		Page
PART I –FINANCIAL INFORMATION

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	2
	Condensed Consolidated ~~Statement~~Statements of Changes in Shareholders’ Deficit for the Three Months Ended March 31, 2020 and 2019 ~~and 2018~~	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31 33
Item 4.	Controls and Procedures	32 33

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	33 34
Item 1A.	Risk Factors	33 34
Item 5.	Other Information	35
Item 6.	Exhibits	34 36

SIGNATURE		35
		37

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

	March 31,			December 31,			March 31,			December 31,
	2019			2018			2020			2019
Assets
Current assets:
Cash and cash equivalents	$	86,116		$	33,293		$	47,574		$	32,433
Receivables:
Oil and natural gas sales		41,308			47,804			35,413			57,367
Joint interest, net		17,620			14,634
Joint interest and other, net								12,277			19,400
Income taxes		54,076			54,076			1,861			1,861
Total receivables		113,004			116,514			49,551			78,628
Prepaid expenses and other assets (Note 1)		34,127			76,406			78,658			30,691
Total current assets		233,247			226,213			175,783			141,752

Oil and natural gas properties and other, net - at cost (Note 1)		514,765			515,421			730,044			748,798

Restricted deposits for asset retirement obligations		15,498			15,685			15,574			15,806
Deferred income taxes								57,418			63,916
Other assets (Note 1)		79,005			91,547			30,084			33,447
Total assets	$	842,515		$	848,866		$	1,008,903		$	1,003,719
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	71,359		$	82,067		$	61,729		$	102,344
Undistributed oil and natural gas proceeds		22,014			28,995			28,176			29,450
Advances from joint interest partners		65,271			20,627			18,285			5,279
Asset retirement obligations		24,799			24,994			2,803			21,991
Accrued liabilities (Note 1)		35,197			29,611			34,428			30,896
Total current liabilities		218,640			186,294			145,421			189,960

Long-term debt (Note 2)		634,005			633,535
Long-term debt: (Note 2)
Principal								677,525			730,000
Carrying value adjustments								(9,467	)		(10,467	)
Long term debt - carrying value								668,058			719,533

Asset retirement obligations, less current portion		289,363			285,143			361,297			333,603
Other liabilities (Note 1)		73,142			68,690			16,464			9,988
Commitments and contingencies (Note 10)		—			—
Commitments and contingencies								—			—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued for both dates presented		—			—			—			—
Common stock, $0.00001 par value; 200,000 shares authorized; 143,513 issued and 140,644 outstanding for both dates presented		1			1
Common stock, $0.00001 par value; 200,000 shares authorized; 144,538 issued and 141,669 outstanding for both dates presented								1			1
Additional paid-in capital		545,627			545,705			548,098			547,050
Retained deficit		(894,096	)		(846,335	)		(706,269	)		(772,249	)
Treasury stock, at cost; 2,869 shares for both dates presented		(24,167	)		(24,167	)		(24,167	)		(24,167	)
Total shareholders’ deficit		(372,635	)		(324,796	)		(182,337	)		(249,365	)
Total liabilities and shareholders’ deficit	$	842,515		$	848,866		$	1,008,903		$	1,003,719

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED ~~CONSOLIDATED~~CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Allowance for credit losses, December 31, 2019	$	9,898
Additional provisions		36
Uncollectible accounts written off		—
Allowance for credit losses, March 31, 2020	$	9,934

Oil and Natural Gas Properties and Other, Net – ~~at cost.~~ At Cost. 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):

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

(Unaudited)

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

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

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

~~In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-13,~~ ~~Financial Instruments – Credit Losses~~ (~~Topic 326~~) (“ASU 2016-13”). The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018. We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

(Unaudited)

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

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement ~~(the~~(as amended, the “Credit Agreement”), which matures on October 18, 2022. The primary terms and covenants associated with the Credit Agreement are as follows, with capitalized terms defined under the Credit Agreement:

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base ~~to occur on~~in or ~~before~~around May 15 and November 14of each calendar year, and ~~certain~~ additional redeterminations ~~that~~ 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 Credit Agreement. See Note 12, Subsequent Events, for revisions to certain terms of the Credit Agreement, including the borrowing base, Leverage Ratio and collateral, resulting from the Spring 2020 semi-annual redetermination.

The Credit ~~Agreement’s security~~Agreement is collateralized by a first priority lien on ~~substantially all~~properties constituting at least 85% of ~~our oil and natural gas properties~~the total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement and certain personal property. The annualized interest rate on borrowings outstanding for the three months ended March 31, ~~2019~~2020 was ~~5.1%~~4.5%, ~~which~~ which excludes debt issuance costs, commitment fees and other fees.

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

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%~~10.4%, ~~which~~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, beginning~~year.

During the three months ended March 31, 2020, we acquired $27.5 million in principal of our outstanding Senior Second Lien Notes for $8.5 million and recorded a non-cash gain on ~~May 1, 2019.~~purchase of debt of $18.5 million, which included a reduction of $0.4 million related to the write-off of unamortized debt issuance costs. The Company purchased additional Senior Second Lien Notes subsequent to March 31, 2020 (refer to Note 12, Subsequent Events).

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. 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 entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).~~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.

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

As of March 31, ~~2019,~~2020 and for all prior measurement periods, we were in compliance with all applicable covenants of the Credit Agreement and ~~Senior Second Lien Notes indenture.~~the Indenture.

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

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

We believe the carrying value of our debt under the 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 ~~based~~ using quoted prices, although the market is not a very active market. The fair value of our long-term debt was classified as Level 2 within the valuation hierarchy. See Note 2, Long-Term Debt for additional information on our long-term debt.

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

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

(Unaudited)

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

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

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

Table of Contents

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

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):

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

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 2019, 2018 ~~2017~~ and ~~2016.~~2017. As of March 31, ~~2019,~~2020, there were ~~128,980~~82,620 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. During the second quarter of 2020, our shareholders approved increasing the shares available by 500,000 shares. During the second quarter of 2020, 109,376 Restricted Shares were granted to non-employee directors. 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.

There was no activity related to Restricted Shares during the three months ended March 31, 2020.

For the outstanding Restricted Shares issued to the non-employee directors as of March 31, ~~2019,~~2020, vesting is expected to occur as follows (subject to any forfeitures):

Share-Based Compensation. 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 ~~adjustments in the valuation allowance.~~our income tax situation. A summary of incentive compensation expense under share-based payment arrangements is as follows (in thousands):

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

Unrecognized Share-Based Compensation.As of March 31, ~~2019,~~2020, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was ~~$5.5~~$4.0 million and ~~$0.3~~$0.4 million, respectively. Unrecognized share-based compensation expense will be recognized through November ~~2020~~2021 for RSUs and April ~~2021~~2022 for Restricted Shares.

Table of Contents

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

Cash-Based Incentive Compensation. In addition to share-based ~~awards,~~compensation, short-term, cash-based awards were granted under the Plan to substantially all eligible employees in ~~2018~~2019 and ~~2017. For 2018, there were two~~2018. The short-term, cash-based awards, ~~consisting of a long-term award and~~which are generally a short-term ~~award. All cash-based awards~~component of the Plan, are performance-based awards consisting of ~~predetermined~~one or more business criteria or individual performance criteria ~~applied against~~and a targeted level or levels of performance with respect to each of such criteria. In addition, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (terms as defined in the ~~applicable performance period. Expense~~awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each ~~award~~cash-based award. During 2018, long-term, cash awards were granted to certain employees subject to pre-defined performance criteria. Expense is recognized over the service period once the ~~applicable~~business criteria, individual performance criteria and financial condition ~~is expected to be met, and~~are met.

