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 ~~March 31,~~ September 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 ~~April~~October 29, 2019, there were ~~140,644,033~~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 ~~March 31,~~September 30, 2019 and December 31, 2018	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	2
	Condensed Consolidated ~~Statement~~Statements of Changes in Shareholders’ Deficit for the Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows for the ~~Three~~Nine Months Ended ~~March 31,~~September 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	21 19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31 26
Item 4.	Controls and Procedures	32 26

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	33 27
Item 1A.	Risk Factors	33 27
Item 6.	Exhibits	34 27

SIGNATURE		35
		28

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

	March 31,			December 31,			September 30,			December 31,
	2019			2018			2019			2018
Assets
Current assets:
Cash and cash equivalents	$	86,116		$	33,293		$	41,741		$	33,293
Receivables:
Oil and natural gas sales		41,308			47,804			51,626			47,804
Joint interest, net		17,620			14,634
Joint interest and other, net								30,484			14,634
Income taxes		54,076			54,076			36,910			54,076
Total receivables		113,004			116,514			119,020			116,514
Prepaid expenses and other assets (Note 1)		34,127			76,406			40,221			76,406
Total current assets		233,247			226,213			200,982			226,213

Oil and natural gas properties and other, net - at cost (Note 1)		514,765			515,421			720,951			515,421
Restricted deposits for asset retirement obligations		15,498			15,685			16,694			15,685
Deferred income taxes								55,579			—
Other assets (Note 1)		79,005			91,547			32,864			91,547
Total assets	$	842,515		$	848,866		$	1,027,070		$	848,866
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	71,359		$	82,067		$	105,922		$	82,067
Undistributed oil and natural gas proceeds		22,014			28,995			25,550			28,995
Advances from joint interest partners		65,271			20,627			36,473			20,627
Asset retirement obligations		24,799			24,994			23,095			24,994
Accrued liabilities (Note 1)		35,197			29,611			37,254			29,611
Total current liabilities		218,640			186,294			228,294			186,294

Long-term debt (Note 2)		634,005			633,535
Long-term debt								718,949			633,535
Asset retirement obligations, less current portion		289,363			285,143			321,400			285,143
Other liabilities (Note 1)		73,142			68,690			16,267			68,690
Commitments and contingencies (Note 10)		—			—
Commitments and contingencies								—			—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued for both dates presented		—			—			—			—
Common stock, $0.00001 par value; 200,000 shares authorized; 143,513 issued and 140,644 outstanding for both dates presented		1			1
Common stock, $0.00001 par value; 200,000 shares authorized; 143,560 issued and 140,690 outstanding on September 30, 2019 and 143,513 issued and 140,644 outstanding on December 31, 2018								1			1
Additional paid-in capital		545,627			545,705			548,134			545,705
Retained deficit		(894,096	)		(846,335	)		(781,808	)		(846,335	)
Treasury stock, at cost; 2,869 shares for both dates presented		(24,167	)		(24,167	)		(24,167	)		(24,167	)
Total shareholders’ deficit		(372,635	)		(324,796	)		(257,840	)		(324,796	)
Total liabilities and shareholders’ deficit	$	842,515		$	848,866		$	1,027,070		$	848,866

Common Stock
Outstanding

Additional
Paid-In

Retained

Treasury Stock

Total
Shareholders’

Shares

Value

Capital

Deficit

Shares

Value

Deficit

Balances at December 31, 2018

140,644

$
1

$
545,705

$
(846,335
)

2,869

$
(24,167
)

$
(324,796
)
Share-based compensation

—

—

(78
)

—

—

—

(78
)
Net loss

—

—

—

(47,761
)

—

—

(47,761
)
Balances at March 31, 2019

140,644

$
1

$
545,627

$
(894,096
)

2,869

$
(24,167
)

$
(372,635
)

	Common Stock Outstanding				Additional Paid-In		Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital		Deficit			Shares		Value			Deficit
Balances, June 30, 2019		140,690	$	1	$	546,886	$	(857,707	)		2,869	$	(24,167	)	$	(334,987	)
Share-based compensation		—		—		1,248		—			—		—			1,248
Net income		—		—		—		75,899			—		—			75,899
Balances, September 30, 2019		140,690	$	1	$	548,134	$	(781,808	)		2,869	$	(24,167	)	$	(257,840	)

	Common Stock Outstanding				Additional Paid-In		Retained			Treasury Stock					Total Shareholders’
	Shares		Value		Capital		Deficit			Shares		Value			Deficit
Balances, June 30, 2018		139,154	$	1	$	548,196	$	(1,031,439	)		2,869	$	(24,167	)	$	(507,409	)
Share-based compensation		—		—		1,373		—			—		—			1,373
Net income		—		—		—		46,260			—		—			46,260
Balances, September 30, 2018		139,154	$	1	$	549,569	$	(985,179	)		2,869	$	(24,167	)	$	(459,776	)

	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		—		—		3,808			—			—		—			3,808
Stock Issued		63		—		—			—			—		—			—
RSUs surrendered for payroll taxes (1)		—		—		(59	)		—			—		—			(59	)
Net income		—		—		—			109,983			—		—			109,983
Balances, September 30, 2018		139,154	$	1	$	549,569		$	(985,179	)		2,869	$	(24,167	)	$	(459,776	)

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 ~~W&T Offshore, Inc.~~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.~~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.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

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

(Unaudited)

~~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.~~

~~Houston Office Lease.~~ Minimum future lease payments due under the lease as of March 31, 2019 are as follows: 2019 - $1.1 million; 2020 - $1.6 million; 2021 - $1.6 million and 2022 - $1.6 million. Expense related to the Houston office lease for the three months ended March 31, 2019 and 2018 was $0.7 million each period.

