UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2021

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

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


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

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

(713) 626-8525

(Registrant’s telephone number, including area code)

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

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

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


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

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

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

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


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

As of July 31, 2021 there were 142,367,242 shares outstanding of the registrant’s common stock, par value $0.00001.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I –FINANCIAL INFORMATION		1

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2021 and 2020	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Six Months Ended June 30, 2021 and 2020	3
	Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2021 and 2020	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	37

PART II – OTHER INFORMATION		38
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 6.	Exhibits	39

SIGNATURE		41

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)


	June 30,		December 31,
	2021		2020
Assets
Current assets:
Cash and cash equivalents	$	209,148	$	43,726
Receivables:
Oil and natural gas sales		50,220		38,830
Joint interest, net		11,750		10,840
Total receivables		61,970		49,670
Prepaid expenses and other assets (Note 1)		30,705		13,832
Total current assets		301,823		107,228

Oil and natural gas properties and other, net (Note 1)		657,657		686,878

Restricted deposits for asset retirement obligations		29,820		29,675
Deferred income taxes		107,337		94,331
Other assets (Note 1)		42,395		22,470
Total assets	$	1,139,032	$	940,582
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	54,624	$	48,612
Undistributed oil and natural gas proceeds		28,688		19,167
Asset retirement obligations		23,888		17,188
Accrued liabilities (Note 1)		100,363		29,880
Current portion of long-term debt		36,771		—
Income tax payable		63		153
Total current liabilities		244,397		115,000
Long-term debt (Note 2)
Principal		730,689		632,460
Unamortized debt issuance costs		(12,773)		(7,174)
Long-term debt, net		717,916		625,286

Asset retirement obligations, less current portion		380,115		375,516
Other liabilities (Note 1)		56,259		32,938
Deferred income taxes		128		128
Commitments and contingencies (Note 11)		—		—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued at June 30, 2021 and December 31, 2020		—		—
Common stock, $0.00001 par value; 200,000 shares authorized; 145,236 issued and 142,367 outstanding at June 30, 2021; 145,174 issued and 142,305 outstanding at December 31, 2020		1		1
Additional paid-in capital		551,260		550,339
Retained deficit		(786,877)		(734,459)
Treasury stock, at cost; 2,869 shares at June 30, 2021 and December 31, 2020		(24,167)		(24,167)
Total shareholders’ deficit		(259,783)		(208,286)
Total liabilities and shareholders’ deficit	$	1,139,032	$	940,582

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues:
Oil	$	88,013	$	30,645	$	166,153	$	115,295
NGLs		8,833		1,917		18,193		8,369
Natural gas		32,470		21,364		68,679		50,664
Other		3,512		1,315		5,451		5,041
Total revenues		132,828		55,241		258,476		179,369
Operating costs and expenses:
Lease operating expenses		47,552		28,313		89,909		83,088
Production taxes		1,956		1,143		3,952		2,059
Gathering and transportation		4,824		3,301		9,143		8,750
Depreciation, depletion, amortization and accretion		30,952		29,483		57,589		68,609
General and administrative expenses		13,986		5,628		24,698		19,591
Derivative loss (gain)		81,440		15,414		106,020		(46,498)
Total costs and expenses		180,710		83,282		291,311		135,599
Operating (loss) income		(47,882)		(28,041)		(32,835)		43,770

Interest expense, net		16,530		14,816		31,564		31,926
Gain on debt transactions		—		(28,968)		—		(47,469)
Other expense, net		—		751		963		1,474
(Loss) income before income taxes		(64,412)		(14,640)		(65,362)		57,839
Income tax benefit		(12,740)		(8,736)		(12,944)		(2,237)
Net (loss) income	$	(51,672)	$	(5,904)	$	(52,418)	$	60,076
Basic and diluted (loss) earnings per common share	$	(0.36)	$	(0.04)	$	(0.37)	$	0.42

See Notes to Condensed Consolidated Financial Statements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at March 31, 2020	141,669	$	1	$	548,098	$	(706,269)	2,869	$	(24,167)	$	(182,337)
Share-based compensation	—		—		1,019		—	—		—		1,019
Stock Issued	—		—		—		—	—		—		—
Net loss	—		—		—		(5,904)	—		—		(5,904)
Balances at June 30, 2020	141,669	$	1	$	549,117	$	(712,173)	2,869	$	(24,167)	$	(187,222)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at March 31, 2021	142,305	$	1	$	550,793	$	(735,205)	2,869	$	(24,167)	$	(208,578)
Share-based compensation	—				467		—	—		—		467
Stock Issued	62		—		—		—	—		—		—
Net loss	—		—		—		(51,672)	—		—		(51,672)
Balances at June 30, 2021	142,367	$	1	$	551,260	$	(786,877)	2,869	$	(24,167)	$	(259,783)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at December 31, 2019	141,669	$	1	$	547,050	$	(772,249)	2,869	$	(24,167)	$	(249,365)
Share-based compensation	—		—		2,067		—	—		—		2,067
Stock Issued	—		—		—		—	—		—		—
Net income	—		—		—		60,076	—		—		60,076
Balances at June 30, 2020	141,669	$	1	$	549,117	$	(712,173)	2,869	$	(24,167)	$	(187,222)


	Common Stock			Additional							Total
	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	—		—		921		—	—		—		921
Stock Issued	62		—		—		—	—		—		—
Net loss	—		—		—		(52,418)	—		—		(52,418)
Balances at June 30, 2021	142,367	$	1	$	551,260	$	(786,877)	2,869	$	(24,167)	$	(259,783)