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

Table of ~~accruals to actual payments.~~Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

(Unaudited)

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

(Unaudited)

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 accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, 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 Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 and this Quarterly Report on Form 10-Q, Part II, Item 1A, Risk Factors, and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

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. We ~~have grown through acquisitions, exploration and development and hold working interests in 48 offshore fields in federal and state waters (47 producing and one field capable of producing). We~~ currently have under lease approximately ~~720,000~~815,000 gross acres ~~(390,000~~(550,000 net acres) spanning across the ~~Outer Continental Shelf (“OCS”)~~OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately ~~515,000~~595,000 gross acres on the conventional shelf and approximately ~~205,000~~220,000 gross acres in the ~~deepwater (water depths in excess of 500 feet).~~deepwater. A majority of our daily production is derived from wells we operate. Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company and through our proportionately consolidated ~~interests~~interest in Monza, as described in more detail in Financial ~~Statements–~~Statements and Supplementary Data – Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

Due to circumstances related to the outbreak of COVID-19, various measures have been taken by federal, state and local governments to reduce the rate of spread of COVID-19. These measures and other factors have resulted in a decrease of general economic activity and a corresponding decrease in global and domestic energy demand impacting commodity pricing. In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) have negatively impacted crude oil prices. These rapid and unprecedented events have pushed crude oil storage near capacity and driven prices down significantly. These events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing. These conditions may continue to exist in future periods, constraining our ability to store and move production to downstream markets, or affecting future decisions to delay or curtail development activity or temporarily shut-in production which could further reduce cash flow.

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The Company has responded to COVID-19 events and current economic conditions as follows:

See the Liquidity and Capital Resources section in this Part II for a discussion of our liquidity and other aspects as a result of the decrease in commodity prices. See Item 1A, Risk Factors, under Item II of this Form 10-Q.

Our financial condition, ~~cash~~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 three months ended March 31, ~~2019~~2020 were comprised of ~~49.2%~~37.5% crude oil and condensate, ~~10.3%~~10.2% NGLs and ~~40.5%~~52.3% 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 three months ended March 31, ~~2019,~~2020, revenues from the sale of crude oil and NGLs made up ~~80.2%~~73.4% of our total revenues compared to ~~79.7%~~80.2% for the three months ended March 31, ~~2018.~~2019. For the three months ended March 31, ~~2019,~~2020, our combined total production expressed in equivalent volumes was ~~9.8% lower~~62.4% higher than for the three months ended March 31, ~~2018, with natural gas having~~2019, primarily due to the ~~largest decline.~~acquisition of the Mobile Bay properties described below. For the three months ended March 31, ~~2019,~~2020, our total revenues were ~~13.5% lower~~6.9% higher than the three months ended March 31, ~~2018 primarily~~2019 due to ~~lower production~~the higher volumes and partially offset by lower realized prices for crude oil, NGLs and ~~NGLs.~~natural gas. See Results of Operations –Three Months Ended March 31, ~~2019~~2020 Compared to the Three Months Ended March 31, ~~2018~~2019 in this Item 2 for additional information.

In August 2019, we completed the purchase of Exxon Mobil Corporation's (“Exxon”) interests in and operatorship of oil and gas producing properties in the eastern region of the Gulf of Mexico offshore Alabama and related onshore and offshore facilities and pipelines (the “Mobile Bay Properties”). After taking into account customary closing adjustments and an effective date of January 1, 2019, cash consideration was $169.8 million, of which substantially all was paid by us at closing. We also assumed the related asset retirement obligations (“ARO”) and certain other obligations associated with these assets. The acquisition was funded from cash on hand and borrowings of $150.0 million under the Credit Agreement (defined below), which were previously undrawn. As of December 31, 2019, the Mobile Bay Properties had approximately 76.6 MMBoe of net proved reserves, of which 99% were proved developed producing reserves consisting primarily of natural gas and NGLs with 20% of the proved net reserves from liquids on an MMBoe basis, based on SEC pricing methodology. For the three months ended March 31, 2020, the average production of the Mobile Bay Properties was approximately 18,500 net Boe per day. The properties include working interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing properties owned and operated by us. With this purchase, we became the largest operator in the area.

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Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. ~~During in~~For the three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018,~~2019, average prices for domestic ethane ~~increased~~decreased by 6%55% and average domestic propane prices decreased by ~~21%~~44% as measured using a price index for Mount Belvieu. The average ~~price~~prices for other domestic NGLs components ~~ranged from decreases of 15%~~decreased 19% to ~~18%~~29% for the three months ended March 31, ~~2019 year-over-year.~~2020 compared to the same period in 2019. 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 ~~of the end of March 2019~~reported in their May 29, 2020 report was ~~approximately the same level as~~significantly lower than a year ago, ~~levels for land based~~decreasing to 301 rigs ~~(an increase of four~~compared to 984 rigs ~~or less than 1%), and higher in the Gulf of Mexico (an increase of 11 rigs or 92%).~~a year ago. The oil rig count ~~as of March 2019~~decreased to 222 rigs compared to 800 rigs a year ago and ~~March 2018 was 816~~the gas and ~~797, respectively. The U.S. natural gas rig count as of March 2019 and March 2018 was 190 and 194, respectively.~~miscellaneous rigs decreased to 79 rigs from 184 a year ago. In the Gulf of Mexico, the number of working rigs was ~~23 rigs (18 oil rigs and five natural gas rigs) as of March 2019 and~~ 12 rigs (all oil) compared to 23 (20 oil ~~rigs) as~~and three natural gas) a year ago.

Table of ~~March 2018. During the three months ended March 31, 2019, we had four rigs running, which represents approximately 20% of the active rigs in the Gulf of Mexico.~~

Contents

Our current capital expenditure forecast for 2019 is approximately $120.0 million composed of select shelf and deepwater projects that, assuming success, would be placed on production within a few months after completion. The forecast also incorporates our capital spending relating to the JV Drilling Program (net to our interest). Our 2019 plans also include spending $24.0 million for ARO. Based upon current price and production expectations for 2019, we believe that our cash flows from operating activities and cash on hand will be sufficient to fund our operations through year-end 2019 and build available cash balances; however, future cash flows are subject to a number of variables and additional capital expenditures may be required to more fully develop our properties. We are also currently evaluating various acquisition opportunities, which, if successful, may increase our capital requirements in 2019 and beyond. We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2019 plans. See our Annual Report on Form 10-K for the year ended December 31, 2018, for additional information.

