W&T OFFSHORE INC (Form: 10-Q, Received: 08/01/2019 16:37:43)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2019

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

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

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

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

(713) 626-8525

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

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

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

As of July 31, 2019, there were 140,690,393 shares outstanding of the registrant’s common stock, par value $0.00001.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I –FINANCIAL INFORMATION

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	2
	Condensed Consolidated Statements of Changes in Shareholders’ Deficit for the Three and Six Months Ended June 30, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	27

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 6.	Exhibits	28

SIGNATURE		29

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

	June 30,			December 31,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	65,709		$	33,293
Receivables:
Oil and natural gas sales		41,812			47,804
Joint interest and other, net		38,756			14,634
Income taxes		54,116			54,076
Total receivables		134,684			116,514
Prepaid expenses and other assets (Note 1)		53,101			76,406
Total current assets		253,494			226,213

Oil and natural gas properties and other, net - at cost (Note 1)		524,512			515,421
Restricted deposits for asset retirement obligations		16,220			15,685
Other assets (Note 1)		73,577			91,547
Total assets	$	867,803		$	848,866
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	97,893		$	82,067
Undistributed oil and natural gas proceeds		27,118			28,995
Advances from joint interest partners		39,154			20,627
Asset retirement obligations		26,335			24,994
Accrued liabilities (Note 1)		19,494			29,611
Total current liabilities		209,994			186,294

Long-term debt (Note 2)		634,415			633,535
Asset retirement obligations, less current portion		296,996			285,143
Other liabilities (Note 1)		61,385			68,690
Commitments and contingencies (Note 12)		—			—
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; 143,560 issued and 140,690 outstanding on June 30, 2019 and 143,513 issued and 140,644 outstanding on December 31, 2018		1			1
Additional paid-in capital		546,886			545,705
Retained deficit		(857,707	)		(846,335	)
Treasury stock, at cost; 2,869 shares for both dates presented		(24,167	)		(24,167	)
Total shareholders’ deficit		(334,987	)		(324,796	)
Total liabilities and shareholders’ deficit	$	867,803		$	848,866

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
Revenues:
Oil	$	109,195		$	116,618	$	195,898		$	213,924
NGLs		4,640			8,734		11,088			18,394
Natural gas		19,567			22,977		41,405			48,844
Other		1,299			1,283		2,390			2,663
Total revenues		134,701			149,612		250,781			283,825
Operating costs and expenses:
Lease operating expenses		40,341			35,582		83,797			72,425
Production taxes		317			439		733			894
Gathering and transportation		7,068			4,928		13,491			9,985
Depreciation, depletion, amortization and accretion		38,073			39,757		71,839			77,838
General and administrative expenses		13,328			14,220		27,437			29,258
Derivative (gain) loss		(1,805	)		6,219		47,081			6,219
Total costs and expenses		97,322			101,145		244,378			196,619
Operating income		37,379			48,467		6,403			87,206
Interest expense, net		12,207			11,786		28,489			22,748
Other expense, net		478			486		809			514
Income (loss) before income tax (benefit) expense		24,694			36,195		(22,895	)		63,944
Income tax (benefit) expense		(11,695	)		112		(11,523	)		221
Net income (loss)	$	36,389		$	36,083	$	(11,372	)	$	63,723
Basic and diluted earnings (loss) per common share	$	0.25		$	0.25	$	(0.08	)	$	0.44

See Notes to Condensed Consolidated Financial Statements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)

	Common Stock Outstanding				Additional Paid-In		Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital		Deficit			Shares		Value			Deficit
Balances, March 31, 2019		140,644	$	1	$	545,627	$	(894,096	)		2,869	$	(24,167	)	$	(372,635	)
Share-based compensation		—		—		1,259		—			—		—			1,259
Stock Issued		46		—		—		—			—		—			—
Net income		—		—		—		36,389			—		—			36,389
Balances, June 30, 2019		140,690	$	1	$	546,886	$	(857,707	)		2,869	$	(24,167	)	$	(334,987	)

	Common Stock Outstanding				Additional Paid-In			Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital			Deficit			Shares		Value			Deficit
Balances, March 31, 2018		139,091	$	1	$	547,039		$	(1,067,522	)		2,869	$	(24,167	)	$	(544,649	)
Share-based compensation		—		—		1,215			—			—		—			1,215
Stock Issued		63		—		—			—			—		—			—
RSUs surrendered for payroll taxes ⁽¹⁾		—		—		(58	)		—			—		—			(58	)
Net income		—		—		—			36,083			—		—			36,083
Balances, June 30, 2018		139,154	$	1	$	548,196		$	(1,031,439	)		2,869	$	(24,167	)	$	(507,409	)

	Common Stock Outstanding				Additional Paid-In		Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital		Deficit			Shares		Value			Deficit
Balances, December 31, 2018		140,644	$	1	$	545,705	$	(846,335	)		2,869	$	(24,167	)	$	(324,796	)
Share-based compensation		—		—		1,181		—			—		—			1,181
Stock Issued		46		—		—		—			—		—			—
Net loss		—		—		—		(11,372	)		—		—			(11,372	)
Balances, June 30, 2019		140,690	$	1	$	546,886	$	(857,707	)		2,869	$	(24,167	)	$	(334,987	)

	Common Stock Outstanding				Additional Paid-In			Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital			Deficit			Shares		Value			Deficit
Balances, December 31, 2017		139,091	$	1	$	545,820		$	(1,095,162	)		2,869	$	(24,167	)	$	(573,508	)
Share-based compensation		—		—		2,434			—			—		—			2,434
Stock Issued		63		—		—			—			—		—			—
RSUs surrendered for payroll taxes ⁽¹⁾		—		—		(58	)		—			—		—			(58	)
Net income		—		—		—			63,723			—		—			63,723
Balances, June 30, 2018		139,154	$	1	$	548,196		$	(1,031,439	)		2,869	$	(24,167	)	$	(507,409	)

(1) RSUs defined in Note 9.

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2019			2018
Operating activities:
Net (loss) income	$	(11,372	)	$	63,723
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		71,839			77,838
Amortization of debt items and other items		2,485			1,126
Share-based compensation		1,181			2,434
Derivative loss		47,081			6,219
Cash receipts (payments) on derivative settlements, net		12,792			(1,149	)
Deferred income taxes		(11,523	)		221
Changes in operating assets and liabilities:
Oil and natural gas receivables		5,992			(6,630	)
Joint interest receivables		(24,162	)		251
Prepaid expenses and other assets		(8,134	)		(14,323	)
Asset retirement obligation settlements		(2,641	)		(12,124	)
Cash advances from JV partners		18,527			(3,805	)
Accounts payable, accrued liabilities and other		4,251			1,411
Net cash provided by operating activities		106,316			115,192
Investing activities:
Investment in oil and natural gas properties and equipment		(63,149	)		(61,133	)
Deposit/acquisition of property interest		(10,000	)		(16,617	)
Net cash used in investing activities		(73,149	)		(77,750	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		—			(4,114	)
Payment of interest on 2nd Lien PIK Toggle Notes		—			(2,920	)
Debt issuance costs and other		(751	)		(26	)
Net cash used in financing activities		(751	)		(7,060	)
Increase in cash and cash equivalents		32,416			30,382
Cash and cash equivalents, beginning of period		33,293			99,058
Cash and cash equivalents, end of period	$	65,709		$	129,440

See Notes to Condensed Consolidated Financial Statements.

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

1.	Basis of Presentation

Operations. W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Our interests in fields, leases, structures and equipment are primarily owned by the Company and its 100%-owned subsidiary, W & T Energy VI, LLC, and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 4.

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

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

Leases. In February 2016, Accounting Standards Update 2016-02, Leases (Topic 842) (“ASU 2016-02”) was issued requiring an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases. The classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. ASU 2016-02 also requires certain quantitative and qualitative disclosures about leasing arrangements. Leases acquired to explore for or extract oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of this standard’s update. ASU 2016-02 was effective for us in the first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized an ROU asset and a lease liability with no retained earnings impact. See Note 8 for additional information.

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

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

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current presentation as follows: In the Condensed Consolidated Statements of Operations, interest income was reclassified from Other expense, net to Interest expense, net, which did not change Income (loss) before income tax (benefit) expense. In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net cash provided by operating activities and Net cash used in investing activities sections, of which did not change the total amounts previous reported. The adjustments did not affect the Condensed Consolidated Balance Sheets.