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2021		2020
Operating activities:
Net (loss) income	$	(52,418)	$	60,076
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		57,589		68,609
Amortization of debt items and other items		2,967		3,682
Share-based compensation		921		2,067
Derivative loss (gain)		106,020		(46,498)
Derivative cash (payments) receipts, net		(41,130)		37,566
Gain on debt transactions		—		(47,469)
Deferred income taxes		(13,006)		(2,207)
Changes in operating assets and liabilities:
Oil and natural gas receivables		(11,390)		34,984
Joint interest receivables		(910)		4,743
Prepaid expenses and other assets		(17,605)		3,505
Income tax		(92)		2,008
Asset retirement obligation settlements		(11,213)		(2,164)
Cash advances from JV partners		(3,925)		5,850
Accounts payable, accrued liabilities and other		30,386		(31,274)
Net cash provided by operating activities		46,194		93,478
Investing activities:
Investment in oil and natural gas properties and equipment		(5,856)		(14,138)
Changes in operating assets and liabilities associated with investing activities		(3,078)		(25,811)
Acquisition of property interests		—		(456)
Purchases of furniture, fixtures and other		2		(70)
Net cash used in investing activities		(8,932)		(40,475)
Financing activities:
Borrowings on credit facility		—		25,000
Repayments on credit facility		(80,000)		(50,000)
Purchase of Senior Second Lien Notes		—		(23,930)
Proceeds from Term Loan		215,000		—
Debt issuance costs and other		(6,840)		—
Net cash provided by (used in) financing activities		128,160		(48,930)
Increase in cash and cash equivalents		165,422		4,073
Cash and cash equivalents, beginning of period		43,726		32,433
Cash and cash equivalents, end of period	$	209,148	$	36,506

See Notes to Condensed Consolidated Financial Statements.

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1. Basis of Presentation

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

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

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

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

Accounting Standards Updates effective January 1, 2021

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

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

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

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Credit Risk and Allowance for Credit Losses. Our revenue has been concentrated in certain major oil and gas companies. For the six months ended June 30, 2021, and the year ended December 31, 2020, approximately 64% and 62%, respectively, of our revenue was from three major oil and gas companies and a substantial majority of our receivables were from sales with major oil and gas companies. We also have receivables related to joint interest arrangements primarily with mid-size oil and gas companies with a substantial majority of the net receivable balance concentrated in less than ten companies. A loss methodology is used to develop the allowance for credit losses on material receivables to estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and forecasts of future economic conditions. Our maximum exposure at any time would be the receivable balance. The receivables related to joint interest billings are reported on the Condensed Consolidated Balance Sheets net of the allowance for credit losses. The allowance for credit losses was $9.1 million as of June 30, 2021 and December 31, 2020.

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


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

(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):


	June 30, 2021		December 31, 2020
Oil and natural gas properties and equipment, at cost	$	8,583,983	$	8,567,509
Furniture, fixtures and other		20,845		20,847
Total property and equipment		8,604,828		8,588,356
Less: Accumulated depreciation, depletion, amortization and impairment		7,947,171		7,901,478
Oil and natural gas properties and other, net	$	657,657	$	686,878

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


	June 30, 2021		December 31, 2020
Right-of-Use assets	$	10,783	$	11,509
Unamortized debt issuance costs		1,333		2,094
Investment in White Cap, LLC		2,995		2,699
Unamortized brokerage fee for Monza		—		626
Proportional consolidation of Monza's other assets (Note 5)		4,209		1,782
Derivatives		21,005		2,762
Other		2,070		998
Total other assets (long-term)	$	42,395	$	22,470

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


	June 30, 2021		December 31, 2020
Accrued interest	$	10,185	$	10,389
Accrued salaries/payroll taxes/benefits		4,218		4,009
Litigation accruals		570		436
Lease liability		673		394
Derivatives		82,832		13,620
Other		1,885		1,032
Total accrued liabilities	$	100,363	$	29,880

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

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


	June 30, 2021		December 31, 2020
Dispute related to royalty deductions	$	5,247	$	5,467
Derivatives		28,122		4,384
Lease liability		11,062		11,360
Black Elk escrow		11,102		11,103
Other		726		624
Total other liabilities (long-term)	$	56,259	$	32,938

2. Debt

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


	June 30, 2021		December 31, 2020
Term Loan:
Principal	$	215,000	$	—
Unamortized debt issuance costs		(6,718)		—
Total Term Loan		208,282		—

Company Credit Agreement borrowings:		—		80,000

Senior Second Lien Notes:
Principal		552,460		552,460
Unamortized debt issuance costs		(6,055)		(7,174)
Total Senior Second Lien Notes		546,405		545,286

Less current portion		(36,771)		—
Total long-term debt, net	$	717,916	$	625,286

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Current Portion of Long-Term Debt

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

Term Loan (Subsidiary Credit Agreement)

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

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

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

Company Credit Agreement

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

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

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

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

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

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

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

Availability under the Company Credit Agreement is subject to semi-annual redeterminations of our borrowing base and, the next scheduled redetermination is to occur on or about October 1, 2021. Subsequent to the October 2021 redetermination, additional redeterminations may be requested at the discretion of either the lenders or the Company. The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Company Credit Agreement. The Company currently has no borrowings outstanding under the Company Credit Agreement and has agreed to not to make borrowings under the Company Credit Agreement unless and until the next semi-annual redetermination of our borrowing base occurs and the Company complies with certain revised hedging requirements.

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

As of June 30, 2021 and December 31, 2020, we had $4.4 million of letters of credit issued and outstanding under the Company Credit Agreement. No borrowings under the Company Credit Agreement were outstanding as of June 30, 2021 and $80.0 million in borrowings were outstanding under the Company Credit Agreement as of December 31, 2020. The annualized interest rate on borrowings outstanding for the six months ended June 30, 2021 was 3.2%, which excludes debt issuance costs, commitment fees and other fees.