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

March 31,

2019

2018

Change

%

(In thousands, except percentages and per share data)

Financial:

Revenues:

Oil
$
86,703

$
97,306

$
(10,603
)

(10.9
)%
NGLs

6,448

9,660

(3,212
)

(33.3
)%
Natural gas

21,838

25,867

(4,029
)

(15.6
)%
Other

1,091

1,380

(289
)

(20.9
)%
Total revenues

116,080

134,213

(18,133
)

(13.5
)%
Operating costs and expenses:

Lease operating expenses

43,456

36,843

6,613

17.9
%
Production taxes

416

455

(39
)

(8.6
)%
Gathering and transportation

6,423

5,057

1,366

27.0
%
Depreciation, depletion, amortization and accretion

33,766

38,081

(4,315
)

(11.3
)%
General and administrative expenses

14,109

15,038

(929
)

(6.2
)%
Derivative loss

48,886

—

48,886

NM

Total costs and expenses

147,056

95,474

51,582

54.0
%
Operating (loss) income

(30,976
)

38,739

(69,715
)

NM

Interest expense, net

16,282

10,962

5,320

48.5
%
Other expense, net

331

28

303

NM

(Loss) income before income tax expense

(47,589
)

27,749

(75,338
)

NM

Income tax expense

172

109

63

57.8
%
Net (loss) income
$
(47,761
)

$
27,640

$
(75,401
)

NM

Basic and diluted (loss) earnings per common share
$
(0.34
)

$
0.19

$
(0.53
)

NM

	Three Months Ended March 31,
	2020			2019			Change				%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	84,650		$	86,703		$	(2,053	)	(2.4	)%
NGLs		6,452			6,448			4		0.1	%
Natural gas		29,300			21,838			7,462		34.2	%
Other		3,726			1,091			2,635		241.5	%
Total revenues		124,128			116,080			8,048		6.9	%
Operating costs and expenses:
Lease operating expenses		54,775			43,456			11,319		26.0	%
Production taxes		916			416			500		120.2	%
Gathering and transportation		5,449			6,423			(974	)	(15.2	)%
Depreciation, depletion, amortization and accretion		39,126			33,766			5,360		15.9	%
General and administrative expenses		13,963			14,109			(146	)	(1.0	)%
Derivative (gain) loss		(61,912	)		48,886			(110,798	)	NM
Total costs and expenses		52,317			147,056			(94,739	)	(64.4	)%
Operating income (loss)		71,811			(30,976	)		102,787		NM
Interest expense, net		17,110			16,282			828		5.1	%
Gain on purchase of debt		(18,501	)		—			(18,501	)	NM
Other expense, net		723			331			392		118.4	%
Income (loss) before income tax expense		72,479			(47,589	)		120,068		NM
Income tax expense		6,499			172			6,327		NM
Net income (loss)	$	65,980		$	(47,761	)	$	113,741		NM
Basic and diluted earnings (loss) per common share	$	0.46		$	(0.34	)	$	0.80		NM

NM – not meaningful

Table of Contents

Three Months Ended

March 31,

2019

2018

Change

% ⁽²⁾

Operating: ⁽¹⁾

Net sales:

Oil (MBbls)

1,478

1,557

(79
)

(5.1
)%
NGLs (MBbls)

309

351

(42
)

(12.0
)%
Natural gas (MMcf)

7,288

8,523

(1,235
)

(14.5
)%
Total oil equivalent (MBoe)

3,001

3,328

(327
)

(9.8
)%

Average daily equivalent sales (Boe/day)

33,349

36,976

(3,627
)

(9.8
)%
Average realized sales prices:

Oil ($/Bbl)
$
58.66

$
62.52

$
(3.86
)

(6.2
)%
NGLs ($/Bbl)

20.88

27.54

(6.66
)

(24.2
)%
Natural gas ($/Mcf)

3.00

3.03

(0.03
)

(1.0
)%
Oil equivalent ($/Boe)

38.31

39.92

(1.61
)

(4.0
)%

Average per Boe ($/Boe):

Lease operating expenses
$
14.48

$
11.07

$
3.41

30.8
%
Gathering and transportation

2.14

1.52

0.62

40.8
%
Production costs

16.62

12.59

4.03

32.0
%
Production taxes

0.14

0.14

—

—

DD&A

11.25

11.44

(0.19
)

(1.7
)%
G&A expenses

4.70

4.52

0.18

4.0
%

$
32.71

$
28.69

$
4.02

14.0
%

	Three Months Ended March 31,
	2020		2019		Change				%
Operating: (1)
Net sales:
Oil (MBbls)		1,827		1,478		349		23.6	%
NGLs (MBbls)		495		309		186		60.2	%
Natural gas (MMcf)		15,307		7,288		8,019		110.0	%
Total oil equivalent (MBoe)		4,873		3,001		1,872		62.4	%

Average daily equivalent sales (Boe/day)		53,553		33,349		20,204		60.6	%
Average realized sales prices:
Oil ($/Bbl)	$	46.33	$	58.66	$	(12.33	)	(21.0	)%
NGLs ($/Bbl)		13.03		20.88		(7.85	)	(37.6	)%
Natural gas ($/Mcf)		1.91		3.00		(1.09	)	(36.3	)%
Oil equivalent ($/Boe)		24.71		38.31		(13.60	)	(35.5	)%

Average per Boe ($/Boe):
Lease operating expenses	$	11.24	$	14.48	$	(3.24	)	(22.4	)%
Gathering and transportation		1.12		2.14		(1.02	)	(47.7	)%
Production costs		12.36		16.62		(4.26	)	(25.6	)%
Production taxes		0.19		0.14		0.05		35.7	%
DD&A		8.03		11.25		(3.22	)	(28.6	)%
G&A expenses		2.87		4.70		(1.83	)	(38.9	)%
	$	23.45	$	32.71	$	(9.26	)	(28.3	)%

(1)

The conversion to ~~Boe~~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.~~

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)~~

~~Variance percentages are calculated using rounded figures and may result in different figures for comparable data.~~

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 March 31, ~~2019~~2020 Compared to the Three Months Ended March 31, ~~2018~~2019

Due to the decrease and volatility in crude oil prices and to a lesser extent, decreases and volatility in natural gas and prices for NGLs, the results of the three months ended March 31, 2020 may not be indicative of future periods. See “Liquidity and Capital Resources – Liquidity Overview” below for additional information.

Revenues. Total revenues ~~decreased $18.1~~increased $8.0 million, or ~~13.5%~~6.9%, to ~~$116.1~~$124.1 million for the three months ended March 31, ~~2019~~2020 as compared to the three months ended March 31, ~~2018.~~2019. Oil revenues decreased ~~$10.6~~$2.1 million, or ~~10.9%~~2.4%, NGLs revenues ~~decreased $3.2 million, or 33.3%,~~were basically flat, natural gas revenues ~~decreased $4.0~~increased $7.5 million, or ~~15.6%~~34.2%, and other revenues ~~decreased $0.3 million.~~increased $2.6 million due to prior period royalty adjustments received during the three months ended March 31, 2020. The decrease in oil revenues was attributable to a ~~6.2%~~21.0% decrease in the average realized sales price to $46.33 per barrel for the three months ended March 31, 2019 from $58.66 per barrel for the three months ended March 31, 2019, ~~from $62.52~~partially offset by an increase in sales volumes of 23.6%. NGLs sales volumes increased by 60.2% and were offset by a 37.6% decrease in the average realized sales price to $13.03 per barrel for the three months ended March 31, ~~2018 and sales volumes decreased 5.1%. The decrease in NGLs revenues was attributable to a 24.2% decrease in the average realized sales price to~~2020 from $20.88 per barrel for the three months ended March 31, ~~2019 from $27.54~~2019. The increase in natural gas revenues was attributable to sales volumes that more than doubled, increasing 110.0%, and partially offset by a 36.3% decrease in the average realized price to $1.91 per ~~barrel~~Mcf for the three months ended March 31, 2018 and sales volumes decreased 12.0%. The decrease in natural gas revenues was attributable to a decrease in sales volumes of 1.2 billion cubic feet (“Bcf”), or 14.5% and a 1.0% decrease in the average realized price to2020 from $3.00 per Mcf for the three months ended March 31, ~~2019 from $3.03 per Mcf for the three months ended March 31, 2018.~~2019. Overall, production volumes ~~decreased 9.8%~~increased 60.6% on a ~~Boe~~Boe/day basis. The largest production increases for the three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018 were from~~2019 was related to our ~~interest~~acquisition of the interests in the ~~Heidelberg field,~~Mobile Bay Properties in August 2019, which ~~was acquired in April 2018, and~~produced an average of 18,500 Boe per day during the three months ended March 31, 2020, increases in production at our ~~Ship Shoal 349~~Mahogany field ~~(Mahogany). Offsetting~~and the acquisition of Garden Banks 783 field (Magnolia) assets in December 2019. These increases were partially offset by production decreases primarily from ~~increases in downtime, with the largest amounts related to planned maintenance, well servicing and rig movements at certain platforms and pipelines.~~natural production declines. Our estimate of deferred production for the three months ended March 31, ~~2019~~2020 was approximately ~~7,200~~3,600 Boe per day as compared to ~~4,200~~7,200 Boe per day for the three months ended March 31, 2018, which comprises 83% of the production volume variance between the two periods. In April 2019, a majority of the pipeline and facility maintenance was completed and improved well performance and continued ramp up of new wells enabled the mid-April production rate to increase to over 37,000 Boe/day. 2019.