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

	June 30,		December 31,
	2019		2018
Derivative assets (1)	$	22,089	$	60,687
Deposit for acquisition		10,000		—
Unamortized bond/insurance premiums		7,108		5,197
Prepaid deposits related to royalties		8,824		8,872
Other		5,080		1,650
Prepaid expenses and other assets	$	53,101	$	76,406

(1)

Includes closed contracts which have not yet settled.

Oil and Natural Gas Properties and Other, Net – 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):

	June 30,		December 31,
	2019		2018
Oil and natural gas properties and equipment	$	8,241,499	$	8,169,871
Furniture, fixtures and other		20,228		20,228
Total property and equipment		8,261,727		8,190,099
Less accumulated depreciation, depletion and amortization		7,737,215		7,674,678
Oil and natural gas properties and other, net	$	524,512	$	515,421

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

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

	June 30,		December 31,
	2019		2018
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Derivative assets		—		21,275
Appeal bond deposits		6,925		6,925
Unamortized debt issuance costs		4,478		4,773
Investment in White Cap, LLC		2,633		2,586
Unamortized brokerage fee for Monza		3,268		2,277
Proportional consolidation of Monza's other assets (Note 4)		2,251		3,275
Other		4,522		936
Total other assets (long-term)	$	73,577	$	91,547

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

	June 30,		December 31,
	2019		2018
Accrued interest	$	10,179	$	12,385
Accrued salaries/payroll taxes/benefits		2,627		2,320
Incentive compensation plans		1,514		10,817
Litigation accruals		3,673		3,673
Other		1,501		416
Total accrued liabilities	$	19,494	$	29,611

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

	June 30,		December 31,
	2019		2018
Apache lawsuit	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		—		11,523
Dispute related to royalty deductions		4,687		4,687
Dispute related to royalty-in-kind		2,197		2,135
Other		5,001		845
Total other liabilities (long-term)	$	61,385	$	68,690

Recent Accounting Developments.

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”) and subsequently issued additional guidance on this topic. 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.

In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”) and subsequently issued additional guidance on this topic. The amendments in ASU 2017-12 require an entity to present the earnings effect of the hedging instrument in the same income statement line in which the earning effect of the hedged item is reported. This presentation enables users of financial statements to better understand the results and costs of an entity’s hedging program. Also, relative to current GAAP, this approach simplifies the financial statement reporting for qualifying hedging relationships. ASU 2017-12 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020. Early adoption is permitted, including adoption in an interim period. As we do not designate our commodity derivative instruments as qualifying hedging instruments, our assessment is this amendment will not impact the presentation of the changes in fair values of our commodity derivative instruments on our financial statements.

The SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification, which revised Regulation S-X, Rule 3-04, Changes in Stockholders’ Equity and Noncontrolling Interests. The new requirement for registrants is to include a reconciliation of changes in stockholders’ equity (deficit) in interim periods for each period that for which a statement of operations is required to be filed. The new requirement became effective for us for the quarter ended March 31, 2019.

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

2.	Long-Term Debt

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

	June 30,			December 31,
	2019			2018
Credit Agreement borrowings	$	21,000		$	21,000

Senior Second Lien Notes:
Principal		625,000			625,000
Unamortized debt issuance costs		(11,585	)		(12,465	)
Total Senior Second Lien Notes		613,415			612,535

Total long-term debt	$	634,415		$	633,535

Credit Agreement

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (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:

•

The borrowing base and lending commitment was $250.0 million as of the filing date of this Form 10-Q.

•

Letters of credit may be issued in amounts up to $30.0 million, provided availability under the Credit Agreement exists. As of June 30, 2019, and December 31, 2018, we had $7.2 million and $9.6 million, respectively, of letters of credit issued and outstanding under the Credit Agreement.

•

The Leverage Ratio is limited to 3.25 to 1.00 for the quarters ending June 30, 2019 and September 30, 2019; and 3.00 to 1.00 for the quarters ending December 31, 2019 and thereafter. In the event of a Material Acquisition, the Leverage Ratio limit is 3.50 to 1.00 for the two quarters following a Material Acquisition.

•

The Current Ratio must be maintained at greater than 1.00 to 1.00.

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on or before May 15 and November 14 each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company. The borrowing base has not changed from the initial amount. 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. The Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal property. The annualized interest rate on borrowings outstanding for the six months ended June 30, 2019 was 5.1%, which excludes debt issuance costs, commitment fees and other fees.

9.75% Senior Second Lien Notes Due 2023

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

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. These covenants are subject to exceptions and qualifications set forth in the Indenture. In addition, most of the above described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Senior Second Lien Notes an investment grade rating and no default exists with respect to the Senior Second Lien Notes.

Covenants

As of June 30, 2019, we were in compliance with all applicable covenants of the Credit Agreement and the Indenture.

Fair Value Measurements

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

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

3.	Fair Value Measurements

Derivative Financial Instruments

We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our open derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. Our open derivative financial instruments are reported in the Condensed Consolidated Balance Sheets using fair value. See Note 6, Derivative Financial Instruments, for additional information on our derivative financial instruments.

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

	June 30,		December 31,
	2019		2018
Assets:
Derivatives instruments - open contracts	$	20,226	$	74,580

Long-Term Debt

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 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):

	June 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Credit Agreement	$	21,000	$	21,000	$	21,000	$	21,000
Senior Second Lien Notes		613,415		594,725		612,535		546,875

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

4.	Joint Venture Drilling Program

On March 12, 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico. The projects are expected to be completed during the years 2018 through 2020, but some projects may possibly extend into years beyond 2020. W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T, are $361.4 million. The JV Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed upon rates. Any exceptions are approved by the Monza board. W&T is or will be the operator of each well in the JV Drilling Program unless there is a designated third-party operator.

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

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

As of June 30, 2019, members of Monza made partner capital contribution payments to Monza totaling $184.9 million, of which $70.2 million was contributed during the six months ended June 30, 2019. Our net contribution to Monza, reduced by distributions received, as of June 30, 2019 was $57.6 million. W&T may be obligated to fund certain cost overruns, subject to certain exceptions, for the JV Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot be estimated at this time.

Consolidation and Carrying Amounts. Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation. We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interests in the Monza properties. As of June 30, 2019, in the Condensed Consolidated Balance Sheet, we recorded $13.4 million, net, in Oil and natural gas properties and other, net, $2.3 million in Other assets and $3.4 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. As of December 31, 2018, in the Condensed Consolidated Balance Sheet, we recorded $8.8 million, net, in Oil and natural gas properties and other, net, $3.3 million in Other assets and $0.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. For the six months ended June 30, 2019, we recorded $4.0 million in Total revenues and $2.5 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations. For the six months ended June 30, 2018, we recorded $0.5 million in Total revenues, $0.4 million in Operating costs and expenses and $0.2 million in Other (income) expense, net in connection with our proportional interest in Monza’s operations.

Additionally, during the six months ended June 30, 2019, we called on Monza to provide, and received, $80.3 million to fund upcoming JV Drilling Program projects, of which $39.1 million is included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners as of June 30, 2019.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

5.	Asset Retirement Obligations

Our asset retirement obligations (“ARO”) represent the estimated present value of the amount incurred to plug, abandon and remediate our properties at the end of their productive lives.