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9.75% Senior Second Lien Notes Due 2023

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

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

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

Covenants

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

Fair Value Measurements

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

3. Fair Value Measurements

Derivative Financial Instruments

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

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


	June 30, 2021		December 31, 2020
Assets:
Derivatives instruments - open contracts, current	$	13,111	$	2,705
Derivatives instruments - open contracts, long-term		21,005		2,762

Liabilities:
Derivatives instruments - open contracts, current		74,632		13,291
Derivatives instruments - open contracts, long-term		28,122		4,384

Debt

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

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


	June 30, 2021				December 31, 2020
	Net Value		Fair Value		Net Value		Fair Value
Liabilities:
Term Loan	$	208,282	$	214,607	$	—	$	—
Company Credit Agreement		—		—		80,000		80,000
Senior Second Lien Notes		546,405		536,660		545,286		393,352
Total		754,687		751,267		625,286		473,352

4. Mobile Bay Transaction

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

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

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The SPVs are wholly-owned subsidiaries of the Company; however, the assets of the SPVs will not be available to satisfy the debt or contractual obligations of any non-SPV entities, including debt securities or other contractual obligations of W&T Offshore, Inc., and the SPVs do not bear any liability for the indebtedness or other contractual obligations of any non-SPVs, and vice versa. As of June 30, 2021, the book value of the assets of the SPVs were $292.4 million.

5. Joint Venture Drilling Program

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

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

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

Through June 30, 2021, nine wells have been completed. In 2020, one well was drilled to target depth, which we expect to be completed in the fourth quarter of 2021. W&T is the operator for seven of the nine wells completed through June 30, 2021.

Through June 30, 2021, members of Monza made partner capital contributions, including our contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling $77.9 million. Our net contribution to Monza, reduced by distributions received, as of June 30, 2021 was $51.6 million. W&T is obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for the Joint Venture Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

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Consolidation and Carrying Amounts

Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation. Through June 30, 2021, there have been no events or changes that would cause a redetermination of the variable interest status. We do not fully consolidate Monza because we are not considered the primary beneficiary of Monza. As of June 30, 2021, in the Condensed Consolidated Balance Sheet, we recorded $6.6 million, net, in Oil and natural gas properties and other, net, $4.2 million in Other assets, $0.3 million in Asset Retirement Obligations ("ARO") and $1.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. As of December 31, 2020, in the Condensed Consolidated Balance Sheet, we recorded $9.9 million, net, in Oil and natural gas properties and other, net, $1.8 million in Other assets, $0.2 million in ARO and $1.3 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. Additionally, during the six months ended June 30, 2021 and during the year ended December 31, 2020, we called on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of June 30, 2021 and December 31, 2020 were $3.4 million and $7.3 million, respectively, which are included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners. For the six months ended June 30, 2021, in the Condensed Consolidated Statement of Operations, we recorded $5.5 million in Total revenues and $6.7 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations. For the year ended December 31, 2020, in the Condensed Consolidated Statement of Operations, we recorded $8.4 million in Total revenues and, $12.1 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations.

6. Asset Retirement Obligations

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

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


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

7. Derivative Financial Instruments

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

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

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

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



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

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

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

(1)	Bbls = Barrels

(2) MMbtu = Million British Thermal Units

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

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


	June 30,		December 31,
	2021		2020
Prepaid expenses and other current assets	$	14,021	$	2,752
Other assets (long-term)		21,005		2,762
Accrued liabilities		82,832		13,620
Other liabilities (long-term)		28,122		4,384

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Realized loss (gain)	$	15,357	$	(22,578)	$	23,602	$	(31,970)
Unrealized loss (gain)		66,083		37,992		82,418		(14,528)
Derivative loss (gain)	$	81,440	$	15,414	$	106,020	$	(46,498)

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


	Six Months Ended June 30,
	2021		2020
Derivative loss (gain)	$	106,020	$	(46,498)
Derivative cash (payments) receipts, net		(41,130)		37,566

8. Share-Based Awards and Cash-Based Awards

Share-Based Awards to Employees

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

As of June 30, 2021, there were 10,347,591 shares of common stock available for issuance in satisfaction of awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when awards are settled in shares of common stock, which shares of common stock are issued net of withholding tax through the withholding of shares. The Company has the option following vesting to settle awards in stock or cash, or a combination of stock and cash. The Company expects to settle outstanding awards, discussed below, that vest in the future using shares of common stock.

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

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

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


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

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


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

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

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


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

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. All PSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. The grant date fair value of the PSUs was determined through the use of the Monte Carlo simulation method. This method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group companies’ stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies. The valuation model assumes dividends, if any, are immediately reinvested. The grant date fair value of the PSUs granted during the six months ended June 30 2021, is $2.2 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted:


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

Share-Based Awards to Non-Employee Directors

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

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

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

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


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

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

Share-Based Compensation Expense

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Share-based compensation expense from:
Restricted stock units	$	339	$	949	$	676	$	1,927
Restricted Shares		128		70		245		140
Total	$	467	$	1,019	$	921	$	2,067

Unrecognized Share-Based Compensation Expense

As of June 30, 2021, unrecognized share-based compensation expense related to our awards of RSUs, PSUs, and Restricted Shares was $3.9 million, $2.2 million, and $0.2 million, respectively. Unrecognized share-based compensation expense will be recognized through December 2023 for RSUs, September 2023 for PSUs, and April 2022 for Restricted Shares.

Cash-Based Incentive Compensation

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

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

●

The first short-term, cash-based award granted in February 2021 was discretionary and subject only to continued employment on the payment dates. The 2021 discretionary bonus award was paid in equal installments on March 15, 2021 and April 15, 2021, to substantially all employees subject to employment on those dates. Incentive compensation expense of $3.8 million and $7.6 million was recognized during the three and six months ended June 30, 2021, respectively, related to these awards.

