depletion, and amortization		27,493		20,818		79,848		66,511
Asset retirement obligations accretion		6,620		5,473		19,536		17,368
General and administrative expenses		23,047		13,391		51,790		38,090
Total operating expenses		128,369		85,765		333,218		271,055
Operating income		138,116		48,181		398,079		121,366

Interest expense, net		16,849		18,910		54,915		50,474
Derivative loss		38,749		73,137		109,892		179,156
Other (income) expense, net		(600)		—		(1,229)		964
Income (loss) before income taxes		83,118		(43,866)		234,501		(109,228)
Income tax expense (benefit)		16,397		(5,902)		46,801		(18,846)
Net income (loss)	$	66,721	$	(37,964)	$	187,700	$	(90,382)

Net income (loss) per common share:
Basic	$	0.46	$	(0.27)	$	1.30	$	(0.64)
Diluted	$	0.46	$	(0.27)	$	1.30	$	(0.64)

Weighted average common shares outstanding
Basic		143,116		142,297		143,026		142,231
Diluted		145,882		142,297		144,696		142,231

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at 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
	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	—		—		5,179		—	—		—		5,179
Stock Issued	299		—		—		—	—		—		—
RSUs surrendered for payroll taxes	—		—		(716)		—	—		—		(716)
Net income	—		—		—		187,700	—		—		187,700
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 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)

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

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 Annual Report on Form 10-K (the “2021 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.

Table of Contents

Summary of Significant Accounting Policies

Revenue and Accounts Receivable – Revenue from the sale of crude oil, natural gas liquids (“NGLs”) and natural gas is recognized when performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of crude oil, NGLs and natural gas to the customer. Revenue is concentrated 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.

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 million and $10.0 million as of September 30, 2022 and December 31, 2021, respectively.

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

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
Derivatives⁽¹⁾(Note 8)	$	28,747	$	21,086
Unamortized insurance/bond premiums		7,475		5,400
Prepaid deposits related to royalties		12,978		8,441
Prepayment to vendors		1,213		4,522
Prepayments to joint interest partners		1,953		2,808
Debt issue costs		604		1,065
Other		44		57
Prepaid expenses and other assets	$	53,014	$	43,379

⁽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
Oil and natural gas properties and equipment	$	8,780,961	$	8,636,408
Furniture, fixtures and other		20,827		20,844
Total property and equipment		8,801,788		8,657,252
Less: Accumulated depreciation, depletion, amortization and impairment		(8,071,830)		(7,992,000)
Oil and natural gas properties and other, net	$	729,958	$	665,252

Table of Contents

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

⁽¹⁾

^{Includes open contracts.}

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


	September 30, 2022		December 31, 2021
Accrued interest	$	25,423	$	10,154
Accrued salaries/payroll taxes/benefits		9,711		9,617
Litigation accruals		524		646
Lease liability		1,620		1,115
Derivatives⁽¹⁾(Note 8)		116,008		81,456
Other		950		3,152
Total accrued liabilities	$	154,236	$	106,140

⁽¹⁾

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

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


	September 30, 2022		December 31, 2021
Dispute related to royalty deductions	$	7,564	$	5,177
Derivatives (Note 8)		75,079		37,989
Lease liability		10,812		11,227
Other		1,386		996
Total other liabilities (long-term)	$	94,841	$	55,389

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" 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 months ended September 30, 2022, the Company did not sell any shares in connection with the ATM Program.

Table of Contents

NOTE 2 — DEBT

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


	September 30, 2022		December 31, 2021
Term Loan:
Principal	$	157,021	$	190,859
Unamortized debt issuance costs		(5,067)		(7,545)
Total Term Loan		151,954		183,314

Credit Agreement borrowings:		—		—

Senior Second Lien Notes:		—
Principal		552,460		552,460
Unamortized debt issuance costs		(2,991)		(4,876)
Total Senior Second Lien Notes		549,469		547,584

Less current portion		(35,450)		(42,960)
Total long-term debt, net	$	665,973	$	687,938

Current Portion of Long-Term Debt

As of September 30, 2022, the current portion of long-term debt of $35.5 million represented principal payments due within one year on the Term Loan (defined below).