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

Balances, December 31, 2018	$	310,137
Liabilities settled		(2,641	)
Accretion of discount		9,302
Liabilities incurred		323
Revisions of estimated liabilities		6,210
Balances, June 30, 2019		323,331
Less current portion		26,335
Long-term	$	296,996

6.	Derivative Financial Instruments

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

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

During 2018, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected future production. The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”). The natural gas contracts were based on Henry Hub natural gas prices as quoted off the NYMEX and expired during the second quarter of 2019. The open contracts as of June 30, 2019 are presented in the following tables:

Crude Oil: Swap, Priced off WTI (NYMEX)
Termination Period	Notional Quantity (Bbls/day) ⁽¹⁾	Notional Quantity (Bbls) ⁽¹⁾	Strike Price
May 2020	1,500	504,000	$	60.80
May 2020	5,000	1,680,000		61.00
May 2020	3,500	1,176,000		60.85

(1)

Bbls = Barrels

Crude Oil: Calls - Bought, Priced off WTI (NYMEX)

Termination Period

Notional Quantity

(Bbls/day) ⁽¹⁾

Notional Quantity
(Bbls) ⁽¹⁾

Strike Price

May 2020

10,000

3,360,000

61.00

(1)

Bbls = Barrels

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(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):

	June 30,		December 31,
	2019		2018
Prepaid expenses and other assets	$	22,089	$	60,687
Other assets (non-current)		—		21,275

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 differences in reported amounts.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019		2018
Derivative (gain) loss	$	(1,805	)	$	6,219	$	47,081	$	6,219

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

	Six Months Ended June 30,
	2019		2018
Cash receipts (payments) on derivative settlements, net	$	12,792	$	(1,149	)

7.	Oil and Gas Property Acquisition

On June 26, 2019, we entered into a purchase and sale agreement with ExxonMobil Corporation and certain of their subsidiaries (collectively "ExxonMobil") to acquire their interests in and operatorship of oil and gas producing properties in the eastern region of the Gulf of Mexico ("GOM") offshore Alabama and a related processing facility for $200 million, subject to customary post-effective date adjustments for an effective date of January 1, 2019. The acquisition will be funded from our cash on hand and borrowings under our Credit Agreement at closing date. The transaction includes nine GOM offshore producing fields and an onshore treating facility that are adjacent to existing properties owned and operated by us. The acquisition is expected to close on or about August 30, 2019. As of June 30, 2019, a deposit of $10.0 million was made related to the pending acquisition.

8.	Leases

ASU 2016-02 was effective for us on January 1, 2019 and we adopted the new standard using a modified retrospective approach. Consequently, upon transition, we recognized an ROU asset and a lease liability with no retained earnings impact.

As provided for in subsequent accounting standards updates related to ASU 2016-02, we are applying the following practical expedients which provide elections to:

•

not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option);

•

not reassess whether a contract contains a lease, lease classifications between operating and financing and accounting for initial direct costs related to leases;

•

not reassess certain land easements in existence prior to January 1, 2019;

•

use hindsight in determining the lease term and assessing impairment; and

•

not separate nonlease and lease components.

Based on the results of our implementation process, we identified one operating lease in existence at January 1, 2019 subject to ASU 2016-02, which is our real estate lease for office space in Houston, Texas that terminates in December 2022. In addition, a right-of-way arrangement related to a pipeline was renewed and paid for during the six months ended June 30, 2019 and was recorded as an ROU. The term of the right-of-way arrangement is ten years. During the six months ended June 30, 2019, we incurred short-term lease costs related to drilling rigs of $11.9 million, net to our interest, of which the majority of such costs were recorded within Oil and natural gas properties, net, on the Condensed Consolidated Balance Sheet. In exercising the practical expedient, we did not separate nonlease and lease components for these short-term leases. We identified no finance leases.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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Houston Office Lease. Minimum future lease payments due under the lease as of June 30, 2019 are as follows: 2019 - $0.8 million; 2020 - $1.6 million; 2021 - $1.6 million and 2022 - $1.6 million. Expense recognized related to the Houston office lease for the six months ended June 30, 2019 and 2018 was $1.3 million during each period.

As of June 30, 2019, we recorded an ROU asset and a lease liability using a discount rate of 9.75%. The discount rate (or incremental borrowing rate) was determined using the interest rate of recently issued debt instruments that were issued at par and for a similar term as the term of our lease for the office space in Houston.

Amounts related to leases recorded within our Condensed Consolidated Balance Sheet are as follows (in thousands):

	June 30, 2019
ROU:
Prepaid expenses and other current assets:	$	1,132
Other assets		4,328
Total ROU	$	5,460

Lease liability:
Accrued liabilities	$	1,133
Other liabilities		3,557
Total lease liability	$	4,690

Lease incentives:
Prepaid expenses and other current assets (contra-asset)	$	(223	)
Other assets (contra-asset)		(734	)
Total lease incentives	$	(957	)

The adoption of the new standard did not impact our Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows or Condensed Consolidated Statements of Changes in Shareholders’ Deficit.

9.	Share-Based Compensation and Cash-Based Incentive Compensation

Awards to Employees. In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended from time to time, the “Plan”) was approved by our shareholders. During 2019, 2018 and 2017, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees. RSUs are a long-term compensation component, and are subject to satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period based on the results achieved. In addition to share-based awards, the Company may grant to its employees cash-based incentive awards under the Plan, which may be used as short-term and long-term compensation components of the awards, and are subject to satisfaction of certain predetermined performance criteria.

As of June 30, 2019, there were 11,852,592 shares of common stock available for issuance in satisfaction of awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, which shares of common stock were issued net of withholding tax through the withholding of shares. The Company has the option following vesting to settle RSUs in stock or cash, or a combination of stock and cash. The Company expects to settle RSUs that vest in the future using shares of common stock.

RSUs currently outstanding relate to the 2019, 2018 and 2017 grants. The 2019 grants are subject to pre-determined performance criteria which will be measured using 2019 performance results. The 2018 and 2017 grants were subject to predetermined performance criteria applied against the applicable performance period. All the RSUs currently outstanding are subject to employment-based criteria and vesting generally occurs in December of the second year after the grant. See the table below for anticipated vesting by year.

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. The fair values for the RSUs granted during 2019, 2018 and 2017 were determined using the Company’s closing price on the grant date. We also estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.

A summary of activity related to RSUs during the six months ended June 30, 2019 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2018		3,355,917		$	3.90
Granted		988,800			4.51
Forfeited (1)		(897,828	)		2.85
Nonvested, June 30, 2019		3,446,889			4.35

(1)

Primarily related to a former executive’s forfeitures.

For the outstanding RSUs issued to the eligible employees as of June 30, 2019, vesting is expected to occur as follows (subject to forfeitures):

	Restricted Stock Units
2019		1,555,740
2020		902,349
2021		988,800
Total		3,446,889

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 and 2017. As of June 30, 2019, there were 82,620 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available are reduced on a one-to-one basis when Restricted Shares are granted.

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

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

A summary of activity related to Restricted Shares during the six months ended June 30, 2019 is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2018		181,832		$	3.08
Granted		46,360			6.04
Vested		(105,012	)		2.67
Nonvested, June 30, 2019		123,180			4.55

For the Restricted Shares vested during the six months ended June 30, 2019, the grant date value was $0.3 million and the vested date value, as determined on the vesting dates, was $0.5 million.

For the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2019, vesting is expected to occur as follows (subject to any forfeitures):

	Restricted Shares
2020		78,428
2021		29,300
2022		15,452
Total		123,180

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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. A summary of incentive compensation expense under share-based payment arrangements is as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Share-based compensation expense from:
Restricted stock units (1)	$	1,189	$	1,145	$	1,041	$	2,294
Restricted Shares		70		70		140		140
Total	$	1,259	$	1,215	$	1,181	$	2,434

(1)

For the six months ended June 30, 2019, share-based compensation expense includes adjustments for a former executive’s forfeitures.

Unrecognized Share-Based Compensation. As of June 30, 2019, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $7.8 million and $0.5 million, respectively. Unrecognized share-based compensation expense will be recognized through November 2021 for RSUs and April 2022 for Restricted Shares.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Cash-Based Incentive Compensation. In addition to share-based awards, cash-based awards were granted under the Plan to eligible employees in 2019, 2018 and 2017. For 2018, there were two cash-based awards consisting of a long-term award and a short-term award. All cash-based awards are performance-based awards consisting of predetermined performance criteria applied against the applicable performance period. Expense for each award is recognized over the service period once the applicable financial condition is expected to be met, and the business criteria and individual performance criteria can be reasonably estimated for the applicable period.

•

For the 2019 short-term, cash-based awards, incentive compensation expense was determined based on estimates of the Company achieving certain performance metrics for 2019 and is being recognized over the May 2019 to February 2020 period. The 2019 short-term, cash-based awards will be eligible for payment during March 2020, subject to participants meeting certain employment-based criteria

•

For the 2018 long-term, cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2018 and is being recognized over the September 2018 to November 2020 period. The 2018 long-term, cash-based awards will be eligible for payment on December 14, 2020 subject to participants meeting certain employment-based criteria.

•

For the 2018 short-term, cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2018 combined with individual performance criteria for 2018 and was recognized over the January 2018 to February 2019 period. The 2018 short-term, cash-based awards were paid during March 2019.