●

The second short-term, cash-based award granted in June 2021 is subject to Company performance-based criteria and individual performance criteria. Incentive compensation expense is based on estimates of Company metrics for full-year 2021 and is being recognized during the 2021 service period. Incentive compensation expense for this award was not material during the six months ended June 30, 2021.

No cash-based incentive awards were granted in 2020, and therefore, no cash-based incentive compensation expense for 2020 was recorded.

Long-term Cash-Based Incentive Compensation.

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

These Cash Awards are accounted for as liability awards and are measured at fair value each reporting date. We recognize compensation cost for share-based payments to employees over the service period from June 28, 2021 through October 1, 2023. The reporting date fair value of the awards was determined through the use of the Monte Carlo simulation method. This method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined peer group companies’ stock, risk-free rate of return, cross-correlations between the Company and our peer group companies, and an appropriate discount rate. The valuation model assumes dividends are immediately reinvested. The fair value of the awards as of June 30, 2021, is $2.2 million. As of June 30, 2021, unrecognized compensation expense related to these awards was $2.2 million. The following table summarizes the assumptions used to calculate the fair value of the outstanding long-term Cash Awards as of June 30, 2021:


	2021 Grant Date
	June 28
Expected term for performance period (in years)	0.5
Expected volatility	67.9	%
Risk-free interest rate	0.1	%
Expected term for cash payment (in years)	2.3
Discount rate used to discount expected cash payment	12.1	%

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Share-based compensation included in:
General and administrative expenses	$	467	$	1,019	$	921	$	2,067
Cash-based incentive compensation included in:
Lease operating expense (1)		816		—		1,655		849
General and administrative expenses (1)		2,676		159		5,359		3,790
Total charged to operating (loss) income	$	3,959	$	1,178	$	7,935	$	6,706

(1)

Includes adjustments of accruals to actual payments.

9. Income Taxes

Tax Benefit and Tax Rate. Income tax benefit for the three months ended June 30, 2021 and 2020 was $12.7 and $8.7 million, respectively. For the six months ended June 30, 2021 and 2020, income tax benefit was $12.9 million and $2.2 million, respectively. For the three and six months ended June 30, 2021, our effective tax rate differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the three and six months ended June 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded as a result of to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 19.8% for both the three and six months ended June 30, 2021 and 59.7% and (3.9%) for the three and six months ended June 30, 2020, respectively.

Calculation of Interim Provision for Income Tax. Historically, we have calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full year to income (loss) for the interim period. In the second quarter of 2021, we concluded that we could not calculate a reliable estimate of our annual effective tax rate. Accordingly, we computed the effective tax rate for the six-month period ending June 30, 2021 using actual results.

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

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

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

The tax years 2017 through 2020 remain open to examination by the tax jurisdictions to which we are subject.

10. Earnings Per Share

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net (loss) income	$	(51,672)	$	(5,904)	$	(52,418)	$	60,076
Less portion allocated to nonvested shares		—		—		—		707
Net (loss) income allocated to common shares	$	(51,672)	$	(5,904)	$	(52,418)	$	59,369
Weighted average common shares outstanding		142,244		141,597		142,197		141,571
Basic and diluted (loss) earnings per common share	$	(0.36)	$	(0.04)	$	(0.37)	$	0.42
Shares excluded due to being anti-dilutive (weighted-average)		880		1,665		899		—

11. Contingencies

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

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

Notices of Proposed Civil Penalty Assessment. In January 2021, we executed a Settlement Agreement with the Bureau of Safety and Environmental Enforcement (“BSEE”) which resolved nine pending civil penalties issued by BSEE. The civil penalties pertained to Incidents of Noncompliance (“INCs”) issued by BSEE alleging regulatory non-compliance at separate offshore locations on various dates between July 2012 and January 2018, with the proposed civil penalty amounts totaling $7.7 million. Under the Settlement Agreement, W&T will pay a total of $720,000 in three annual installments. The first installment was paid in March 2021. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022. During the three months ended June 30, 2021, we did not pay any civil penalties to BSEE related to newly issued INCs.

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

12. Subsequent Events

As described in more detail in Note 2 – Debt, on July 15, 2021, the Company entered into a Waiver and Seventh Amendment to Sixth Amended and Restated Credit Agreement dated effective June 30, 2021, which further amended the Company Credit Agreement and waived certain hedging transaction requirements.

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

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

Forward-Looking Statements

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

These forward-looking statements are subject risks, uncertainties and assumptions, most of which are difficult to predict and many of which are beyond our control. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, estimates, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our 2020 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of June 2021, we hold working interests in 41 offshore fields in federal and state waters (40 fields producing and 1 field capable of producing, with 33 fields in federal waters and 8 in state waters). We currently have under lease approximately 621,700 gross acres (424,400 net acres) spanning across the outer continental shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama State waters, 426,800 gross acres on the conventional shelf and approximately 186,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, W & T Energy VI, LLC, Delaware limited liability companies, and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements – Note 5 Joint Venture Drilling Program under Part I, Item 1 in this Quarterly Report.

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Recent Events

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

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

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

This transaction is described in more detail under Financial Statements –Note 4 – Mobile Bay Transaction, under Part 1, Item 1, of this Quarterly Report.

Oil and Natural Gas Production and Commodity Pricing

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the six months ended June 30, 2021 were comprised of 37.4% crude oil and condensate, 10.0% NGLs and 52.6% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past. For the six months ended June 30, 2021, our total revenues were 44.1% higher than the six months ended June 30, 2020 due to higher realized prices for crude oil, NGLs and natural gas, which were partially offset by lower volumes. See Results of Operations – Six Months Ended June 30, 2021, Compared to the Six Months Ended June 30, 2020 in this Item 2 for additional information.