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 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.

The Company believes that cash on hand and cash flows from operations will enable the Company to satisfy its debt obligations as well as meet its other funding requirements for at least one year from 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.

If necessary, there are further actions the Company could undertake to increase cash flows which include limiting capital expenditures and reducing operating expenditures. Additionally, the Company may seek to raise cash through the sale of up to $100 million of equity available under the ATM program.

Table of Contents

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 in an aggregate principal amount equal to $215.0 million (the “Term Loan”). The Term Loan requires quarterly amortization payments, which commenced on September 30, 2021. The Term Loan bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and any subsidiaries other than the Subsidiary Borrowers and the subsidiary that owns the equity in the Subsidiary Borrowers, and is secured by the first lien security interests in the equity of the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers (the Mobile Bay Properties, defined below).

In exchange for the net cash proceeds received by the Subsidiary Borrowers from the Term Loan, the Company assigned to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, in the Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, in the Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore crude oil treating and sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”). A portion of the proceeds to the Company was used to repay the $48.0 million outstanding balance on its reserve-based lending facility under the 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 Note 5 – Subsidiary Borrowers.

As of September 30, 2022 and December 31, 2021, the Company had $157.0 million and $190.9 million in principal amount of Term Loan outstanding, respectively.

Credit Agreement

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

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

Table of Contents

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 30, 2022, are as follows:

The revised borrowing base is $50.0 million;

The commitment will expire and final maturity of any and all outstanding loans is January 3, 2024, or in the event that the 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.

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

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.

Table of Contents

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

9.75% Senior Second Lien Notes Due 2023

On October 18, 2018, W&T issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and mature on November 1, 2023, and are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”). The estimated annual effective interest rate on the Senior Second Lien Notes is 10.3%, which includes amortization of debt issuance costs. Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year. As of September 30, 2022 and December 31, 2021, $552.5 million in principal amount of Senior Second Lien Notes remained issued and outstanding.

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

Covenants

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

NOTE 3 – FAIR VALUE MEASUREMENTS

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 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 financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 8 – Derivative Financial Instruments, for additional information on derivative financial instruments.

Table of Contents

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


	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

Debt Instruments

The following table presents the net value and fair value of the Company’s debt (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

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

Table of Contents

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 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired. The amounts recorded on the Condensed Consolidated Balance Sheet for the purchase price allocation and liabilities assumed related to the acquisitions described above on February 1, 2022, and April 1, 2022, are presented in the following tables, respectively (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

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 8 – Derivative Financial Instruments, of this Quarterly Report on Form 10-Q (this “Quarterly Report”).

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

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
Assets:
Cash and cash equivalents	$	54,219	$	38,937
Receivables:
Oil and natural gas sales		80,431		34,420
Joint interest, net		(5,749)		(10,856)
Prepaid expenses and other assets		614		356
Oil and natural gas properties and other, net		280,444		272,747
Other assets		(19,438)		(19,903)
Liabilities:
Accounts payable		49,859		29,678
Undistributed oil and natural gas proceeds		22,077		3,144
Accrued liabilities		89,431		29,937
Current portion of long-term debt		35,450		42,960
Long-term debt, net		116,504		140,353
Asset retirement obligations		59,107		54,515
Other liabilities		79,602		42,615

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
	September 30, 2022		September 30, 2021
Total revenues	$	218,625	$	63,053
Total operating expenses		52,961		26,644
Interest expense, net		11,841		5,930
Derivative loss		187,896		124,364
Other income		64		—

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 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 indirect interest through the 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.

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

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

Through September 30, 2022, 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 30, 2022.

Through September 30, 2022, 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 million. Through September 30, 2022, 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 million.