•

For the 2017 cash-based awards, incentive compensation expense was determined based on the Company achieving certain performance metrics for 2017 combined with individual performance criteria for 2017 and was recognized over the January 2017 to February 2018 period. The 2017 cash-based awards were paid during March 2018.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Share-based compensation included in:
General and administrative expenses	$	1,259	$	1,215	$	1,181	$	2,434
Cash-based incentive compensation included in:
Lease operating expense (1)		402		543		279		1,403
General and administrative expenses (1)		1,243		1,391		3,338		4,063
Total charged to operating income	$	2,904	$	3,149	$	4,798	$	7,900

(1)

Includes adjustments of accruals to actual payments.

10.

Income Taxes

Our income tax benefit for the three and six months ended June 30, 2019 was $11.7 million and $11.5 million, respectively. During the three months ended June 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the Internal Revenue Service ("IRS"), which resulted in a net tax benefit for the three and six months ended June 30, 2019. Our income tax expense for the three and six months ended June 30, 2018 was $0.1 million and $0.2 million, respectively. Our effective tax rate was not meaningful for the periods presented as we continue to record a full valuation allowance on net deferred tax assets.

During the six months ended June 30, 2019 and 2018, we did not receive any income tax refunds or make any income tax payments of significance.

As of June 30, 2019 and December 31, 2018, our valuation allowance was $121.8 million and $117.8 million, respectively, related to net federal and state deferred tax assets. Net deferred tax assets were recorded related to net operating loss, interest expense carryforwards and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

As of June 30, 2019 and December 31, 2018, we had current income taxes receivable of $54.1 million, which primarily relates to our net operating loss carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years. These carryback claims were made pursuant to IRC Section 172(f) (related to rules regarding “specified liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims required a review by the Congressional Joint Committee on Taxation, which was completed during the second quarter of 2019. We expect to receive the income tax refunds during the third quarter of 2019.

The tax years 2013 through 2018 remain open to examination by the tax jurisdictions to which we are subject.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11.

Earnings (Loss) Per Share

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019			2018
Net income (loss)	$	36,389	$	36,083	$	(11,372	)	$	63,723
Less portion allocated to nonvested shares		666		1,474		—			2,621
Net income (loss) allocated to common shares	$	35,723	$	34,609	$	(11,372	)	$	61,102
Weighted average common shares outstanding		140,567		138,929		140,507			138,892

Basic and diluted earnings (loss) per common share	$	0.25	$	0.25	$	(0.08	)	$	0.44

Shares excluded due to being anti-dilutive (weighted-average)		—		—		2,978			—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

12.

Contingencies

Apache Lawsuit. On December 15, 2014, Apache filed a lawsuit against the Company, Apache Deepwater, L.L.C. vs. W&T Offshore, Inc., alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney’s fees and costs assessed in the judgment. We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit and provided oral arguments in December 2018. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017. On July 16, 2019, a panel of the U.S. Court of Appeals for the Fifth Circuit rendered its opinion that affirmed the trial court's judgement against the Company. The Company intends to pursue vigorously all available legal recourse. See Note 13, Subsequent Event, for additional information.

The deposit of $49.5 million with the registry of the court is recorded in Other assets (long-term) on the Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018. In addition, we recorded $49.5 million in Other liabilities (long-term) on the Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018.

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the Department of the Interior. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017. Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana. We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision. On December 4, 2018, the IBLA denied our motion for reconsideration. On February 4, 2019, we filed our first amended complaint, and the government has filed its Answer in the Administrative Record. On July 9, 2019, we filed an Objection to the Administrative Record and Motion to Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the record. A hearing on that motion has been set for July 31, 2019. After W&T’s Motion to Supplement is fully resolved, the parties will file cross-motions for summary judgment.

Royalties-In-Kind (“RIK”). Under a program of the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program. The MMS added to the RIK program our lease at the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed. The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to become fixed for accounting purposes. The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed. We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor. We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ruling on May 29, 2018. We filed an appeal on July 24, 2018. Part of the ruling was in favor of our position and part was in favor of MMS’ position. Based solely on the District Court’s ruling, we recorded a liability reserve of $2.2 million and $2.1 million as of June 30, 2019 and December 31, 2018, respectively. We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals and the government filed a cross-appeal. Briefing has now been completed and we are waiting for the Court to schedule oral argument, which we expect will occur in 2019. Based on the briefs filed, W&T has asserted that the government has waived its claim for interest for the period prior to the MMS’s issuance of its order in 2010 requiring W&T to make a cash payment to resolve delivery imbalances (MMS quantified this interest amount as approximately $0.7 million); the government has not disputed W&T’s assertion on this issue.

Royalties – “Unbundling” Initiative. The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. For the six months ended June 30, 2019 and 2018, we paid $0.2 million and $0.3 million, respectively, of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment. During the six months ended June 30, 2019 and 2018, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) at various offshore locations. We currently have nine open civil penalties issued by the BSEE from INCs, which have not been settled as of the filing date of this Form 10-Q. The INCs underlying these open civil penalties cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations on various dates ranging from July 2012 to January 2018. The proposed civil penalties for these INCs total $7.7 million. As of June 30, 2019 and December 31, 2018, we have accrued approximately $3.5 million, which is our best estimate of the final settlements once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

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

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

13. Subsequent Event

On July 16, 2019, a panel of the United States Fifth Circuit Court of Appeals rendered its opinion in the lawsuit, Apache Deepwater, L.L.C. vs. W&T Offshore, Inc. The opinion affirmed the trial court's judgment against the Company. The Company intends to pursue vigorously all available legal recourse. As noted above in Note 12, in 2017 in connection with the appeal, the Company deposited $49.5 million in the registry of the court and accrued such amount as a liability. Accordingly, management of the Company does not believe that the appeal court's decision to affirm the trail court's judgment will materially impact our available liquidity, financial position or results of operations.

See Note 7, Oil and Gas Property Acquisition, for information regarding the Company’s recent agreement to purchase from ExxonMobil interests in and operatorship of certain oil and gas producing properties.

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

Forward-Looking Statements

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 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.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. We have grown through acquisitions, exploration and development and hold working interests in 47 offshore fields in federal and state waters (45 producing and two fields capable of producing). As of June 30, 2019, we have under lease approximately 710,000 gross acres (440,000 net acres) spanning across the Outer Continental Shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 490,000 gross acres on the conventional shelf and approximately 220,000 gross acres in the deepwater (water depths in excess of 500 feet). 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 in Monza, as described in more detail in Financial Statements– Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the six months ended June 30, 2019 were comprised of 51.1% crude oil and condensate, 9.2% NGLs and 39.7% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past. For the six months ended June 30, 2019, revenues from the sale of crude oil and NGLs made up 82.5% of our total revenues compared to 81.9% for the six months ended June 30, 2018. For the six months ended June 30, 2019, our combined total production expressed in equivalent volumes was 8.3% lower than for the six months ended June 30, 2018, with natural gas having the largest decline. For the six months ended June 30, 2019, our total revenues were 11.6% lower than the six months ended June 30, 2018 primarily due to lower production and lower realized prices for crude oil, NGLs and natural gas. See Results of Operations – Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018 in this Item 2 for additional information.

Our operating results are strongly influenced by the price of the commodities that we produce and sell. The price of those commodities is affected by both domestic and international factors, including domestic production. During the six months ended June 30, 2019, our average realized crude oil price was $61.96 per barrel. This is a decrease from our average realized crude oil price of $64.93 per barrel, or 4.6%, for the six months ended June 30, 2018 and a decrease from our average realized crude oil price of $65.62 per barrel, or 5.6%, for the year 2018. Our average realized prices of NGLs and natural gas for the six months ended June 30, 2019 were lower than the average realized prices for the six months ended June 30, 2018 by 29.8% and 3.8%, respectively.

Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary significantly by field. All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of WTI versus Poseidon, LLS and HLS for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 improved by approximately $4.00 per barrel for these types of crude oils.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. For the six months ended June 30, 2019 compared to the six months ended June 30, 2018, average prices for domestic ethane decreased by 15% and average domestic propane prices decreased by 30% as measured using a price index for Mount Belvieu. The average price for other domestic NGLs components ranged from decreases of 20% to 33% for the six months ended June 30, 2019 year-over-year. 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.