Revenues from oil and NGLs as a percent of our total revenues were 73.4% for the three months ended March 31, 2020 compared to 80.2% for the three months ended March 31, ~~2019 compared to 79.7% for the three months ended March 31, 2018.~~2019. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 28.1% for the three months ended March 31, 2020 compared to 35.6% for the three months ended March 31, ~~2019 compared to 44.0% for the three months ended March 31, 2018.~~2019.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased ~~$6.6~~$11.3 million, or ~~17.9%~~26.0%, to ~~$43.5~~$54.8 million in the three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018.~~2019. On a component basis, base lease operating expenses increased ~~$1.4~~$15.9 million, workover expenses ~~increased $2.3~~decreased $3.4 million, and facilities maintenance expense ~~increased $2.9~~decreased $1.2 million. Base lease operating expenses increased primarily due to the ~~addition~~acquisition of the ~~Heidelberg field interest, acquired~~Mobile Bay Properties in ~~April 2018, and~~August 2019, which had base lease operating expenses of ~~$1.7~~$11.3 million for the three months ended March 31, 2020. In addition, the acquisition of the Magnolia field in December 2019 increased base lease operating expenses by $3.2 million. The decreases in workover expense and facility maintenance were due to fewer projects undertaken, with the primary decrease due to a workover at the Mississippi Canyon 800 field occurring during the three months ended March 31, 2019.

Production taxes. Production taxes increased $0.5 million to $0.9 million in the three months ended March 31, 2020 compared to the three months ended March 31, 2019 due to the acquisition of the Mobile Bay Properties, which has operations in state waters.

Gathering and transportation. Gathering and transportation expenses decreased $1.0 million to $5.4 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to lower transportation rates at certain fields and lower volumes at the Green Canyon 859 (Heidelberg) field.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, decreased to $8.03 per Boe for the three months ended March 31, 2020 from $11.25 per Boe for the three months ended March 31, 2019. On a nominal basis, DD&A increased to $39.1 million (or 15.9%) for the three months ended March 31, 2020 from $33.8 million for the three months ended March 31, 2019. DD&A on a nominal basis increased largely due to higher production, partially offset by the lower rate per Boe. The rate per BOE decreased mostly as a result of increases in proved reserves from the acquisition of the Mobile Bay Properties. Other factors affecting the DD&A rate are capital expenditures and revisions to proved reserve volumes.

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General and administrative expenses (“G&A”). G&A was $14.0 million for the three months ended March 31, 2020, decreasing 1.0 % from $14.1 million for the three months ended March 31, 2019. The ~~increase in workover expense~~decrease was primarily due to ~~2019 projects at our Mahogany field. The facility maintenance expense increase was primarily attributable~~increased fees for overhead charged to ~~work performed in 2019 at our Mahogany field combined with multiple other fields.~~

~~Gathering~~partners (credits to expense), lower medical claims and ~~transportation.~~ ~~Gathering and transportation~~lower legal expenses, increased $1.4 million to $6.4 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 primarily related to the East Cameron 321 field due to a change in our customer where transportation costs were separately billed and recorded as such beginning in the second half of 2018, and arepartially offset by ~~higher realized prices recorded for crude oil. In addition, expenses~~ increased ~~due to the Heidelberg field.~~

~~Depreciation, depletion, amortization and accretion (“DD&A”).~~ DDincentive compensation expenses. G&A ~~which includes accretion for ARO, decreased to $11.25~~on a per Boe basis was $2.87 per Boe for the three months ended March 31, ~~2019 from $11.44 per Boe for the three months ended March 31, 2018. On a nominal basis, DD&A decreased~~2020 compared to $33.8 million (or 11.3%) for the three months ended March 31, 2019 from $38.1 million for the three months ended March 31, 2018. DD&A on a nominal basis decreased primarily due to lower production. Other factors affecting the DD&A rate are production, capital expenditures, sales of assets and changes in proved reserves volumes.

~~General and administrative expenses (“G&A”)~~. G&A was $14.1 million for the three months ended March 31, 2019, decreasing 6.2% from $15.0 million for the three months ended March 31, 2018. The decrease was primarily due to a decrease in incentive compensation. G&A on a per Boe basis was $4.70 per Boe for the three months ended March 31, ~~2019 compared to $4.52 per Boe for the~~2019.

Derivative (gain) loss. The three months ended March 31, ~~2018.~~

~~Derivative loss.~~ 2020 reflects a $61.9 million derivative gain primarily due to decreased crude oil prices during March 2020 as compared to oil prices during December 2019, which increased the estimated fair value of closed and open crude oil contracts between the two measurement dates. The three months ended March 31, 2019 reflects a $48.9 million derivative loss primarily due to increased crude oil prices during March 2019 as compared to oil prices during December 2018, which decreased the estimated fair value of open crude oil contracts between the two measurement dates. ~~For the three months ended March 31, 2018, we did not have any gains or losses from derivative contracts.~~

Interest expense, net. Interest expense, net, was ~~$16.3~~$17.1 million and ~~$11.0~~$16.3 million for the three months ended March 31, 2020 and 2019, ~~and 2018,~~ respectively. ~~During 2018, a portion~~The increase is due to higher borrowings under the Credit Agreement related to the acquisition of the Mobile Bay Properties.

Gain on purchase of debt: A gain of $18.5 million was recorded related to the purchase of $27.5 million of principal of our ~~interest was recorded as offsets to carrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60,~~ ~~Troubled Debt Restructuring~~ ~~(“ASC 470-60”), which lowered reported interest expense for~~outstanding Senior Second Lien Notes during the three months ended March 31, ~~2018 and affects the comparability.~~ 2020.