Consolidation and Carrying Amounts

W&T’s interest in Monza is considered to be a variable interest that is proportionally consolidated. Through September 30, 2022, 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
Working capital	$	3,583	$	4,648
Oil and natural gas properties and other, net		39,131		45,510
Asset retirement obligations		432		375
Other assets		15,409		2,511
Other liabilities		2,627		—

Additionally, during the year ended December 31, 2021, W&T called on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of September 30, 2022 and December 31, 2021 were $2.9 million and $14.8 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,
	2022		2021
Total revenues	$	23,681	$	8,730
Total operating expenses		10,805		7,564
Derivative loss		—		1,966

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

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


	Nine Months Ended September 30,
	2022
Asset retirement obligations, beginning of period	$	424,495
Liabilities settled		(61,285)
Accretion expense		19,536
Liabilities acquired		33,202
Liabilities incurred		138
Revisions of estimated liabilities		37,524
Asset retirement obligations, end of period		453,610
Less: Current portion		(54,886)
Long-term	$	398,724

NOTE 8 — 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 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 collateral to the derivative counterparties and does not require collateral from the derivative counterparties.

W&T has elected not to designate commodity derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as Derivative (gain) loss on the Condensed Consolidated Statements of Operations in each period presented. The cash flows of all commodity derivative contracts are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.

The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices and the natural gas contracts are based off the Henry Hub prices, both of which are quoted off the New York Mercantile Exchange (“NYMEX”).

Table of Contents

The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts as of September 30, 2022:



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

Crude Oil - WTI (NYMEX)		(Bbls)⁽¹⁾	(Bbls)⁽¹⁾		($/Bbls)⁽¹⁾		($/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

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 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 10 — INCOME TAXES

Tax Benefit and Tax Rate

For the three months ended September 30, 2022, the Company recognized income tax expense of $16.4 million for an effective tax rate of 19.7%. For the three months ended September 30, 2021 the Company recognized income tax benefit of $5.9 million for an effective tax rate of 13.5%.

For the nine months ended September 30, 2022, the Company recognized income tax expense of $46.8 million for an effective tax rate of 20.0%. 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 months ended September 30, 2022 and 2021, 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.

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 30, 2022, and December 31, 2021, the valuation allowance was $15.2 million and $24.4 million, respectively, and relates primarily to state net operating losses and the disallowed interest expense limitation carryover.

Income Taxes Receivable, Refunds and Payments

As of September 30, 2022 and December 31, 2021, the Company did not have any outstanding current income taxes receivable. During the nine months ended September 30, 2022 the Company did not receive any income tax refunds and made federal income tax payments of $5.2 million. During the nine months ended September 30, 2021, the Company did not receive any income tax refunds or make any income tax payments of significance.

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

Table of Contents

NOTE 11 — EARNINGS PER SHARE

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

								��
	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income (loss)	$	66,721	$	(37,964)	$	187,700	$	(90,382)
Less portion allocated to nonvested shares		1,265		—		2,166		—
Net income (loss) allocated to common shares	$	65,456	$	(37,964)	$	185,534	$	(90,382)

Weighted average common shares outstanding - basic		143,116		142,297		143,026		142,231
Dilutive effect of securities		2,766		—		1,670		—
Weighted average common shares outstanding - diluted		145,882		142,297		144,696		142,231
Earnings per common share:
Basic	$	0.46	$	(0.27)	$	1.30	$	(0.64)
Diluted		0.46		(0.27)		1.30		(0.64)

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

NOTE 12 — 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 million as of September 30, 2022.

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 pay a total of $720,000 in three annual installments. The first and second installments were paid in March 2021 and March 2022, respectively. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022, which 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 – The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. For example, recent historical declines in commodity prices created an environment where there is an increased risk that owners and/or operators of interests purchased from the Company may no longer be able to satisfy plugging or abandonment obligations that attach to those interests. In that event, due to operation of law, W&T may be required to assume plugging or abandonment obligations for those interests. During 2021, as a result of the declaration of bankruptcy by a third party that is the indirect successor in title to certain offshore interests that were previously divested by the Company, W&T recorded a loss contingency accrual related to the anticipated cost to decommission certain wells, pipelines, and production facilities for which the Company may receive decommissioning orders from BSEE. W&T no longer owns these assets nor are they related to current operations. 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.

Table of Contents

NOTE 13 — SUBSEQUENT EVENTS

On November 1, 2022, the $552.5 million principal of the Senior Second Lien Notes were reclassified from long-term debt to current debt as a result of their November 1, 2023 maturity date. See Note 2 – Debt for additional information.