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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 June 28, 2019 was lower than a year ago for land based rigs (a decrease of 86 rigs, or 8%), and higher in the Gulf of Mexico (an increase of seven rigs or 37%). The oil rig count as of June 28, 2019 and June 29, 2018 was 793 and 858, respectively. The U.S. natural gas rig count as of June 28, 2019 and June 29, 2018 was 173 and 187, respectively. In the Gulf of Mexico, the number of working rigs was 26 rigs (24 oil rigs and two natural gas rigs) as of June 28, 2019 and 19 rigs (15 oil rigs and three natural gas rigs) as of June 29, 2018. During the three months ended June 30, 2019, we had four rigs running, which represents approximately 15% of the active rigs in the Gulf of Mexico.

On June 26, 2019, we entered into a purchase and sale agreement with ExxonMobil Corporation to acquire their interests in and operatorship of oil and gas producing properties in the eastern region of the GOM offshore Alabama and a related processing facility for $200 million, subject to customary post-effective date adjustments for an effective date of January 1, 2019. The acquisition will be funded from cash on hand and borrowings under the Credit Agreement at closing date. The transaction includes nine GOM offshore producing fields and an onshore treating facility that are adjacent to existing properties owned and operated by us. The acquisition is expected to close on or about August 30, 2019. As of the effective date of the acquisition, the properties had approximately 74 million Boe of net proved reserves, of which 99% were proved developed producing reserves and 22% of the proved net reserves are from liquids, based on October 15, 2018 NYMEX Henry Hub gas and NYMEX WTI oil prices. For the first quarter of 2019, the average production of the properties being acquired was approximately 19,800 net Boe per day.

Our capital expenditure forecast for 2019 excluding the above acquisition, other potential acquisitions and ARO is estimated to be approximately $125 to $155 million composed of select shelf and deepwater projects most of which, 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 approximately $23 million for ARO. Based upon current price and production expectations for 2019, we believe that our cash flows from operating activities, cash on hand and borrowing availability under the Credit Agreement will be sufficient to fund our operations through year-end 2019 and the acquisition of the ExxonMobil properties described above; 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.

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Results of Operations

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

	Three Months Ended June 30,											Six Months Ended June 30,
	2019			2018		Change			%			2019			2018		Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	109,195		$	116,618	$	(7,423	)		(6.4	)%	$	195,898		$	213,924	$	(18,026	)		(8.4	)%
NGLs		4,640			8,734		(4,094	)		(46.9	)%		11,088			18,394		(7,306	)		(39.7	)%
Natural gas		19,567			22,977		(3,410	)		(14.8	)%		41,405			48,844		(7,439	)		(15.2	)%
Other		1,299			1,283		16			1.2	%		2,390			2,663		(273	)		(10.3	)%
Total revenues		134,701			149,612		(14,911	)		(10.0	)%		250,781			283,825		(33,044	)		(11.6	)%
Operating costs and expenses:
Lease operating expenses		40,341			35,582		4,759			13.4	%		83,797			72,425		11,372			15.7	%
Production taxes		317			439		(122	)		(27.8	)%		733			894		(161	)		(18.0	)%
Gathering and transportation		7,068			4,928		2,140			43.4	%		13,491			9,985		3,506			35.1	%
Depreciation, depletion, amortization and accretion		38,073			39,757		(1,684	)		(4.2	)%		71,839			77,838		(5,999	)		(7.7	)%
General and administrative expenses		13,328			14,220		(892	)		(6.3	)%		27,437			29,258		(1,821	)		(6.2	)%
Derivative (gain) loss		(1,805	)		6,219		(8,024	)		NM			47,081			6,219		40,862			NM
Total costs and expenses		97,322			101,145		(3,823	)		(3.8	)%		244,378			196,619		47,759			24.3	%
Operating income		37,379			48,467		(11,088	)		(22.9	)%		6,403			87,206		(80,803	)		(92.7	)%
Interest expense, net		12,207			11,786		421			3.6	%		28,489			22,748		5,741			25.2	%
Other expense, net		478			486		(8	)		(1.6	)%		809			514		295			57.4	%
Income (loss) before income tax (benefit) expense		24,694			36,195		(11,501	)		(31.8	)%		(22,895	)		63,944		(86,839	)		NM
Income tax (benefit) expense		(11,695	)		112		(11,807	)		NM			(11,523	)		221		(11,744	)		NM
Net income (loss)	$	36,389		$	36,083	$	306			0.8	%	$	(11,372	)	$	63,723	$	(75,095	)		NM
Basic and diluted earnings (loss) per common share	$	0.25		$	0.25		—			—		$	(0.08	)	$	0.44	$	(0.52	)		NM

NM – not meaningful

	Three Months Ended June 30,										Six Months Ended June 30,
	2019		2018		Change			% ⁽²⁾			2019		2018		Change			% ⁽²⁾
Operating: ⁽¹⁾
Net sales:
Oil (MBbls)		1,683		1,738		(55	)		(3.2	)%		3,161		3,295		(134	)		(4.1	)%
NGLs (MBbls)		264		316		(52	)		(16.5	)%		573		667		(94	)		(14.1	)%
Natural gas (MMcf)		7,450		8,186		(736	)		(9.0	)%		14,738		16,709		(1,971	)		(11.8	)%
Total oil equivalent (MBoe)		3,189		3,419		(230	)		(6.7	)%		6,190		6,747		(557	)		(8.3	)%

Average daily equivalent sales (Boe/day)		35,045		37,571		(2,526	)		(6.7	)%		34,201		37,275		(3,074	)		(8.2	)%
Average realized sales prices:
Oil ($/Bbl)	$	64.86	$	67.09	$	(2.23	)		(3.3	)%	$	61.96	$	64.93	$	(2.97	)		(4.6	)%
NGLs ($/Bbl)		17.59		27.61		(10.02	)		(36.3	)%		19.36		27.57		(8.21	)		(29.8	)%
Natural gas ($/Mcf)		2.63		2.81		(0.18	)		(6.4	)%		2.81		2.92		(0.11	)		(3.8	)%
Oil equivalent ($/Boe)		41.83		43.38		(1.55	)		(3.6	)%		40.13		41.67		(1.54	)		(3.7	)%

Average per Boe ($/Boe):
Lease operating expenses	$	12.65	$	10.41	$	2.24			21.5	%	$	13.54	$	10.73	$	2.81			26.2	%
Gathering and transportation		2.22		1.44		0.78			54.2	%		2.18		1.48		0.70			47.3	%
Production costs		14.87		11.85		3.02			25.5	%		15.72		12.21		3.51			28.7	%
Production taxes		0.10		0.13		(0.03	)		(23.1	)%		0.12		0.13		(0.01	)		(7.7	)%
DD&A		11.94		11.63		0.31			2.7	%		11.61		11.54		0.07			0.6	%
G&A expenses		4.18		4.16		0.02			0.5	%		4.43		4.34		0.09			2.1	%
	$	31.09	$	27.77	$	3.32			12.0	%	$	31.88	$	28.22	$	3.66			13.0	%

(1)

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

(2)

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 June 30, 2019 Compared to the Three Months Ended June 30, 2018

Revenues. Total revenues decreased $14.9 million, or 10.0%, to $134.7 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. Oil revenues decreased $7.4 million, or 6.4%, NGLs revenues decreased $4.1 million, or 46.9%, natural gas revenues decreased $3.4 million, or 14.8%, and other revenues were approximately the same. The decrease in oil revenues was attributable to a 3.3% decrease in the average realized sales price to $64.86 per barrel for the three months ended June 30, 2019 from $67.09 per barrel for the three months ended June 30, 2018 and a 3.2% decrease in sales volumes. The decrease in NGLs revenues was attributable to a 36.3% decrease in the average realized sales price to $17.59 per barrel for the three months ended June 30, 2019 from $27.61 per barrel for the three months ended June 30, 2018 and a 16.5% decrease in sales volumes. The decrease in natural gas revenues was attributable to a 6.4% decrease in the average realized price to $2.63 per Mcf for the three months ended June 30, 2019 from $2.81 per Mcf for the three months ended June 30, 2018 and a 9.0% decrease in sales volumes. Overall, production volumes decreased 6.7% on a Boe basis. The largest production increases for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 were from our Ship Shoal 349 (Mahogany) field, Fairway field and Viosca Knoll 734 field. Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to maintenance issues at certain platforms and pipelines. Our estimate of deferred production for the three months ended June 30, 2019 was approximately 4,900 Boe per day as compared to 4,600 Boe per day for the three months ended June 30, 2018, which comprises 12% of the production volume variance between the two periods.