Income tax expense. Our income tax expense for the three months ended March 31, 2020 and 2019 was $6.5 million and ~~2018 was~~ $0.2 million, ~~and $0.1 million,~~ respectively. ~~Immaterial deferred~~For the three months ended March 31, 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 ~~was recorded for~~limitation under Internal Revenue Code Section 163(j). For the three months ended March 31, 2019, immaterial deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance. Our effective tax rate ~~using book pre-tax income~~was 9.0% for the three months ended March 31, 2020 and was not meaningful for ~~either period. For both periods, adjustments in~~ the ~~valuation allowance primarily offset changes in net deferred tax assets.~~three months ended March 31, 2019. As of March 31, ~~2019,~~2020, our valuation allowance was ~~$127.8~~$47.8 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 89 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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Liquidity and Capital Resources

Liquidity Overview

Our primary liquidity needs are to fund capital and operating expenditures and strategic ~~property~~ acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, ~~make related interest payments~~operate our properties and satisfy our AROs. 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 borrowings and expect to continue to do so in the future.

As COVID-19 and other worldly events impact crude oil prices, and to a lesser degree, natural gas prices, we are actively monitoring the impacts on our results of operations, financial position, and liquidity. As of March 31, 2020, we had $47.6 million cash on hand, availability of $170 million under the Credit Agreement (and subsequently reduced by $35 million to $135 million due to redetermination of the borrowing base as discussed in the Credit Agreement section below) and no maturities of long-term debt until 2022. Despite this appearance of liquidity, the impact of unprecedented decline in oil prices during March and April of 2020 were severe and so dramatic as to threaten the entire oil and gas industry including the Company. Oil prices began recovering some in May 2020 and through mid-June 2020. In reaction to these events, we moved quickly to preserve resources and protect the health of our employees. Furthermore, we have taken certain actions to address the current economic environment as follows:

We have reduced our capital expenditure budget for the remainder o. f 2020. Excluding acquisitions and plugging and abandonment expenditures, we are estimating capital expenditures to be approximately $15 million to $25 million for 2020. ARO (plugging and abandonment) spending is estimated to be between of $2 million to $4 million..

Since December 31, 2019, we have reduced the amount outstanding of our Senior Second Lien Notes by $72.5 million to $552.5 million as of June 22, 2020 through purchases in the open market for $23.9 million, resulting in annualized interest savings of $7.1 million.

On ~~October 18, 2018,~~June 17, 2020, we entered into the Third Amendment and Waiver to the Credit Agreement, which, ~~matures~~among other things, waived the Leverage Ratio (as defined in the Credit Agreement) and replaced it with a first lien leverage covenant of 2.00 to 1.00 through year-end 2021.

While we currently expect our cash on ~~October~~hand, net cash provided by operating activities and our available sources of liquidity are sufficient to meet our cash requirements, the Company will continue to monitor the evolving situation. In the event of long-term market deterioration, the Company may need additional liquidity, which would require us to evaluate alternatives and take appropriate actions.

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Sources and Uses of Cash

Cash Flow and Working Capital. Net cash provided by operating activities for the three months ended March 31, 2020 and 2019 was $84.3 million and $84.8 million, respectively. Production volumes increased by 60.6% measured on a Boe per day basis, which caused revenues to increase by $48.4 million. Our combined average realized sales price per Boe decreased by 35.5% for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, which caused total revenues to decrease $43.0 million.

Other items affecting operating cash flows were lower receivable balances, which increased operating cash flows by $29.1 million for the three months ended March 31, 2020 compared to an increase of $3.5 million for the three months ended March 31, 2019; lower cash advance balances from joint venture partners, which decreased $31.6 million between the two periods; lower cash derivative receipts, net, which decreased $7.5 million between the two periods; and a return of collateral related to a bond of $6.9 million which occurred during the three months ended March 31, 2020. Other working capital items accounted for the changes in net cash provided by operating activities

Net cash used in investing activities primarily represents our acquisition of and investments in oil and gas properties and equipment partially offset by sales of such assets. Net cash used in investing activities for the three months ended March 31, 2020 and 2019 was $35.6 million and $31.6 million, respectively. Our capital expenditures on an occurrence basis for the three months ended March 31, 2020 were split approximately 25% for investments in the deep waters of the Gulf of Mexico and approximately 75% for investments on the conventional shelf of the Gulf of Mexico. During the three months ended March 31, 2020, the purchase of the remaining 25% interest in the Magnolia field was consummated for approximately $2.0 million.

Net cash used by financing activities for the three months ended March 31, 2020 and 2019 was $33.5 million and $0.4 million, respectively. The net cash used for the three months ended March 31, 2020 included repayment borrowings of $25.0 million under the Credit Agreement and $8.5 million to purchase $27.5 million principal of Senior Second Lien Notes on the open market. Net cash used by financing activities for the three months ended March 31, 2019 was $0.4 million related to debt issuance costs.

Derivative Financial Instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas. During the three months ended March 31, 2020, we entered into derivative contracts for natural gas for a portion of our future production. During the second quarter of 2020, we added the following derivative contracts: (i) Henry Hub cashless collars on 10,000 Mcf per day of production for the period of May 2020 through December 2020 with a floor of $1.75 per Mcf and a ceiling of $2.58 per Mcf; (ii) Henry Hub cashless collars on 20,000 Mcf per day of production for the period of January 2021 through December 2021 with an average floor of $2.17 per Mcf and an average ceiling of $3.00 per Mcf; and (iii) NYMEX crude oil swaps of 1,000 barrels per day for January 2021 through December 2021 at a weighted average price of $41.00 per barrel. See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Asset Retirement Obligations. Each quarter, we review and revise our ARO estimates. Our ARO as of March 31, 2020 and December 31, 2019 were $364.1 million and $355.6 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, 2019 for additional information.

Income Taxes. We do not expect to make any significant income tax payments during 2020 and we expect to collect the income tax receivable of $1.9 million during 2020. See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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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. During the first quarter 2020, we significantly reduced our 2020 capital expenditure budget in response to the unprecedented decline in oil prices. The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

	Three Months Ended March 31,
	2020		2019
Exploration (1)	$	1,206	$	4,251
Development (1)		7,180		17,269
Magnolia acquisition		2,002		—
Seismic and other		1,156		9,113
Investments in oil and gas property/equipment	$	11,544	$	30,633

(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):

	Three Months Ended March 31,
	2020		2019
Conventional shelf	$	6,322	$	6,079
Deepwater		2,064		15,441
Exploration and development capital expenditures	$	8,386	$	21,520

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments to report payments related to capital expenditures.

Our capital expenditures for the three months ended March 31, 2020 were financed by cash flow from operations and cash on hand.

Drilling Activity

During the three months ended March 31, 2020, we drilled the East Cameron 349 B-1 well (Cota) to target depth. We expect initial production to be in the first half of 2021, subject to completion of certain infrastructure and the level of commodity prices. The Cota well is in the Joint Venture Drilling Program. We did not drill any dry holes during the three months ended March 31, 2020.

Offshore Lease Awards

During the three months ended March 31, 2020, we were the apparent high bidder on two blocks in the Gulf of Mexico Lease Sale 254 held by the BOEM on March 18, ~~2022.~~2020. We are the apparent high bidder on one deepwater block, Garden Bank 782, and one shallow water block, Eugene Island Area South block 345. The two blocks cover a total of approximately 10,760 acres and we will pay $0.7 million combined for a 100% working interest if awarded.