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 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. The terms of the Eleventh Amendment were approved by the Audit Committee of the Board of Directors of the Company.

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 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 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. 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 forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These forward-looking statements are subject to risks, uncertainties and assumptions, most of which are difficult to predict and many of which are beyond our control. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, estimates, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Part I, Item 1A, Risk Factors, and market risks are discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our 2021 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.

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 30, 2022, we hold working interests in 47 offshore fields in federal and state waters (45 fields producing and 2 fields capable of producing, which include 39 fields in federal waters and 8 in state waters). We currently have under lease approximately 622,000 gross acres (449,500 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 gross acres on the conventional shelf and approximately 165,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC and, W & 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.

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 quarter at approximately $80.00 per barrel and $6.50 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, the EIA expects the WTI spot price average to decrease to $85.98 per barrel during the fourth quarter of 2022 as compared to the third quarter 2022 average of $93.07 per barrel. The EIA also expects the Henry Hub spot price to average $7.70 per Mcf during the fourth quarter of 2022 as compared to $8.30 during the third quarter of 2022.

Table of Contents

As compared to the prior year, spot prices remain high, likely as a result of low inventories and continued uncertainty surrounding the Russia-Ukraine conflict and the related potential effects on future oil and gas supply. Per the EIA, average crude oil prices using the WTI daily spot price increased to $98.96 per barrel during the nine months ended September 30, 2022 compared 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).

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.

The annual rate of inflation in the United States was measured at 8.2% in September 2022 by the Consumer Price Index, the highest in more than four decades. In addition, the Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate and signaled that the Federal Reserve would continue to take 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 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”) – On August 16, 2022, President Biden signed the IRA into law. Several provisions in the IRA are expected 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 gas production, and onshore processing, transmission and compression, gathering, and boosting station source categories. For 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 charge is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and the first fee payment will be in 2025 based on 2024 data. The methane emissions charge may increase our operating costs and adversely affect our business.

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. As many BOEM regulations are being reviewed by the Department of the Interior, 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 as of the filing date of this Quarterly Report and we currently do not have surety bond collateral outstanding. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Results of Operations

Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021

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 loss in our Condensed Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:


	Three Months Ended September 30,
	2022		2021
Oil	49.0	%	55.4	%
NGLs	6.3	%	9.1	%
Natural gas	42.7	%	33.7	%
Other	2.0	%	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 three months ended September 30, 2022 and 2021:


	Three Months Ended September 30,
	2022		2021			Change

	(In thousands, except realized sales price data)
Revenues:
Oil	$	130,560	$	74,265	$	56,295
NGLs		16,875		12,205		4,670
Natural gas		113,673		45,137		68,536
Other		5,377		2,339		3,038
Total revenues		266,485		133,946		132,539

Production Volumes:
Oil (MBbls)		1,447		1,083		364
NGLs (MBbls)		454		376		78
Natural gas (MMcf)		11,499		10,481		1,018
Total oil equivalent (MBoe)		3,818		3,206		612

Average daily equivalent sales (Boe/day)		41,500		34,848		6,652

Average realized sales prices:
Oil ($/Bbl)	$	90.23	$	68.57		21.66
NGLs ($/Bbl)		37.17		32.46		4.71
Natural gas ($/Mcf)		9.89		4.31		5.58
Oil equivalent ($/Boe)		68.39		41.05		27.34
Oil equivalent ($/Boe), including realized commodity derivatives⁽¹⁾		50.86		31.95		18.91

(1)

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


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

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 30, 2022 and 2021 (in thousands):


	Price		Volume		Total
Oil	$	31,321	$	24,975	$	56,296
NGLs		2,124		2,546		4,670
Natural gas		64,150		4,385		68,535
	$	97,595	$	31,906	$	129,501

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 of WTI versus HLS and LLS for the three months ended September 30, 2022 increased on average by approximately $0.27 and $1.00 per barrel, respectively. The monthly average differential for WTI versus Poseidon declined on average by approximately $2.74 per barrel compared to the same period in 2021.