Revenues from oil and NGLs as a percent of our total revenues were 84.5% for the three months ended June 30, 2019 compared to 83.8% for the three months ended June 30, 2018. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 27.1% for the three months ended June 30, 2019 compared to 41.2% for the three months ended June 30, 2018.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $4.8 million, or 13.4%, to $40.3 million for the three months ended June 30, 2019 compared to the three months ended June 30, 2018. On a component basis, base lease operating expenses increased $2.0 million and facilities maintenance expense increased $3.5 million, partially offset by a decrease in workover expenses of $0.7 million. Base lease operating expenses increased primarily due to lower charges to joint interest partners at our Mississippi Canyon 243 (Matterhorn) field, which are recorded as credits to expense. In addition, base lease operating expenses increased at our Green Canyon 859 (Heidelberg) field, which was acquired in April 2018, and a credit related to settlement of a joint-venture audit recorded during the three months ended June 30, 2018. The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Mahogany field. The decrease in workover expense was primarily due to lower project expenses at our Mahogany field, which were partially offset by higher project expenses incurred at other fields.

Gathering and transportation. Gathering and transportation expenses increased $2.1 million to $7.1 million for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 primarily related to rate changes from certain third-party pipelines.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, increased to $11.94 per Boe for the three months ended June 30, 2019 from $11.63 per Boe for the three months ended June 30, 2018. On a nominal basis, DD&A decreased to $38.1 million (or 4.2%) for the three months ended June 30, 2019 from $39.8 million for the three months ended June 30, 2018. DD&A on a nominal basis decreased primarily due to lower production. Other factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

General and administrative expenses (“G&A”). G&A was $13.3 million for the three months ended June 30, 2019, decreasing 6.3% from $14.2 million for the three months ended June 30, 2018. The decrease was primarily due to increased charges (credits) to counterparties related to joint interest arrangements, lower expenses related to surety bonds and lower incentive compensation expenses. G&A on a per Boe basis was $4.18 per Boe for the three months ended June 30, 2019 compared to $4.16 per Boe for the three months ended June 30, 2018.

Derivative (gain) loss. The three months ended June 30, 2019 reflects a $1.8 million derivative gain primarily due to decreased crude oil future pricing used to value our derivative contracts at June 30, 2019 as compared to March 31, 2019, which increased the estimated fair value of our open crude oil contracts between the two measurement dates. For the three months ended June 30, 2018, we recorded a net loss of $6.2 million from derivative contracts.

Interest expense, net. Interest expense, net, was $12.2 million and $11.8 million for the three months ended June 30, 2019 and 2018, respectively. During the three months ended June 30, 2019, we accrued interest income of $4.0 million related to income tax refunds as we received confirmation from the IRS that our refund filings have been approved for payment. During the three months ended June 30, 2018, a portion 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 the three months ended June 30, 2018 and affects the comparability.

Income tax (benefit) expense. Our income tax benefit for the three months ended June 30, 2019 was $11.7 million and our income tax expense for the three months ended June 30, 2018 was $0.1 million. During the three months ended June 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, which resulted in a net tax benefit for the three months ended June 30, 2019. Immaterial deferred income tax expense was recorded for the three months ended June 30, 2018 due to dollar-for-dollar offsets by our valuation allowance. Our effective tax rate using book pre-tax income was not meaningful for either period. For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets. As of June 30, 2019, our valuation allowance was $121.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs. See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018

Revenues. Total revenues decreased $33.0 million, or 11.6%, to $250.8 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. Oil revenues decreased $18.0 million, or 8.4%, NGLs revenues decreased $7.3 million, or 39.7%, natural gas revenues decreased $7.4 million, or 15.2%, and other revenues decreased $0.3 million. The decrease in oil revenues was attributable to a 4.6% decrease in the average realized sales price to $61.96 per barrel for the six months ended June 30, 2019 from $64.93 per barrel for the six months ended June 30, 2018 and a 4.1% decrease in sales volumes. The decrease in NGLs revenues was attributable to a 29.8% decrease in the average realized sales price to $19.36 per barrel for the six months ended June 30, 2019 from $27.57 per barrel for the six months ended June 30, 2018 and a 14.1% decrease in sales volumes. The decrease in natural gas revenues was attributable to a 3.8% decrease in the average realized price to $2.81 per Mcf for the six months ended June 30, 2019 from $2.92 per Mcf for the six months ended June 30, 2018 and a 11.8% decrease in sales volumes. Overall, production volumes decreased 8.3% on a Boe basis. The largest production increases for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 were from our Mahogany field, Ship Shoal 028 field, Ship Shoal 032 field, Fairway field and Heidelberg field, which was acquired in April 2018. Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to maintenance issues at certain platforms and pipelines. Our estimate of deferred production for the six months ended June 30, 2019 was approximately 6,000 Boe per day as compared to 4,400 Boe per day for the six months ended June 30, 2018, which comprises 52% of the production volume variance between the two periods.

Revenues from oil and NGLs as a percent of our total revenues were 82.5% for the six months ended June 30, 2019 compared to 81.9% for the six months ended June 30, 2018. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 31.2% for the six months ended June 30, 2019 compared to 42.5% for the six months ended June 30, 2018.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $11.4 million, or 15.7%, to $83.8 million in the six months ended June 30, 2019 compared to the six months ended June 30, 2018. On a component basis, base lease operating expenses increased $3.4 million, facilities maintenance expense increased $6.4 million and workover expenses increased $1.6 million. Base lease operating expenses increased primarily due to the addition of the Heidelberg field, acquired in April 2018, which had an increase in base lease operating expense of $2.3 million. In addition, base lease operating expenses increased due to lower charges to joint interest partners at our Matterhorn field, which are recorded as credits to expense, and a credit related to settlement of a joint-venture audit recorded during the six months ended June 30, 2018. The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Mahogany field. The increase in workover expense was primarily due to 2019 projects at our Mahogany field.

Gathering and transportation. Gathering and transportation expenses increased $3.5 million to $13.5 million for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily related to rate changes from certain third-party pipelines which became effective during the three months ended June 30, 2019.

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, increased to $11.61 per Boe for the six months ended June 30, 2019 from $11.54 per Boe for the six months ended June 30, 2018. On a nominal basis, DD&A decreased to $71.8 million (or 7.7%) for the six months ended June 30, 2019 from $77.8 million for the six months ended June 30, 2018. DD&A on a nominal basis decreased primarily due to lower production. Other factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

General and administrative expenses. G&A was $27.4 million for the six months ended June 30, 2019, decreasing 6.2% from $29.3 million for the six months ended June 30, 2018. The decrease was primarily due to lower expenses related to surety bonds and lower incentive compensation expenses. G&A on a per Boe basis was $4.43 per Boe for the six months ended June 30, 2019 compared to $4.34 per Boe for the six months ended June 30, 2018.

Derivative loss. The six months ended June 30, 2019 reflects a $47.1 million derivative loss primarily due to increased crude oil future pricing used to value our derivative contracts at June 30, 2019 as compared to December 31, 2018, which decreased the estimated fair value of our open crude oil contracts between the two measurement dates. For the six months ended June 30, 2018, we recorded a net loss of $6.2 million from derivative contracts.

Interest expense, net. Interest expense, net, was $28.5 million and $22.7 million for the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, we accrued interest income of $4.0 million related to income tax refunds as we received confirmation from the IRS that our refund filings have been approved for payment. During the six months ended June 30, 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under ASC 470-60, which lowered reported interest expense and affects the comparability.

Income tax (benefit) expense. Our income tax benefit for the six months ended June 30, 2019 was $11.5 million and our income tax expense for the six months ended June 30, 2018 was $0.2 million. During the six months ended June 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, which resulted in a net tax benefit for the six months ended June 30, 2019. Immaterial deferred income tax expense was recorded for the six months ended June 30, 2018 due to dollar-for-dollar offsets by our valuation allowance. Our effective tax rate using book pre-tax income was not meaningful for either period. For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets. See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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Liquidity and Capital Resources

Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our 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.