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Debt

Credit Agreement. As of March 31, ~~2019, we had $21.0 million~~2020, borrowings outstanding under the Credit Agreement ~~and $8.1~~were $80.0 million ofand letters of credit issued under the Credit ~~Agreement.~~Agreement were $5.8 million. During the three months ended March 31, ~~2019, we did not have any additional borrowings or repayments under the Credit Agreement.~~2020, a repayment of $25.0 million was made. Availability under our Credit Agreement as of March 31, ~~2019~~2020 was ~~$220.9~~$164.2 million. As of June 17, 2020, following the borrowing base retermination and the recent Senior Second Lien Note purchases, availability under the Credit Agreement was $128.9 million and we had $80.0 million of borrowings outstanding under the Credit Agreement. The Credit Agreement matures on October 18, 2022.

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, which was initially set at $250.0 million and was reduced to $215.0 million in June 2020. The next redetermination will occur in the fall of 2020. Generally, we must be in compliance with the ~~next redetermination to be completed by May 15, 2019. Any redetermination by our lenders to change our borrowing base will result~~covenants in ~~a similar change in the availability under~~ our Credit ~~Agreement. The~~Agreement in order to access borrowings under the Credit ~~Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.~~Agreement.

We currently have six lenders under our Credit ~~Agreement, with commitments ranging from $25.0 million to $62.5 million for the current borrowing base.~~Agreement. While we ~~have~~do not ~~experienced, nor do we~~ anticipate any difficulties in obtaining funding from any of these lenders as of the date of the filing of this Quarterly Report, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position. See Financial Statements – Note 2 –Long-Term Debt and –Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.

Senior Second Lien Notes. As of March 31, ~~2019,~~2020, we had outstanding ~~$625.0~~$597.5 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023. ~~The~~During the three months ended March 31, 2020, we purchased $27.5 million in principal of our outstanding Senior Second Lien Notes ~~are secured by a second-priority lien~~in the open market for $8.5 million. Subsequent to March 31, 2020, we purchased an additional $45.1 million in outstanding notes on ~~all of our assets that are secured under~~ the ~~Credit Agreement.~~open market for $15.3 million. See Financial Statements – Note 2 ~~–Long-Term~~– Long-Term Debtand–Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.

Debt Covenants. The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of March 31, ~~2019.~~2020. See Financial Statements – Note 2 – Long-Term Debt and–Note 12– Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.

~~BOEM~~

Uncertainties

Bureau of Ocean Energy Management (“BOEM”) Matters. 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 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 ~~2019~~2020 as of the filing date of this Form ~~10-Q.~~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.

~~Cash Flow and Working Capital.~~ Net cash provided by operating activities for the three months ended March 31, 2019 and 2018 was $84.8 million and $75.0 million, respectively. Our combined average realized sales price per Boe decreased 4.0% for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, which caused total revenues to decrease $8.0 million. Production volumes decreased by 9.8% primarily from increases in downtime, which caused revenues to decrease by $9.8 million. In addition, operating expenses impacting operating cash flows increased by $8.3 million primarily for workover and facility projects.

Other items affecting operating cash flows was an increase of $44.6 million for the three months ended March 31, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to $19.1 million for the three months ended March 31, 2018. ARO settlements were $0.3 million for the three months ended March 31, 2019, which decreased from $7.0 million for the three months ended March 31, 2018. During the three months ended March 31, 2019, cash derivative receipts, net, were $11.9 million primarily due to derivative oil contracts. Working capital items accounted for the balance of the change in net cash provided by operating activities.

Net cash used in investing activities for the three months ended March 31, 2019 and 2018 was $31.6 million and $41.3 million, respectively, which represents our investments in oil and gas properties and equipment. The majority of our capital expenditures for the three months ended March 31, 2019 were for investments in the deep waters of the Gulf of Mexico and, to a lesser extent, on the conventional shelf of the Gulf of Mexico. There were no material acquisitions or asset sales in the three months ended March 31, 2019 and a deposit of $3.0 million was made during the three months ended March 31, 2018 related to the Heidelberg acquisition consummated in April 2018.

Net cash used by financing activities for the three months ended March 31, 2019 and 2018, respectively was $0.4 million and $2.1 million, respectively. The net cash used for the three months ended March 31, 2018 was for interest payments on certain debt reported as financing activities under ASC 470-60.

~~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 2018, we entered into derivative contracts for crude oil and natural gas for a portion of our future production. See ~~Financial Statements – Note 6 – Derivative Financial Instruments~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

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Insurance Coverage

Insurance Coverage. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $30.0 million. Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention. The operational and named windstorm coverages are effective for one year beginning June 1, ~~2018.~~2020. 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, ~~2019~~2020 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 $150.0 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, ~~2019,~~2020, and ~~we expect to renew~~ our Energy Package effective on June 1, ~~2019,~~2020, 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.

~~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. During the three months ended March 31, 2018, we received reimbursement of capital expenditures from Monza for projects in the JV Drilling Program, some of which had incurred costs during 2017. These reimbursements related to 2017 are reported in a separate line in the table below. The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

Contractual Obligations

Three Months Ended

March 31,

2019

2018

Exploration ⁽¹⁾

$
4,251

$
2,718

Development ⁽¹⁾

17,269

30,907

Reimbursement from Monza for 2017 expenditures

—

(14,075
)
Seismic and other

9,113

1,567

Investments in oil and gas property/equipment

$
30,633

$
21,117

~~(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):~~

Three Months Ended

March 31,

2019

2018

Conventional shelf

$
6,079

$
24,284

Deepwater

15,441

9,341

Exploration and development capital expenditures

$
21,520

$
33,625

~~The capital expenditures reported in the above two tables are included within~~ ~~Oil and natural gas properties and other, net~~ on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments to report payments related to capital expenditures.

~~Our capital expenditures for the three months ended March 31, 2019 were financed by cash flow from operations and cash on hand.~~

During the three months ended March 31, 2019, we completed one of two target zones for the Virgo A-13 well, which began producing during March 2019. The other target zone for the Virgo A-13 well was completed in April 2019. The Virgo A-13 well is in the JV Drilling Program. During the three months ended March 31, 2018, we completed two wells. We did not drill any dry holes in either period presented.

~~Exploration/Development Activities.~~ ~~As of April 15, 2019, we were drilling on the South Timbalier 320 A-3 and the Mississippi Canyon 800 SS2 wells, both of which are in the JV Drilling Program.~~

~~Offshore Lease Awards.~~ During the three months ended March 31, 2019, we were the apparent high bidder on 15 blocks (eight deepwater and seven shallow water) in the Gulf of Mexico Lease Sale 252 held by the BOEM on March 20, 2019. These 15 blocks cover approximately 73,500 acres and, if awarded, we will pay approximately $3.5 million for all of the awarded leases combined, which reflects a 100% working interest in the acreage. As of the filing date of this Form 10-Q, we have received official notice of being awarded one of the leases and we expect to receive official notice related to the other leases within 90 days of the lease sale date.

~~Capital Expenditure Budget.~~ Our current 2019 capital expenditure forecast is approximately $120 million, which excludes potential acquisitions. The forecast incorporates the shared investments in certain wells included in the JV Drilling Program. ~~We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.~~

~~Income Taxes. As of March 31, 2019, we had current income taxes receivable of $54.1 million.~~ ~~For 2019, we~~ ~~do not expect to make any significant income tax payments. See~~ ~~Financial Statements – Note 8 –Income Taxes~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Asset Retirement Obligations~~. Each quarter, we review and revise our ARO estimates. Our ARO at March 31, 2019 and December 31, 2018 were $314.2 million and $310.1 million, respectively. Our plans include spending $24.0 million in 2019 for ARO compared to $28.6 million spent on ARO in 2018. 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, 2018 for additional information.~~

~~Contractual Obligations~~. Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt,~~and~~Note 5 – Asset Retirement Obligations andNote 12, Subsequent Events underPart I, Item 1 of this Form 10-Q. As of March 31, ~~2019,~~2020, there were no drilling rig ~~commitments, excluding ARO drilling rig commitments, were approximately $9.2 million, which was approximately the same as the amount as of December 31, 2018.~~commitments. Except for scheduled utilization, other contractual obligations as of March 31, ~~2019~~2020 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, ~~2018.~~2019.