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 30, 2022 compared to the three months ended September 30, 2021, average prices for domestic ethane increased by 58.0% and average domestic propane prices increased by 61.8% as measured using a price index for Mount Belvieu. The average prices for normal butane increased by 7.8% while other domestic NGL components decreased between 7.2% and 11.5% for the three months ended September 30, 2022 compared to the same period in 2021. 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 by 612 MBoe to 3,818 MBoe in the three months ended September 30, 2022 compared to the same period in 2021, primarily due to the acquisition 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.

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 September 30,
	2022		2021			Change

Operating expenses:
Lease operating expenses	$	59,010	$	39,490	$	19,520
Gathering, transportation and production taxes		12,199		6,593		5,606
Depreciation, depletion, amortization and accretion		34,113		26,291		7,822
General and administrative expenses		23,047		13,391		9,656
Total operating expenses	$	128,369	$	85,765	$	42,604

Average per Boe ($/Boe):
Lease operating expenses	$	15.46	$	12.32	$	3.14
Gathering, transportation and production taxes		3.20		2.06		1.14
DD&A		8.93		8.20		0.73
G&A expenses		6.04		4.18		1.86
Operating expenses	$	33.63	$	26.76	$	6.87

Table of Contents

Lease operating expenses – Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased $19.5 million to $59.0 million for the three months ended September 30, 2022 compared to $39.5 million for the three months ended September 30, 2021. On a component basis, base lease operating expenses increased $15.0 million, workover expenses increased $1.0 million, facilities maintenance expense increased $4.3 million, and hurricane repairs decreased $0.8 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 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 million in the three months ended September 30, 2022 compared to the three months ended September 30, 2021 primarily due to a new transportation contract related to the properties acquired in the first half of 2022. Additionally, the increase 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.

Depreciation, depletion, amortization and accretion (“DD&A”) – DD&A, which includes accretion for ARO, increased to $8.93 per Boe for the three months ended September 30, 2022 from $8.20 per Boe for the three months ended September 30, 2021. On a nominal basis, DD&A increased $7.8 million for the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 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 and gas prices compared to the smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”) – G&A increased $9.7 million, to $23.0 million for the three months ended September 30, 2022 as compared to $13.4 million for the three months ended September 30, 2021. The increase is primarily due to non-recurring professional services incurred 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, we incurred increased incentive compensation costs related to the higher grant date fair value of RSU and PSU awards granted during 2022 as compared to the value of awards granted in 2021.

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 September 30,
	2022		2021			Change

Other income and expenses:
Derivative loss	$	38,749	$	73,137	$	(34,388)
Interest expense, net		16,849		18,910		(2,061)
Other (income) expense, net		(600)		—		(600)
Income tax expense (benefit)		16,397		(5,902)		22,299

Table of Contents

Derivative loss – During the three months ended September 30, 2022, the $38.7 million derivative loss 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 million of unrealized gain, net from the increase in the fair value of open contracts. During the three months ended September 30, 2021, the $73.1 million derivative loss recorded for crude oil and natural gas derivative contracts consisted of $30.0 million in realized losses and $43.1 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.

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 Financial Instruments under Part I, Item 1 of this Quarterly Report for additional information.

Interest expense, net – Interest expense, net, was $16.8 million and $18.9 million for the three months ended September 30, 2022 and 2021, respectively. The decrease of $2.1 million in 2022 is primarily due to lower interest expense on the lower outstanding principal balance of the Term Loan and increased interest income.

Income tax expense (benefit) – Income tax expense for the three months ended September 30, 2022 was $16.4 million compared to an income tax benefit of $5.9 million during the three months ended September 30, 2021. For the three months ended September 30, 2022 and 2021, our income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to our valuation allowance. Our effective tax rate was 19.7% and 13.5% for the three months ended September 30, 2022 and 2021, respectively.