Our operating results are strongly influenced by the price of the commodities that we produce and sell. The price of those commodities is affected by both domestic and international factors, including domestic production. During the six months ended June 30, 2021, our average realized crude oil price was $60.88 per barrel. This is an increase of 71.2% from our average realized crude oil price of $35.57 per barrel during the six months ended June 30, 2020. Per the Energy Information Administration ("EIA"), crude oil prices using average West Texas Intermediate (“WTI”) daily spot pricing increased to $62.21 per barrel during the six months ended June 30, 2021 compared to $36.58 per barrel during the six months ended June 30, 2020 representing an increase of 70.1%. Crude oil prices have recovered to pre-pandemic levels from their April 2020 lows caused by the ongoing COVID-19 pandemic as the vaccines have been more widely distributed and economic activity has increased.

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Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary significantly by field. All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of Poseidon, LLS and HLS to WTI for the six months ended June 30, 2021 averaged ($0.23), $2.06, and $1.60 per barrel, respectively, and each average differential has changed ($0.13), $0.75, and $0.58 per barrel, respectively compared to the six months ended June 30, 2020.

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

Our average realized price of NGLs of $24.94 per barrel for the six months ended June 30, 2021 was 169.6% higher than the average realized price of $9.25 per barrel for the six months ended June 30, 2020. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the six months ended June 30, 2021 compared to the six months ended June 30, 2020, average prices for domestic ethane increased by 81.4% and average domestic propane prices increased by 189.0% as measured using a price index for Mount Belvieu. The average prices for other domestic NGLs components increased from 87.5% to 107.3% for the six months ended June 30, 2021 compared to the same period in 2020. We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as reported in their July 23, 2021 report was higher than a year ago, increasing to 491 rigs compared to 253 rigs a year ago. The oil rig count increased to 387 rigs compared to 180 rigs a year ago and the gas and miscellaneous rigs increased to 104 rigs from 73 a year ago. In the Gulf of Mexico, the number of working rigs was 17 rigs compared to 12 a year ago.

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Results of Operations

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2021		2020			Change	2021		2020			Change

	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	88,013	$	30,645	$	57,368	$	166,153	$	115,295	$	50,858
NGLs		8,833		1,917		6,916		18,193		8,369		9,824
Natural gas		32,470		21,364		11,106		68,679		50,664		18,015
Other		3,512		1,315		2,197		5,451		5,041		410
Total revenues		132,828		55,241		77,587		258,476		179,369		79,107
Operating costs and expenses:
Lease operating expenses		47,552		28,313		19,239		89,909		83,088		6,821
Production taxes		1,956		1,143		813		3,952		2,059		1,893
Gathering and transportation		4,824		3,301		1,523		9,143		8,750		393
Depreciation, depletion, amortization and accretion		30,952		29,483		1,469		57,589		68,609		(11,020)
General and administrative expenses		13,986		5,628		8,358		24,698		19,591		5,107
Derivative loss (gain)		81,440		15,414		66,026		106,020		(46,498)		152,518
Total costs and expenses		180,710		83,282		97,428		291,311		135,599		155,712
Operating (loss) income		(47,882)		(28,041)		(19,841)		(32,835)		43,770		(76,605)
Interest expense, net		16,530		14,816		1,714		31,564		31,926		(362)
Gain on debt transactions		—		(28,968)		28,968		—		(47,469)		47,469
Other expense, net		—		751		(751)		963		1,474		(511)
(Loss) income before income tax (benefit) expense		(64,412)		(14,640)		(49,772)		(65,362)		57,839		(123,201)
Income tax (benefit) expense		(12,740)		(8,736)		(4,004)		(12,944)		(2,237)		(10,707)
Net (loss) income	$	(51,672)	$	(5,904)	$	(45,768)	$	(52,418)	$	60,076	$	(112,494)
Basic and diluted (loss) earnings per common share	$	(0.36)	$	(0.04)	$	(0.32)	$	(0.37)	$	0.42	$	(0.79)

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	Three Months Ended June 30,						Six Months Ended June 30,
	2021		2020			Change	2021		2020			Change
Operating: (1) (2)
Net sales:
Oil (MBbls)		1,352		1,414		(62)		2,729		3,241		(512)
NGLs (MBbls)		337		410		(73)		729		905		(176)
Natural gas (MMcf)		12,189		12,006		183		22,988		27,313		(4,325)
Total oil equivalent (MBoe)		3,721		3,826		(106)		7,290		8,699		(1,409)

Average daily equivalent sales (Boe/day)		40,888		42,047		(1,159)		40,278		47,795		(7,517)
Average realized sales prices:
Oil ($/Bbl)	$	65.11	$	21.67	$	43.44	$	60.88	$	35.57	$	25.31
NGLs ($/Bbl)		26.18		4.67		21.51		24.94		9.25		15.69
Natural gas ($/Mcf)		2.66		1.78		0.88		2.99		1.85		1.14
Oil equivalent ($/Boe)		34.75		14.09		20.66		34.71		20.04		14.67
Oil equivalent ($/Boe), including realized commodity derivatives)		38.89		8.19		30.69		37.94		16.36		21.58

Average per Boe ($/Boe):
Lease operating expenses	$	12.78	$	7.40	$	5.38	$	12.33	$	9.55	$	2.78
Gathering and transportation		1.30		0.86		0.44		1.25		1.01		0.24
Production costs		14.08		8.26		5.82		13.58		10.56		3.02
Production taxes		0.52		0.30		0.22		0.54		0.24		0.30
DD&A		8.32		7.71		0.61		7.90		7.89		0.01
G&A expenses		3.76		1.47		2.29		3.39		2.25		1.14
Operating costs	$	26.68	$	17.74	$	8.94	$	25.41	$	20.94	$	4.47

(1)

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

(2)	Some average figures and variance percentages in this table may not compute due to rounding.