Critical Accounting Policies

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2019. See Financial Statements -– Note 1 -– Basis of Presentation under Part 1, Item 1of this Form 10-Q for additional information.

Recent Accounting Pronouncements

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about the types of market risks for the three months ended March 31, ~~2019~~2020 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, ~~2018. As such,~~2019. However, the declines in crude oil and natural gas prices have caused, and could continue to cause significant financial impacts to us. See the Liquidity section in Item II above for a discussion on the possible effects. In addition, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~ 2019.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and ~~could~~sustain current prices would have significant impacts on our business in the future. During ~~2018,~~2020, we entered into derivative ~~crude oil~~natural gas contracts related to a portion of our estimated future production. We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments. Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements. See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk. As of March 31, ~~2019,~~2020, we had ~~$21.0~~$80.0 million borrowings outstanding under our Credit Agreement and were subject to the variable London Interbank Offered Rate and the Applicable Margin. We did not have any derivative instruments related to interest rates.

Item 4. ~~Contr~~~~ols~~Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO have each concluded that as of March 31, ~~2019,~~2020, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended March 31, ~~2019,~~2020, 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 1011 –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

~~Investors should carefully consider~~

The COVID-19 pandemic has affected, and may continue to materially adversely affect, our industry, business, financial condition or results of operations.

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the ~~risk factors included under Part I, Item 1A,~~ ~~Risk Factors,~~oil and gas industry. The COVID-19 outbreak and the responsive actions to limit the spread of the virus have significantly reduced global economic activity, resulting in a decline in the demand for oil, natural gas, and other commodities. These economic consequences have been a primary cause of the significant supply-and-demand imbalance for oil. The current supply-and-demand imbalance and significantly lower oil pricing may continue to affect us, constraining our ability to store and move production to downstream markets, or affecting future decisions to delay or curtail development activity or temporarily shut-in production which could further reduce cash flow.

The extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on the nature, spread and duration of the disease, the responsive actions to contain its spread or address its effects, its effect on the demand for oil and natural gas, the timing and severity of the related consequences on commodity prices and the economy more generally, including any recession resulting from the pandemic, among other things. Any extended period of depressed commodity prices or general economic disruption as a result of the pandemic would adversely affect our business, financial conditions and results of operations. In addition, the COVID-19 pandemic has heightened the other risks and uncertainties set forth in the “Risk Factors” section of our Annual Report on Form 10-K for the year ~~ended December 31, 2018,~~2019.

We will likely incur greater costs to bring production associated with our shut-in wells back online, and are unable to predict the production levels of such wells once brought back online.

The significant supply/demand balance for oil materially decreased global crude oil prices in the first quarter of 2020 and generated a surplus of oil. This significant surplus created a saturation of storage and crude storage constraints, which led us to shut-in production in some of our oil-weighted properties due to the lack of availability and capacity of processing, gathering, storing and transportation systems. We will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in. Such factors could adversely affect our financial condition and results of operations.

Investors should carefully consider these risk factors together with all of the other information included in this document, in our Annual Report on Form 10-K for the year 2019, and in our other public filings, press releases and discussions with our management.

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Item 5. Other Information

On June 17, 2020,the lenders under the Credit Agreement completed their semi-annual borrowing base redetermination and entered into the Third Amendment and Waiver to the Credit Agreement. Although the Company had not violated any covenants, the Third Amendment provides less stringent covenant requirements given the recent changes in the oil and gas markets. The ~~potential effects of crude oil prices are discussed~~Third Amendment includes the following changes, among other things, to the Credit Agreement:

The borrowing base under ~~Part I, Item 1A,~~ ~~Risk Factors,~~ ~~in our Annual Report on Form 10-K for~~ the ~~year~~Credit Agreement was reduced from $250.0 million to $215.0 million.

Increase the interest rate margin by 25 basis points.

Amend the financial covenants as follows:

From the period ended June 30, 2020 through the period ended December 31, ~~2018 and also discussed in~~2021, the ~~Part I, Item 2,~~ ~~Management’s Discussion and Analysis~~Company will not be required to comply with the Leverage Ratio covenant.

During the Waiver Period, the Company will be required to maintain a 2.00 to 1.00 ratio limit of ~~Financial Condition~~ ~~and~~ ~~Results~~first lien debt outstanding under the Credit Agreement on the last day of ~~Operations~~ in the ~~Overview~~ ~~section of this Form 10-Q.~~

~~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 Annual Report on Form 10-K~~most recent quarter to EBITDAX for the ~~year ended December 31, 2018.~~trailing four quarters.

Increase the requirement to provide first priority liens on properties constituting at least 85% of total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement to 90%.

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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 ~~3.2~~3.1 of the Company’s ~~Registration Statement~~Current Report on Form ~~S-1,~~8-K, filed ~~May 3, 2004~~March 22, 2019 (File No. ~~333-115103)~~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))
~~3.5~~
10.1*		~~Second~~Third Amendment and Waiver to Sixth Amended and Restated ~~Bylaws of~~Credit Agreement, dated June 17, 2020, by and among W&T Offshore, Inc. ~~(Incorporated by reference to Exhibit 3.1 of~~, Toronto Dominion (Texas) LLC, as agent and the ~~Company’s Current Report on Form 8-K, filed March 22, 2019 (File No. 001-32414))~~various agents and lenders party thereto.

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*		XBRL Instance Document.

101.SCH*		XBRL Schema Document.

101.CAL*		XBRL Calculation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

101.LAB*		XBRL Label Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

Filed or ~~Furnished~~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 ~~May 2, 2019.~~June 23, 2020.


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

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

Nine Greenway Plaza, Suite 300, Houston, Texas	77046-0908
(Address of principal executive offices)	(Zip Code)


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

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

	Three Months Ended
	March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Operating activities:
Net (loss) income	$	(47,761	)	$	27,640
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Net income (loss)							$	65,980		$	(47,761	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		33,766			38,081			39,126			33,766
Amortization of debt items and other items		1,152			466			1,625			1,152
Share-based compensation		(78	)		1,219			1,048			(78	)
Derivative loss		48,886			—
Derivative (gain) loss								(61,912	)		48,886
Cash receipts on derivative settlements, net		11,948			—			4,404			11,948
Deferred income taxes		172			109
Gain on purchase of debt								(18,501	)		—
Deferred Income taxes								6,499			172
Changes in operating assets and liabilities:
Oil and natural gas receivables		6,496			501			21,954			6,496
Joint interest receivables		(2,986	)		1,919			7,123			(2,986	)
Prepaid expenses and other assets		(4,269	)		(6,391	)		11,011			(4,269	)
Asset retirement obligation settlements		(254	)		(7,022	)		(249	)		(254	)
Cash advances from JV partners		44,644			19,147			13,006			44,644
Accounts payable, accrued liabilities and other		(6,871	)		(688	)		(6,790	)		(6,871	)
Net cash provided by operating activities		84,845			74,981			84,324			84,845
Investing activities:
Investment in oil and natural gas properties and equipment		(31,581	)		(38,271	)		(33,575	)		(31,581	)
Deposit for acquisition		—			(3,000	)
Acquisition of property interest								(2,002	)		—
Purchases of furniture, fixtures and other								(70	)		—
Net cash used in investing activities		(31,581	)		(41,271	)		(35,647	)		(31,581	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		—			(2,057	)
Debt issuance costs		(441	)		—
Repayments on credit facility								(25,000	)		—
Purchase of Senior Second Lien Notes								(8,536	)		—
Debt issuance costs and other								—			(441	)
Net cash used in financing activities		(441	)		(2,057	)		(33,536	)		(441	)
Increase in cash and cash equivalents		52,823			31,653			15,141			52,823
Cash and cash equivalents, beginning of period		33,293			99,058			32,433			33,293
Cash and cash equivalents, end of period	$	86,116		$	130,711		$	47,574		$	86,116