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

Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021

Revenues


	Nine Months Ended September 30,
	2022		2021
Oil	56.4	%	61.3	%
NGLs	6.5	%	7.7	%
Natural gas	35.2	%	29.0	%
Other	1.9	%	2.0	%

Table of Contents


	Nine Months Ended September 30,
	2022		2021			Change

Revenues:
Oil	$	412,526	$	240,418	$	172,108
NGLs		47,430		30,397		17,033
Natural gas		257,452		113,816		143,636
Other		13,889		7,790		6,099
Total revenues	$	731,297	$	392,421	$	338,876

Production Volumes:
Oil (MBbls)		4,227		3,812		415
NGLs (MBbls)		1,187		1,105		82
Natural gas (MMcf)		33,965		33,469		496
Total oil equivalent (MBoe)		11,075		10,495		580

Average daily equivalent sales (Boe/day)		40,568		38,444		2,124

Average realized sales prices:
Oil ($/Bbl)	$	97.59	$	63.07	$	34.52
NGLs ($/Bbl)		39.96		27.51		12.45
Natural gas ($/Mcf)		7.58		3.40		4.18
Oil equivalent ($/Boe)		64.78		36.65		28.13
Oil equivalent ($/Boe), including realized commodity derivatives⁽¹⁾		63.76		31.71		32.05

(1)

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

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 months ended September 30, 2022 and 2021 (in thousands):


	Price		Volume		Total
Oil	$	145,927	$	26,181	$	172,108
NGLs		14,897		2,136		17,033
Natural gas		141,950		1,686		143,636
	$	302,774	$	30,003	$	332,777

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 of WTI versus Poseidon and HLS for the nine months ended September 30, 2022 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 per barrel compared to 2021.

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 months ended September 30, 2022 compared to the nine months ended September 30, 2021, average prices for domestic ethane increased by 65.5% and average domestic propane prices increased by 15.5% as measured using a price index for Mount Belvieu. The average prices for other domestic NGLs components increased between 21.1% and 34.0% for the nine months ended September 30, 2022 compared to the same period in 2021. 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 by 580 MBoe to 11,075 MBoe during the nine months ended September 30, 2022 as compared to production volumes during the nine months ended September 30, 2021. primarily due to the acquisition 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.

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,
	2022		2021			Change

	(In thousands, except per Boe data)
Operating expenses:
Lease operating expenses	$	155,397	$	129,399	$	25,998
Gathering, transportation and production taxes		26,647		19,687		6,960
Depreciation, depletion, amortization and accretion		99,384		83,879		15,505
General and administrative expenses		51,790		38,090		13,700
Total operating expenses	$	333,218	$	271,055	$	62,163

Average per Boe ($/Boe):
Lease operating expenses	$	14.03	$	12.33	$	1.70
Gathering, transportation and production taxes		2.41		1.88		0.53
DD&A		8.97		7.99		0.98
G&A expenses		4.68		3.63		1.05
Operating expenses	$	30.09	$	25.83	$	4.26

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

Table of Contents

Base lease operating expenses increased primarily due to increased expenses related to the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields acquired during the first half of 2022, and increased insurance expense. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve 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 million in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 primarily due to a new transportation contract related to the properties acquired in the first half of 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, increased to $8.97 per Boe for the nine months ended September 30, 2022 from $7.99 per Boe for the nine months ended September 30, 2021. On a nominal basis, DD&A increased $15.5 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021 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 and gas prices compared to the smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses – G&A increased $13.7 million to $51.8 million for the nine months ended September 30, 2022 as compared to $38.1 million for the nine months ended September 30, 2021. The increase is primarily due to non-recurring professional services costs incurred 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, we incurred increased incentive compensation costs related to the higher grant date fair value of RSU and PSU awards granted during 2022 as compared to the value of awards granted in 2021.

Other Income and Expense

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


	Nine Months Ended September 30,
	2022		2021			Change

Other income and expenses:
Derivative loss	$	109,892	$	179,156	$	(69,264)
Interest expense, net		54,915		50,474		4,441
Other (income) expense, net		(1,229)		964		(2,193)
Income tax expense (benefit)		46,801		(18,846)		65,647

Derivative loss – During the nine months ended September 30, 2022, the $109.9 million derivative loss recorded for crude oil and natural gas derivative contracts consists of $96.3 million of realized losses 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 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 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.