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

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

Revenues. The increase in oil revenues was attributable to an increase in average realized sales price per Bbl to $65.11 from $21.67 for the three months ended June 30, 2021 and 2020, respectively. This was partially offset by a decrease in oil sales volumes of 4.4% for the three months ended June 30, 2021 as compared to the same period in the prior year. The increase in NGLs revenues was attributable to an increase in the average realized sales price per Bbl to $26.18 from $4.67 for the three months ended June 30, 2021 and 2020, respectively. This was partially offset by a 17.8% decrease in NGL sales volumes during the three months ended June 30, 2021 as compared to the same period in the prior year. The increase in natural gas revenues was attributable to an increase in the average realized price to $2.66 per Mcf from $1.78 per Mcf for the three months ended June 30, 2021 and 2020, respectively, and a 1.5% increase in volumes.

Overall, sales volumes decreased 2.7% on a Boe per day basis primarily due to shut-ins related to well maintenance at the Mahogany field and (to a lesser extent) the Mobile Bay area. We estimate that these shut-ins reduced the produced volumes for the three months ended June 30, 2021 by approximately 3,198 Boe per day as compared to 4,100 Boe per day for the three months ended June 30, 2020.

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

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance expense, increased $19.2 million, or 68.0%, for the three months ended June 30, 2021 compared to the three months ended June 30, 2020. On a component basis, base lease operating expenses increased $14.6 million, workover expenses increased $2.0 million, facilities maintenance expense increased $1.4 million, and hurricane repairs increased $1.2 million.

Base lease operating expenses increased primarily due to (i) higher contract labor, equipment rental, and transportation costs of $3.1 million at various fields; (ii) increased incentive compensation costs related to field employees of $2.2 million; (iii) a reduction in credits to expense from prior period royalty adjustments of $2.4 million as compared to the prior period; (iv) a reduction in credits to expense of $2.3 million received in prior period from the PPP funds; and (v) a reduction in credits to expense in the prior year associated with the finalization of the Mobile Bay acquisition. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Lastly, we incurred $1.2 million in expenses related to hurricane repairs at various fields during the three months ended June 30, 2021 that we did not incur during the comparable prior year period.

Production taxes. Production taxes increased $0.8 million in the three months ended June 30, 2021 compared to the three months ended June 30, 2020 due to the increase in realized natural gas prices, increased NGL prices, and to a lesser extent increased natural gas production volumes.

Gathering and transportation. Gathering and transportation expenses increased $1.5 million for the three months ended June 30, 2021 compared to the three months ended June 30, 2020 primarily due to lower costs in the comparable prior year period that were impacted by credits to expense associated with the finalization of the Mobile Bay acquisition.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, increased to $8.32 per Boe for the three months ended June 30, 2021 from $7.71 per Boe for the three months ended June 30, 2020. On a nominal basis, DD&A increased 5.0%, or $1.5 million for the three months ended June 30, 2021 as compared to the three months ended June 30, 2020. The rate per Boe increased year-over-year mostly as a result of increases in the future development costs included in the depreciable base compared to the relatively smaller increase in proved reserves over the comparable prior year period.

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General and administrative expenses (“G&A”). G&A increased $8.4 million, or 148.5%, for the three months ended June 30, 2021 as compared to the three months ended June 30, 2020. The increase was primarily due to (i) increased incentive compensation expenses and payroll expenses of $1.8 million; (ii) a decrease of $5.0 million in G&A credits related to the PPP funds received in the prior period; (iii) an increase in legal costs of $0.4 million; (iv) a reduction in overhead allocations to partners (credits to expense) of $0.6 million, and (v) increases of $0.6 million in other miscellaneous G&A expense items such as software licensing and surety bond costs.

Derivative loss (gain). The three months ended June 30, 2021 includes an $81.4 million derivative loss primarily due to increased crude oil and natural gas prices during June 2021 compared to prices during March 2021, which decreased the estimated fair value of open contracts between the two measurement dates. The three months ended June 30, 2020 reflects a $15.4 million derivative loss primarily due to increased crude oil prices during June 2020 compared to oil prices during March 2020, which decreased the estimated fair value of open crude oil contracts between the two measurement dates. Partially offsetting were realized gains from oil swap contracts where the price was below the contract strike price.

Interest expense, net. Interest expense, net, was $16.5 million and $14.8 million for the three months ended June 30, 2021 and 2020, respectively. The increase of $1.7 million in 2021 is primarily due to interest expense on the principal balance of the Term Loan, and a reduction in credits to interest expense related to the PPP funds received in the prior period; partially offset by reductions to outstanding borrowings (lower interest expense) under the Company Credit Agreement during 2021.

Gain on purchase of debt. A gain of $29.0 million was recorded related to the purchase of $45.1 million of principal of our outstanding Senior Second Lien Notes during the three months ended June 30, 2020. No such transactions occurred during the three months ended June 30, 2021.

Income tax benefit. Our income tax benefit was $12.7 million and $8.7 million for the three months ended June 30, 2021 and 2020, respectively. For the three months ended June 30, 2021, our income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the three months ended June 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded related to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 19.8% for the three months ended June 30, 2021 and 59.7% for the three months ended June 30, 2020.

As of June 30, 2021, the valuation allowance on our deferred tax assets was $22.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Quarterly Report for additional information.

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

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

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

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

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

Base lease operating expenses increased during the six months ended June 30, 2021 primarily due to (i) higher contract labor, equipment rental, and transportation costs of $1.3 million at various fields; (ii) increased incentive compensation costs related to field employees of $2.2 million; (iii) a reduction in credits to expense from prior period royalty adjustments of $1.1 million as compared to the prior period; (iv) a reduction in credits to expense of $2.3 million received in prior period from the PPP funds; and (v) a reduction in credits to expense in the prior year associated with the finalization of the Mobile Bay acquisition; partially offset by (vi) $5.7 million of reduced expenses during the first quarter of 2021 related to successful cost reduction efforts at various fields and other reduced expenses; and (vii) $4.3 million of reduced expenses related to fields that were no longer producing during the six months ended June 30, 2021. The increases in workover expenses and facilities maintenance expense were due to an increase in projects undertaken. Lastly, we incurred $3.8 million in expenses related to hurricane repairs at various fields during the six months ended June 30, 2021 that we did not incur during the prior year period.