	March 31, 2019
ROU:
Prepaid expenses and other current assets:	$	1,095
Other assets		3,856
Total ROU	$	4,951

Lease liability:
Accrued liabilities	$	1,095
Other liabilities		3,856
Total lease liability	$	4,951

Lease incentives:
Prepaid expenses and other current assets (contra-asset)	$	(213	)
Other assets (contra-asset)		(795	)
Total lease incentives	$	(1,008	)

	March 31,		December 31,		March 31, 2020		December 31, 2019
	2019		2018
Derivative assets ⁽¹⁾	$	16,959	$	60,687
Derivatives - current (1)					$	64,039	$	7,266
Unamortized bond/insurance premiums		4,944		5,197		4,478		4,357
Prepaid deposits related to royalties		8,871		8,872		7,555		7,980
Prepayment to vendors						1,825		10,202
Other		3,353		1,650		761		886
Prepaid expenses and other assets	$	34,127	$	76,406	$	78,658	$	30,691

	Common Stock Outstanding				Additional Paid-In			Retained			Treasury Stock					Total Shareholders’			Common Stock Outstanding				Additional Paid-In			Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital			Deficit			Shares		Value			Deficit			Shares		Value		Capital			Deficit			Shares		Value			Deficit
Balances at December 31, 2018		140,644	$	1	$	545,705		$	(846,335	)		2,869	$	(24,167	)	$	(324,796	)
Balances, December 31, 2018																				140,644	$	1	$	545,705		$	(846,335	)		2,869	$	(24,167	)	$	(324,796	)
Share-based compensation		—		—		(78	)		—			—		—			(78	)		—		—		(78	)		—			—		—			(78	)
Net loss		—		—		—			(47,761	)		—		—			(47,761	)		—		—		—			(47,761	)		—		—			(47,761	)
Balances at March 31, 2019		140,644	$	1	$	545,627		$	(894,096	)		2,869	$	(24,167	)	$	(372,635	)
Balances, March 31, 2019																				140,644	$	1	$	545,627		$	(894,096	)		2,869	$	(24,167	)	$	(372,635	)

	March 31, 2019				December 31, 2018				March 31, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Credit Agreement	$	21,000	$	21,000	$	21,000	$	21,000	$	80,000	$	80,000	$	105,000	$	105,000
Senior Second Lien Notes		613,005		623,256		612,535		546,875		588,058		136,421		614,533		597,188

Balance, December 31, 2018	$	310,137
Balances, December 31, 2019				$	355,594
Liabilities settled		(254	)		(249	)
Accretion of discount		4,588			5,716
Liabilities incurred		44
Liabilities incurred, including acquisitions					2,704
Revisions of estimated liabilities		(353	)		335
Balance, March 31, 2019		314,162
Balances, March 31, 2020					364,100
Less current portion		24,799			2,803
Long-term	$	289,363		$	361,297

Crude Oil: Swap, Priced off WTI (NYMEX)
Termination Period	Notional Quantity (Bbls/day) ⁽¹⁾		Notional Quantity (Bbls) ⁽¹⁾		Strike Price
May 2020		1,500		640,500	$	60.80
May 2020		5,000		2,135,000		61.00
May 2020		3,500		1,494,500		60.85

Crude Oil: Open Swap Contracts, Priced off WTI (NYMEX)
Period	Notional Quantity (Bbls/day) (1)	Notional Quantity (Bbls) (1)	Weighted Average Strike Price
Apr 2020 - May 2020	10,000	610,000	$ 60.92

Crude Oil: Open Call Contracts - Bought, Priced off WTI (NYMEX)
Period	Notional Quantity (Bbls/day) (1)	Notional Quantity (Bbls) (1)	Strike Price
Apr 2020 - May 2020	10,000	610,000	$ 61.00

June 2020 - Dec. 2020	10,000	2,140,000	$ 67.50

Crude Oil: Open Collar Contracts - Priced off WTI (NYMEX)
Period	Notional Quantity (Bbls/day) (1)	Notional Quantity (Bbls) (1)	Put Option Weighted Strike Price (Bought)	Call Option Weighted Strike Price (Sold)
June 2020 - Dec. 2020	10,000	2,140,000	$ 45.00	$ 63.51

Natural Gas: Open Collar Contracts, Priced off Henry Hub (NYMEX)
Period	Notional Quantity (MMBtu/day) (2)	Notional Quantity (MMBtu) (2)	Put Option Strike Price (Bought)	Call Option Strike Price (Sold)
May 2020 - Dec. 2022	40,000	39,000,000	$ 1.83	$ 3.00

Natural Gas: Open Call Contracts, Bought, Priced off Henry Hub (NYMEX)
Period	Notional Quantity (MMBtu/day) (2)	Notional Quantity (MMBtu) (2)	Strike Price
May 2020 - Dec. 2022	40,000	39,000,000	$ 3.00

	Three Months Ended March 31,
	2020		2019
Cash receipts on derivative settlements, net	$	4,404	$	11,948

	March 31,		December 31,		March 31, 2020		December 31, 2019
	2019		2018
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Derivative assets		4,169		21,275
Appeal bond deposits		6,925		6,925
Right-of-Use assets (Note 7)					$	12,745	$	7,936
Unamortized debt issuance costs		4,511		4,773		3,458		3,798
Investment in White Cap, LLC		2,546		2,586		2,917		2,590
Unamortized brokerage fee for Monza		3,746		2,277		2,881		3,423
Proportional consolidation of Monza's other assets (Note 4)		3,299		3,275		4,222		5,308
Derivative assets						2,847		2,653
Appeal bond deposits						—		6,925
Other		4,309		936		1,014		814
Total other assets (long-term)	$	79,005	$	91,547	$	30,084	$	33,447

	March 31, 2020		December 31, 2019
ROU assets	$	12,745	$	7,936

Lease liability:
Accrued liabilities	$	2,472	$	2,716
Other liabilities		9,581		4,419
Total lease liability	$	12,053	$	7,135

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2018		3,355,917		$	3.90
Forfeited ⁽¹⁾		(856,718	)		2.77
Nonvested, March 31, 2019		2,499,199			4.28

	Restricted Stock Units		Restricted Stock Units
2019		1,579,140
2020		920,059		803,995
2021				788,082
Total		2,499,199		1,592,077

	Restricted Shares		Restricted Shares
2019		105,012
2020		62,972		78,424
2021		13,848		29,300
2022				15,456
Total		181,832		123,180