Credit Agreement. On October 18, 2018, we entered into the Credit Agreement, which matures on October 18, 2022. As of June 30, 2019, we had $21.0 million borrowings outstanding under the Credit Agreement and $7.2 million of letters of credit issued under the Credit Agreement. During the six months ended June 30, 2019, we did not have any additional borrowings or repayments under the Credit Agreement. Availability under our Credit Agreement as of June 30, 2019 was $221.8 million. As noted in the Overview section of this Item, the funding of the pending oil and gas property acquisition from ExxonMobil will be from cash on hand and borrowings under the Credit Agreement.

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 has not changed. The next redetermination is to be completed by November 15, 2019. Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our Credit Agreement. The Credit Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.

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. While we have not experienced, nor do we anticipate, 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 under Part I, Item 1 of this Form 10-Q for additional information.

Senior Second Lien Notes. As of June 30, 2019, we had outstanding $625.0 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements – Note 2 –Long-Term Debt 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 June 30, 2019.

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 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

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

Cash Flow and Working Capital. Net cash provided by operating activities for the six months ended June 30, 2019 and 2018 was $106.3 million and $115.2 million, respectively. Our combined average realized sales price per Boe decreased by 3.7% for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, which caused total revenues to decrease $15.7 million. Production volumes decreased by 8.3% primarily from increases in downtime, which caused revenues to decrease by $17.0 million. In addition, operating expenses impacting operating cash flows increased by $14.1 million primarily for workover and facility projects.

Other items affecting operating cash flows was an increase of $18.5 million for the six months ended June 30, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to a decrease of $3.8 million for the six months ended June 30, 2018. ARO settlements were $9.5 million lower between the two periods and cash derivative receipts, net, increased $13.9 million between the two periods 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 six months ended June 30, 2019 and 2018 was $73.1 million and $77.8 million, respectively, which represents our investments in oil and gas properties and equipment. Our capital expenditures for the six months ended June 30, 2019 were split fairly evenly for investments in the deep waters of the Gulf of Mexico and on the conventional shelf of the Gulf of Mexico. During the six months ended June 30, 2019, we made a deposit of $10.0 million related to the pending oil and gas property acquisition from ExxonMobil described in the Overview section of this Item and there were no material acquisitions or asset sales in the period. During the six months ended June 30, 2018, the purchase of the interest in the Heidelberg field was consummated for $16.6 million.

Net cash used by financing activities for the six months ended June 30, 2019 and 2018 was $0.8 million and $7.1 million, respectively. The net cash used for the six months ended June 30, 2018 was primarily 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. 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, 2019. 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 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, and our Energy Package effective on June 1, 2019, 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 six months ended June 30, 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):

	Six Months Ended June 30,
	2019		2018
Exploration (1)	$	10,018	$	5,934
Development (1)		43,996		37,535
Deposit for acquisition		10,000		—
Heidelberg field		—		16,617
Reimbursement from Monza for 2017 expenditures		—		(14,075	)
Seismic and other		12,884		2,409
Investments in oil and gas property/equipment	$	76,898	$	48,420

(1)

Reported geographically in the subsequent table.

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

	Six Months Ended June 30,
	2019		2018
Conventional shelf	$	25,204	$	30,922
Deepwater		28,810		12,547
Exploration and development capital expenditures	$	54,014	$	43,469

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 six months ended June 30, 2019 were financed by cash flow from operations and cash on hand.

During the six months ended June 30, 2019, we completed the Virgo A-13 well, which began producing during March 2019 and the South Timbalier 320 A-3 well, which began producing in July 2019. Both of these wells are in the JV Drilling Program. We did not drill any dry holes during the six months ended June 30, 2019. During the six months ended June 30, 2018, we completed two wells.

Exploration/Development Activities. As of July 15, 2019, we were drilling on the Ship Shoal 028 #41 well and were performing completion operations on the MC 800 S02 well. Both of these wells are in the JV Drilling Program.

Offshore Lease Awards. During the six months ended June 30, 2019, we were successful in acquiring leases on 15 blocks (eight deepwater and seven shallow water) from the Gulf of Mexico Lease Sale 252 held by the BOEM on March 20, 2019, and these leases have been officially assigned to us. These 15 blocks cover approximately 73,500 acres and we paid approximately $3.5 million for all of the awarded leases combined, which reflects a 100% working interest in the acreage.

Capital Expenditure Forecast. Our 2019 capital expenditure forecast is estimated to be approximately $125 to 155 million, which excludes the pending transaction for the Exxon Mobil properties described in the Overview section of this Item, any additional potential acquisitions and ARO. 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.

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Income Taxes. As of June 30, 2019, we had current income taxes receivable of $54.1 million and accrued $4.0 million of related interest income, which is expected to be received in the third quarter of 2019. For 2019, we do not expect to make any significant income tax payments. See Financial Statements – Note 10 –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 as of June 30, 2019 and December 31, 2018 were $323.3 million and $310.1 million, respectively. Our plans include spending approximately $23 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, Note 5 – Asset Retirement Obligations and Note 7 – Oil and Gas Property Acquisition under Part I, Item 1 of this Form 10-Q. As of June 30, 2019, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $10.2 million, which was approximately the same as the amount as of December 31, 2018. Except for scheduled utilization, other contractual obligations as of June 30, 2019 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.

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

Recent Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the six months ended June 30, 2019 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, 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.

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 have impacts on our business in the future. During 2018, we entered into derivative crude oil 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 June 30, 2019, we had $21.0 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. Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO have each concluded that as of June 30, 2019, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended June 30, 2019, 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 12 – Contingencies and Note 13 – Subsequent Event , 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 risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results 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 for the year ended December 31, 2018.

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		Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

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

10.1*†		Purchase and Sale Agreement, dated as of January 1, 2019, between Exxon Mobil Corporation, Mobil Oil Exploration & Producing Southeast Inc., XH, LLC, Exxon Mobile Bay Limited Partnership, ExxonMobil U.S. Properties Inc. and W&T Offshore, Inc.

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 herewith.

†	Certain information has been excluded from this exhibit because it is both (i) not material and (ii) would likely cause competitive harm to the registrant if publicly disclosed.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 1, 2019.

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

Article 1. DEFINITIONS		1

1.01.	Ad Valorem Taxes	1
1.02.	Additional Instruments	1
1.03.	Affiliate	1
1.04.	Allocation	1
1.05.	Associated Party or Parties	1
1.06.	Base Purchase Price	1
1.07.	Business Day(s)	2
1.08.	Claim or Claims	2
1.09.	Closing	2
1.10.	Closing Date	2
1.11.	Closing Settlement Statement	2
1.12.	Code	2
1.13.	Condition	2
1.14.	Effective Time	2
1.15.	Environmental Laws	2
1.16.	Execution Date	2
1.17.	ExxonMobil-operated	2
1.18.	Final Settlement Statement	2
1.19.	Interest or Interests	2
1.20.	Lender	4
1.21.	Liability or Liabilities	4
1.22.	Material Difference	4
1.23.	Material Related Agreements	4
1.24.	NORM	4
1.25.	Occurrence	4
1.26.	Oil	4
1.27.	Operator	4
1.28.	PCB	4
1.29.	Performance Deposit	4
1.30.	Person	4
1.31.	Property or Properties	4
1.32.	Property Sales Accounting Agreement	4
1.33.	Raw Make	4
1.34.	RCRA	5
1.35.	Related Agreements	5
1.36.	Strict Liability	5
1.37.	TSCA	5
1.38.	Title Defect	5
1.39.	Transition Services Agreement	5
1.40.	Well or Wells	5

Article 2. PURCHASE AND SALE		5

Article 3. PURCHASE PRICE		5

3.01.	Base Purchase Price	5
3.02.	Performance Deposit and Payment	5
3.03.	Allocation of Base Purchase Price	6

Article 4. INTENTIONALLY LEFT BLANK		6

Article 5. BUYER’S REVIEW		6

5.01.	Buyer’s Review before Sinning this Agreement	6
5.02.	Access to ExxonMobil-Operated Interests	7
5.03.	Environmental Assessment	7
5.04.	Access to Interests Operated by Others	8
5.05.	Material, Facilities, Platforms, and Equipment	8
5.06.	No Warranty of Accuracy; Disclaimer	8
5.07.	Buyer’s Confidentiality Obligations	8