Interest expense, net – Interest expense, net, was $54.9 million and $50.5 million for the nine months ended September 30, 2022 and 2021, respectively. The increase of $4.4 million in 2022 is primarily due to 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 partially offset by expenses for additional contingent abandonment obligations pertaining to certain of legacy Gulf of Mexico properties. See 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 months ended September 30, 2022 was $46.8 million compared to an income tax benefit of $18.8 million during the nine months ended September 30, 2021. For the nine months ended September 30, 2022 and 2021, income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes and adjustments to our valuation allowance. Our effective tax rate was 20.0% and 17.3% for the nine months ended September 30, 2022 and 2021, respectively.

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 30, 2022, we had $447.1 million cash on hand and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. Additionally, 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,
	2022		2021			Change

	(In thousands)
Operating activities	$	326,851	$	111,291	$	215,560
Investing activities		(89,677)		(12,406)		(77,271)
Financing activities		(35,843)		114,973		(150,816)

Operating activities – Net cash provided by operating activities increased $215.6 million for the nine months ended September 30, 2022 compared to the corresponding period in 2021. This was primarily due to (i) the $332.8 million increase in oil, NGL, and natural gas revenues during the nine months ended September 30, 2022 as compared to the prior year period, and (ii) $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. 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.

Table of Contents

These increases 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 operating cash flows by $13.2 million as compared to $43.3 million for the nine months ended September 30, 2022 and 2021, respectively, primarily related to higher oil and natural gas receivables balances due to higher realized prices combined with higher payables and accrued liabilities balances.

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

Financing activities – During the nine months ended September 30, 2022, cash used in financing activities was $35.8 million, primarily due to principal payments on the Term Loan. Net cash provided by financing activities was $115.0 million for the nine months ended September 30, 2021 which included the proceeds from the Term Loan of $206.8 million, offset by $11.8 million of principal payments on the Term Loan and repayment of $80.0 million of borrowings under the Credit Agreement.

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 8 – 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,
	2022		2021		2022		2021
Crude Oil ($/Bbl):	��
Average realized sales price, before the effects of derivative settlements	$	90.23	$	68.57	$	97.59	$	63.07
Effects of realized commodity derivatives		(9.97)		(12.55)		(14.90)		(8.72)
Average realized sales price, including realized commodity derivatives	$	80.26	$	56.02	$	82.69	$	54.35
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements	$	9.89	$	4.31	$	7.58	$	3.40
Effects of realized commodity derivatives⁽¹⁾⁽²⁾		(4.56)		(1.49)		1.52		(0.55)
Average realized sales price, including realized commodity derivatives	$	5.33	$	2.82	$	9.10	$	2.85

(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.}

Income Taxes – For 2022, we expect 10% to 15% of our income tax expense to be cash taxes. We do not have any outstanding current income taxes receivable and made $5.2 million in income tax payments during the nine months ended September 30, 2022. See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

Table of Contents

Capital Expenditures

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


	Nine Months Ended September 30,
	2022		2021

	(In thousands)
Exploration⁽¹⁾	$	10,065	$	5,850
Development⁽¹⁾		12,743		5,660
Acquisitions of interests		51,474		754
Seismic and other		7,158		3,761
Investments in oil and gas property/equipment – accrual basis	$	81,440	$	16,025

(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,
	2022		2021

	(In thousands)

Conventional shelf ⁽¹⁾	$	10,473	$	4,469
Deepwater		12,335		7,041
Exploration and development capital expenditures – accrual basis	$	22,808	$	11,510

(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 months ended September 30, 2022 were financed by cash flow from operations and cash on hand.

Acquisitions – As described in Financial Statements – Note 4 – Acquisitions under Part I, Item 1 of this Quarterly Report, 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 30, 2022 and December 31, 2021 were $453.6 million and $424.5 million, respectively. The increase is primarily due to the acquisition of assets as described above. These increases were 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 Annual Report for additional information.

Table of Contents

Drilling Activity

We did not drill any wells in the nine months ended September 30, 2022. During the nine months ended September 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

Term Loan – As of September 30, 2022, we had $157.0 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 under Part I, Item 1 of this Quarterly Report for additional information.

Credit Agreement – During the nine months ended September 30, 2022, 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 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

Senior Second Lien Notes – 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. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements – Note 2 – 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 financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, Credit Agreement and the Indenture. 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 30, 2022. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

Table of Contents

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. See Financial Statements – Note 5 – Subsidiary Borrowers under Part II, Item 1 in this Quarterly Report for additional information.