Production taxes. Production taxes increased $1.9 million during the six months ended June 30, 2021 compared to the three months ended June 30, 2020 due to the increase in realized natural gas prices, partially offset by decreased natural gas production volumes.

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

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, increased to $7.90 per Boe for the six months ended June 30, 2021 from $7.89 per Boe for the six months ended June 30, 2020. On a nominal basis, DD&A decreased 16.1%, or $11.0 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. The rate per BOE increased year-over-year mostly as a result of increases in future development costs included in the depreciable base compared to the relatively smaller increase in proved reserves and the decrease in production volumes over the same period.

General and administrative expenses. G&A increased $5.1 million, or 26.1%, for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. The increase was primarily due to (i) a decrease of $5.0 million in G&A credits related to the PPP funds received in the prior period; (ii) a reduction in overhead allocations to partners (credits to expense) of $1.6 million; and (iii) an increase in legal costs of $1.2 million; partially offset by (i) the $2.1 million employee retention credit recognized during the three months ended March 31, 2021, and (ii) a net decrease of $0.6 million in payroll and incentive compensation expenses. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, and Liquidity and Capital Resources in this Item 2 of this Form 10-Q for additional information on the employee retention credit.

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

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Interest expense, net. Interest expense, net, was $31.6 million and $31.9 million for the six months ended June 30, 2021 and 2020, respectively. The decrease is primarily due to reductions to outstanding borrowings (lower interest expense) under the Company Credit Agreement during 2021; partially offset by interest expense on the principal balance of the Term Loan, and a reduction in credits to interest expense related to the PPP funds received in the prior period.

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

Income tax benefit. Our income tax benefit was $12.9 million and $2.2 million for the six months ended June 30, 2021 and 2020, respectively. For the six months ended June 30, 2021, our income tax benefit differed from the statutory Federal tax rate primarily by the impact of state income taxes. For the six months ended June 30, 2020, our effective tax rate primarily differed from the statutory Federal tax rate for adjustments recorded as a result to the enactment of the CARES Act on March 27, 2020. The CARES Act modified certain income tax statutes, including changes related to the business interest expense limitation under Code Section 163(j). Our effective tax rate was 19.8% for the six months ended June 30, 2021 and (3.9)% for the six months ended June 30, 2020.

Liquidity and Capital Resources

Liquidity Overview

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

As of June 30, 2021, we had $209.1 million cash on hand, no borrowings under our Company Credit Agreement and no maturities of long-term debt until October 2023, other than scheduled quarterly amortization payments under the Term Loan (see Financial Statements – Note 2 – Debt, under Part I, Item 1 of this Quarterly Report for additional information). We currently expect our cash on hand, net cash provided by operating activities and other available sources of liquidity to be sufficient to meet our cash requirements over the next 12 months. We have recently agreed by amendment to our Company Credit Agreement to refrain from borrowing under our bank credit facility unless and until the next redetermination of our borrowing base, which is scheduled to occur on or about October 1, 2021, and the Company complies with certain revised hedging requirements. We expect that our borrowing base under our Company Credit Agreement will be adjusted in the next scheduled redetermination, including adjustments as a result of the elimination of the Mobile Bay assets as collateral under the Company Credit Agreement.

We are actively monitoring the debt capital markets, and we intend to seek financing with longer tenors and market based covenants to continue to provide working and potential acquisition capital. The terms of such financing, which may replace or augment our current Company Credit Agreement, may vary significantly from those under our current Company Credit Agreement.

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Sources and Uses of Cash

Cash Flow Overview


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

Operating activities. Net cash provided by operating activities decreased $47.3 million for the six months ended June 30, 2021 compared to the corresponding period in 2020. This was primarily due to (i) cash derivative payments, the net of which decreased operating cash flows $41.1 million for the six months ended June 30, 2021 compared to cash derivative receipts, net, which increased operating cash flows $37.6 million for the six months ended June 30, 2020; and (ii) asset retirement obligation settlements which decreased operating cash flows by $11.2 million for the six months ended June 30, 2020 compared to $2.2 million for the six months ended June 30, 2020.

Our combined average realized sales price per Boe increased by 73.2% for the six months ended June 30, 2021 compared to the six months ended June 30, 2020, which caused total revenues to increase $106.6 million. The increase to revenues was offset by a 16.2% decrease in total sales volumes during the six months ended June 30, 2021 as compared to the six months ended June 30, 2020, which cause revenues to decrease $27.9 million. Other items affecting operating cash flows were (i) higher receivable balances due to increases in realized prices, which decreased operating cash flows by $12.3 million for the six months ended June 30, 2021 compared to an increase of $39.7 million for the six months ended June 30, 2020; and (ii) decreased cash advance balances from joint venture partners, which decreased operating cash flows by $3.9 million for the six months ended June 30, 2021 compared to an increase of $5.9 million for the six months ended June 30, 2020. Other working capital items and share based compensation expense accounted for the remaining changes in net cash provided by operating activities.

Investing activities. Net cash used in investing activities decreased $31.5 million for the six months ended June 30, 2021 compared to the corresponding period in 2020. Our current year capital budget is weighted toward the second half of 2021, therefore, investing activities have been lower in the six months ended June 30, 2021 compared to the same period in 2020. Net cash used in investing activities for the six months ended June 30, 2021 included $3.1 million in working capital changes associated with capital expenditures incurred in 2020 but paid during the six months ended June 30, 2021.