Article 6. TITLE AND TITLE DEFECTS		9

6.01.	Title Defect	9
6.02.	Adjustments to Base Purchase Price based on Allocations	9
6.03.	Description and Other Errors	11
6.04.	Restrictions on Use	12
6.05.	Engineering Controls	12
6.06.	Covenants Running with the Land	13
6.07.	Retention of Title for Gas	13

Article 7. PRE-CLOSING OBLIGATIONS		13

7.01.	Preferential Rights.	13
7.02.	Related Agreements	14
7.03.	Third Party Notifications and Approvals	14
7.04.	Change of Operator	15
7.05.	Employees	15

Article 8. CLOSING		15

8.01.	Closing Date	15
8.02.	Buyer’s Right to Delay Closing	16
8.03.	ExxonMobil’s Right to Delay Closing	16
8.04.	Closing Obligations	16
8.05.	Offset of Amounts Owed to ExxonMobil and Affiliates	21
8.06.	Conditions Precedent	22
8.07.	Buyer’s Representation by Closing	22
8.08.	Insurance	22
8.09.	Right to Terminate	24

Article 9. POST-CLOSING OBLIGATIONS		24

9.01.	Filing and Recording	24
9.02.	Copies	24
9.03.	Further Assurances	25
9.04.	Post-Closing Third-Party Consents	25
9.05.	Reassignment	25
9.06.	Buyer’s Compliance	25
9.07.	Property Sales Accounting Agreement	25
9.08.	Plugging and Abandoning Wells: Remediation	25

Article 10. TAXES		26

10.01.	Ad Valorem Taxes	26
10.02.	Production Taxes	26
10.03.	Other Taxes	26
10.04.	Tax-Deferred Exchange	27

Article 11. OIL IN STORAGE, PROCEEDS, COSTS, EXPENSES, CLAIMS, AND DISBURSEMENTS		27

11.01.	Oil in Storage	27
11.02.	Proceeds, Costs, and Expenses	28
11.03.	Notice to Remitters of Proceeds	29
11.04.	Reservation of Claims	29

Article 12. EXXONMOBIL-OPERATED INTERESTS		29

12.01.	Operation by ExxonMobil	29
12.02.	Charges Paid by Buyer	29
12.03.	Risk of Loss	30
12.04.	Selection of Operator	30
12.05.	Removal of Signs	30

Article 13. INTERESTS OPERATED BY OTHERS		31

13.01.	Charges Paid by Buyer	31
13.02.	Risk of Loss	31

Article 14. []		31

Article 15. INTENTIONALLY LEFT BLANK		31

Article 16. RELEASE, DISCHARGE, AND COVENANT NOT TO SUE; OBLIGATIONS TO INDEMNIFY, DEFEND, AND HOLD HARMLESS; LIMITATION OF DAMAGES		31

16.01.	Buyer’s Release and Discharge of ExxonMobil and its Associated Parties	31
16.02.	Buyer’s Covenant Not to Sue ExxonMobil or its Associated Parties	31
16.03.	Obligations to Indemnify, Defend, and Hold Harmless, Limitation of Damages	32
16.04.	Buyer’s Obligations	33

16.05.	Buyer’s Duty to Defend	35
16.06.	Buyer’s Waiver of Consumer Rights Under the Texas Deceptive Trade Practices Consumer Protection Act and Other Consumer Protection Laws	35
16.07.	Retroactive Effect	35
16.08.	Inducement to ExxonMobil	35

Article 17. ALTERNATE DISPUTE RESOLUTION AND ARBITRATION		35

17.01.	General	35
17.02.	Negotiations	36
17.03.	Arbitration	36
17.04.	Notice	36

Article 18. ENVIRONMENTAL MATTERS		37

18.01.	Buyer’s Acknowledgment Concerning Possible Contamination of the Interests and Property	37
18.02.	Adverse Environmental Conditions	37
18.03.	Remediation	38
18.04.	Disposal of Materials, Substances, and Wastes; Compliance with Law	40

Article 19. BUYER’S AND EXXONMOBIL’S REPRESENTATIONS		41

19.01.	Representations Not Exclusive	41
19.02.	Securities Laws	41
19.03.	Basis of Buyer’s Decision	41
19.04.	Material Factor	42
19.05.	ExxonMobil’s Representations	42

Article 20. GAS IMBALANCES		42

20.01.	ExxonMobil’s and Buyer’s Respective Obligations	42
20.02.	Settlement	43

Article 21. FINAL SETTLEMENT STATEMENT		43

Article 22. INTENTIONALLY LEFT BLANK		44

Article 23. COMMUNICATIONS		44

Article 24. []		44

Article 25. HART-SCOTT-RODINO ANTITRUST IMPROVEMENTS ACT OF 1976; REQUIRED FILINGS IN FOREIGN JURISDICTIONS		45

25.01.	Obligation to Make Filings	45
25.02.	Cooperation on Making Filings	45

Article 26. EXXONMOBIL’S DISCLAIMER OF WARRANTIES AND REPRESENTATIONS		46

Article 27. MISCELLANEOUS		46

27.01.	No Joint and Several Obligations	46
27.02.	Entire Agreement	46
27.03.	Successors and Assigns; Amendment; Survival	46
27.04.	Choice of Law	47
27.05.	Assignment	47
27.06.	No Admissions	47
27.07.	No Third-Party Beneficiaries	48
27.08.	Public Communications	48
27.09.	Audit Clause	48
27.10.	Headings and Titles	48
27.11.	Exhibits	49
27.12.	Includes	49
27.13.	Severability	49
27.14.	Counterparts	49
27.15.	Conflicts	49
27.16.	Not to Be Construed against the Drafter	49
27.17.	No Waiver	49
27.18.	Conspicuousness	49
27.19.	Execution by the Parties	49

EXHIBIT A.	DESCRIPTION OF THE INTERESTS	A-1
EXHIBIT A-1.	INTERESTS	A-1-1
EXHIBIT B.	EASEMENTS, PERMITS, ETC	B-1
EXHIBIT C.	FORM OF ASSIGNMENT AND BILL OF SALE	C-1
EXHIBIT D.	PROPERTY SALES ACCOUNTING AGREEMENT	D-1
EXHIBIT E.	GAS-PRODUCTION-IMBALANCE ACCOUNTS	E-1
EXHIBIT F.	ENVIRONMENTAL ASSESSMENT AND TESTING CONFIDENTIALITY, RELEASE AND INDEMNIFICATION AGREEMENT	F-1
EXHIBIT G.	EMPLOYEES AND BENEFITS	G-1
EXHIBIT H.	PERFORMANCE BOND	H-1
EXHIBIT H-1.	PERFORMANCE BOND ESCALATION	H-1-1
EXHIBIT I.	TRANSITION SERVICES AGREEMENT	I-1
EXHIBIT J.	SPECIAL WARRANTY DEED	1- I
EXHIBIT K.	RIGHT-OF-WAY	K-1

W&T OFFSHORE, INC.		EXXON MOBIL CORPORATION


By:	/s/ Tracy W. Krohn	By:	/s/ Mickey D. Johnson

Name:	Tracy W. Krohn	Name:	Mickey D. Johnson

Title:	Chief Executive Officer	Title:	Agent and Attorney-in-Fact

Date:	6-26-19	Date:	6-26-19

MOBIL OIL EXPLORATION & PRODUCING SOUTHEAST INC.		XH, LLC


By:	/s/ Mickey D. Johnson	By:	/s/ Mickey D. Johnson

Name:	Mickey D. Johnson	Name:	Mickey D. Johnson

Title:	Agent and Attorney-in-Fact	Title:	Agent and Attorney-in-Fact

Date:	6-26-19	Date:	6-26-19

EXXON MOBILE BAY LIMITED PARTNERSHIP		EXXONMOBIL U.S. PROPERTIES INC.

Exxon Mobil Corporation, General Partner, on behalf of Exxon Mobile Bay Limited Partnership

By:	/s/ Jarod M. Rolland	By:	/s/ Mickey D. Johnson

Name:	Jarod M. Rolland	Name:	Mickey D. Johnson

Title:	Agent and Attorney-in-Fact	Title:	Agent and Attorney-in-Fact

Date:	June 26, 2019	Date:	6-26-19

Date: August 1, 2019	/s/ Tracy W. Krohn
	Tracy W. Krohn
	Chairman, Chief Executive Officer, President and Director
	(Principal Executive Officer)