At that time, we designated the Aquasition Entities as unrestricted subsidiaries under the Indenture governing our Senior Second Lien Notes (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the 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.

Table of Contents

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 30, 2022 (in thousands):


	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
Restricted cash		4,417		—		4,417
Receivables:
Oil and natural gas sales		89,195		(80,431)		8,764
Joint interest, net		16,815		5,749		22,564
Total receivables		106,010		(74,682)		31,328
Prepaid expenses and other assets		53,014		(614)		52,400
Total current assets		610,571		(129,515)		481,056
Oil and natural gas properties and other, net		729,958		(280,444)		449,514
Restricted deposits for asset retirement obligations		21,760		—		21,760
Deferred income taxes		62,334		—		62,334
Other assets		65,681		19,438		85,119
Total assets	$	1,490,304	$	(390,521)	$	1,099,783
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	75,068	$	(49,859)	$	25,209
Undistributed oil and natural gas proceeds		59,518		(22,077)		37,441
Asset retirement obligations		54,886		—		54,886
Accrued liabilities		154,236		(89,431)		64,805
Current portion of long-term debt		35,450		(35,450)		—
Income tax payable		1,613		—		1,613
Total current liabilities		380,771		(196,817)		183,954
Long-term debt
Principal		674,031		(121,571)		552,460
Unamortized debt issuance costs		(8,058)		5,067		(2,991)
Long-term debt, net		665,973		(116,504)		549,469
Asset retirement obligations, less current portion		398,724		(59,107)		339,617
Other liabilities		99,740		(79,602)		20,138
Deferred income taxes		113		—		113
Common stock		1		—		1
Additional paid-in capital		557,386		—		557,386
Retained deficit		(588,237)		61,509		(526,728)
Treasury stock, at cost		(24,167)		—		(24,167)
Total shareholders’ equity (deficit)		(55,017)		61,509		6,492
Total liabilities and shareholders’ equity (deficit)	$	1,490,304	$	(390,521)	$	1,099,783

Table of Contents

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 months ended September 30, 2022 (in thousands):


		Consolidated		Eliminations of Unrestricted Subsidiaries		Consolidated restricted subsidiaries
Revenues:
Oil	$	412,526	$	(710)	$	411,816
NGLs		47,430		(28,541)		18,889
Natural gas		257,452		(180,109)		77,343
Other		13,889		(9,265)		4,624
Total revenues		731,297		(218,625)		512,672
Operating expenses:
Lease operating expenses		155,397		(37,350)		118,047
Gathering, transportation and production taxes		26,647		(13,910)		12,737
Depreciation, depletion, amortization and accretion		99,384		(619)		98,765
General and administrative expenses		51,790		(1,082)		50,708
Total operating expenses		333,218		(52,961)		280,257
Operating income		398,079		(165,664)		232,415

Interest expense, net		54,915		(11,841)		43,074
Derivative loss (gain)		109,892		(187,896)		(78,004)
Other income, net		(1,229)		(64)		(1,293)
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

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:


		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

Table of Contents

Contractual Obligations

As of September 30, 2022, there were no long-term drilling rig commitments. Except as disclosed herein, contractual obligations as of September 30, 2022 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our 2021 Annual Report.

Critical Accounting Policies and Estimates

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

There have been no changes to our critical accounting policies which are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of our 2021 Annual Report.

Recent Accounting Pronouncements

There was no recently issued accounting standards material to us.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our CEO and 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 30, 2022, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

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

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Financial Statements – Note 12 – 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 the date of this Quarterly Report, except as described below, there have been no material changes to our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our 2021 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.

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.

Table of Contents

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 of Contents

Item 6. Exhibits


Exhibit Number		Description

3.1		Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

3.2		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 (File No. 001-32414))

10.1*†		Eleventh Amendment to Sixth Amended and Restated Credit Agreement dated effective as of November 7, 2022

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.

Table of Contents

SIGNATURE

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


	W&T OFFSHORE, INC.

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. senior Avg

W&T Offshore (WTI) 10-Q2022 Q3 Quarterly report

Content analysis