Financing activities. Net cash provided by financing activities increased $177.1 million for the six months ended June 30, 2021 compared to the corresponding period in 2020. Net cash provided by financing activities for the six months ended June 30, 2021 was $128.2 million compared to net cash used in financing activities of $48.9 million for the six months ended June 30, 2020. The net cash provided for the six months ended June 30, 2021 included the proceeds from the term loan of $208.2 million, offset by repayment of $80.0 million of borrowings under the Company Credit Agreement. The net cash used for the six months ended June 30, 2020 included repayment of $25.0 million of borrowings under the Credit Agreement and $23.9 million to purchase $72.5 million principal of Senior Second Lien Notes on the open market.

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


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

Asset Retirement Obligations. Each quarter, we review and revise our ARO estimates. Our ARO estimates as of June 30, 2021 and December 31, 2020 were $404.0 million and $392.7 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 for additional information.

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

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

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Capital Expenditures

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


	Six Months Ended June 30,
	2021		2020

	(In thousands)
Exploration (1)	$	1,309	$	1,686
Development (1)		902		10,274
Magnolia and Mobile Bay acquisitions		471		456
Seismic and other		3,174		2,177
Investments in oil and gas property/equipment – accrual basis	$	5,856	$	14,593

(1)

Reported geographically in the subsequent table.

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


	Six Months Ended June 30,
	2021		2020

	(In thousands)

Conventional shelf	$	101	$	9,391
Deepwater		2,110		2,569
Exploration and development capital expenditures – accrual basis	$	2,211	$	11,960

Our exploration and development spending decreased $9.7 million compared to prior year, primarily in the conventional shelf area, which includes Alabama state waters, due to the fact that our current year capital budget is weighted toward the second half of 2021. Excluding acquisitions and plugging and abandonment expenditures, we are currently estimating capital expenditures to range from $30.0 million to $60.0 million for 2021 and ARO spending to range from $25.0 million to $35.0 million.

The capital expenditures are included within Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheets and recorded on an incurred basis. The capital expenditures reported within the Investing section of the Condensed Consolidated Statements of Cash Flows include adjustments to report cash payments related to capital expenditures. Net cash used in investing activities for the six months ended June 30, 2021 included $3.1 million in working capital changes associated with capital expenditures incurred in 2020 but paid during the six months ended June 30, 2021. Our capital expenditures for the six months ended June 30, 2021 were financed by cash flow from operations and cash on hand.

Drilling Activity

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

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Debt

Term Loan. As of June 30, 2021, we had $215.0 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments commencing September 30, 2021, bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than Borrowers and the subsidiary that owns the equity of Borrowers, and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of Borrowers (the Mobile Bay Properties). See Financial Statements – Note 2 –Debt under Part I, Item 1 of this Form 10-Q for additional information.

Company Credit Agreement. As of June 30, 2021, we had no borrowings outstanding under the Company Credit Agreement and letters of credit issued under the Company Credit Agreement were $4.4 million. During the six months ended June 30, 2021, we repaid $80.0 million of borrowings. The Company Credit Agreement matures on October 18, 2022.

Availability under our Company Credit Agreement is subject to semi-annual redeterminations of our borrowing base, which was lowered from $215.0 million to $190.0 million following redetermination on January 6, 2021. As of June 30, 2021, we had no borrowings under our Company Credit Agreement and, in light of our expected near term capital needs and our current cash position, we have agreed not to make borrowings under the Company Credit Agreement unless and until the next scheduled redetermination of our borrowing base on or about October 1, 2021 and the Company complies with certain revised hedging requirements (pursuant to the Seventh Amendment executed on July 15, 2021). Generally, we must be in compliance with the covenants in our Company Credit Agreement in order to access borrowings under the Company Credit Agreement.

We anticipate an adjustment to our borrowing base under the Company Credit Agreement in the next scheduled redetermination primarily as a result of the elimination of the Mobile Bay assets as collateral under the Company Credit Agreement and pledge of such assets under the Subsidiary Credit Agreement.

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

Debt Covenants. The Term Loan, Company Credit Agreement, and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, Company Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Term Loan, Company Credit Agreement and the Senior Second Lien Notes indenture as of and for the period ended June 30, 2021. See Financial Statements – Note 2 – Debt under Part I, Item 1 of this Quarterly Report for additional information.

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

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Uncertainties

Bureau of Ocean Energy Management (“BOEM”) Matters. In order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurance that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. As of the filing date of this Form 10-Q, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.

Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have historically requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. No additional demands were made to us by sureties during 2021 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

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

Insurance Coverage

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

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

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

Contractual Obligations

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

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Quarterly Report), other contractual obligations as of June 30, 2021 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2020.

Critical Accounting Policies and Estimates

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

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

Recent Accounting Pronouncements

See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, of this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

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

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

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

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Financial Statements – Note 11 – Contingencies under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.

Item 1A. Risk Factors

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

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our 2020 Annual Report.

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Item 6. Exhibits


Exhibit Number		Description

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

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

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

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

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

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

10.3*		Credit Agreement, dated May 19, 2021, by and among Aquasition LLC, as Borrower, Aquasition II LLC, as Co-Borrower, and Munich Re Reserve Risk Financing, as the lenders party thereto.

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

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

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

31.1*		Section 302 Certification of Chief Executive Officer

31.2*		Section 302 Certification of Chief Financial Officer

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

101.INS*		Inline XBRL Instance Document

101.SCH*		Inline XBRL Schema Document

101.CAL*		Inline XBRL Calculation Linkbase Document

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101.DEF*		Inline XBRL Definition Linkbase Document

101.LAB*		Inline XBRL Label Linkbase Document

101.PRE*		Inline XBRL Presentation Linkbase Document

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

*	Filed or furnished herewith.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 4, 2021.


	W&T OFFSHORE, INC.

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