As of March 31, 2019, we recorded an ROU asset and a lease liability of $5.0 million 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.

~~After the adoption of the new standard update, the amounts recorded within our Condensed Consolidated Balance Sheet are as follows (in thousands):~~

March 31, 2019

ROU:

Prepaid expenses and other current assets:

$
1,095

Other assets

3,856

Total ROU

$
4,951

Lease liability:

Accrued liabilities

$
1,095

Other liabilities

3,856

Total lease liability

$
4,951

Lease incentives:

Prepaid expenses and other current assets (contra-asset)

$
(213
)
Other assets (contra-asset)

(795
)
Total lease incentives

$
(1,008
)

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.

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

Revenue Recognition. We recognize revenue from the sale of crude oil, ~~NGLs,~~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 ~~Net~~Income (loss) ~~income~~ before income tax (benefit) expense. In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net ~~Cash Used~~cash provided by operating activities and Net cash used in ~~Investing Activities~~investing activities sections, of which did not change the total ~~amount~~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):

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Derivative assets ⁽¹⁾	$	16,959	$	60,687	$	23,150	$	60,687
Unamortized bond/insurance premiums		4,944		5,197		5,497		5,197
Prepaid deposits related to royalties		8,871		8,872		8,794		8,872
Other		3,353		1,650		2,780		1,650
Prepaid expenses and other assets	$	34,127	$	76,406	$	40,221	$	76,406

(1)

Includes closed contracts which have not yet settled.

2.	Long-Term Debt

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

March 31,

December 31,

2019

2018

Credit Agreement ⁽¹⁾ borrowings
$
21,000

$
21,000

Senior Second Lien Notes: ⁽¹⁾

Principal

625,000

625,000

Unamortized debt issuance costs

(11,995
)

(12,465
)
Total Senior Second Lien Notes ⁽¹⁾

613,005

612,535

Total long-term debt
$
634,005

$
633,535

	September 30,			December 31,
	2019			2018
Credit Agreement borrowings	$	105,000		$	21,000

Senior Second Lien Notes:
Principal		625,000			625,000
Unamortized debt issuance costs		(11,051	)		(12,465	)
Total Senior Second Lien Notes		613,949			612,535

Total long-term debt	$	718,949		$	633,535

~~(1)~~

~~Defined below~~

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

Credit Agreement

On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (the “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 ~~March 31,~~September 30, 2019 and December 31, 2018, we had ~~$8.1~~$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 ~~3.50 to 1.00 for March 31, 2019;~~ 3.25 to 1.00 for ~~quarters~~the quarter 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 (which includes our August 2019 acquisition of the Mobile Bay properties described in Note 7), 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~~properties constituting at least 85% of ~~our oil and natural gas properties~~the total proved reserves of the Company as set forth on reserve reports required to be delivered under the Credit Agreement and certain personal property. The annualized interest rate on borrowings outstanding for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 ~~was~~was 5.1%, ~~which~~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~~Notes is 10.3%, ~~which~~which includes amortization of debt issuance costs. Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each ~~year, beginning on May 1, 2019.~~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 entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).~~Indenture. These covenants are subject to exceptions and qualifications set forth in the Indenture. In addition, most of the above described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Senior Second Lien Notes an investment grade rating and no default exists with respect to the Senior Second Lien Notes.

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

Covenants

~~Covenants~~

As of ~~March 31,~~September 30, 2019, we were in compliance with all applicable covenants of the Credit Agreement and ~~Senior Second Lien Notes indenture.~~the Indenture.

Fair Value Measurements

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

3. ~~Fair Value Measurements~~

Table of Contents

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):

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Assets:
Derivatives instruments - open contracts	$	20,275	$	74,580	$	21,965	$	74,580

4.	Joint Venture Drilling Program

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~~certain 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 ~~March 31,~~September 30, 2019, members of Monza made partner capital ~~contribution payments~~contributions, including our initial contributions of working interest in the drilling projects, to Monza totaling ~~$184.9~~$282.2 million, of which ~~$70.2~~$125.5 million was contributed during the ~~three~~nine months ended ~~March 31,~~September 30, 2019. Our net contribution to Monza, reduced by distributions received, as of ~~March 31,~~September 30, 2019 was ~~$58.9~~$61.4 million. W&T ~~may be~~is obligated to fund certain cost overruns to the extent they occur, 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. Through September 30, 2019, there have not been any events or changes that would cause a redetermination of the variable interest status. We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interests in the Monza properties. As of ~~March 31,~~September 30, 2019, in the Condensed Consolidated Balance Sheet, we recorded ~~$11.0~~$16.8 million, net, in Oil and natural gas properties and other, net, ~~$3.3~~$3.7 million in Other assets and ~~$5.0~~$3.6 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 ~~three~~nine months ended ~~March 31,~~September 30, 2019, we recorded ~~$1.6~~$7.4 million in Total revenues and ~~$0.9~~$4.6 million in Operating costs and expenses in connection with our proportional interest in Monza’s operations. ~~No revenues or expenses were recorded in~~For the ~~three~~nine months ended ~~March 31,~~September 30, 2018, we recorded $2.2 million in Total revenues, $1.1 million in Operating costs and expenses and $0.3 million, net, in Other (income) expense, net in connection with our proportional interest in Monza’s operations.

Additionally, during the ~~three-months~~nine months ended ~~March 31,~~September 30, 2019, we called on Monza to provide, and received, ~~cash calls from Monza of $66.3~~$123.5 million to fund JV Drilling Program projects, of which ~~$65.2~~$36.5 million is included in the Condensed Consolidated Balance Sheet in Advances from joint interest partners as of ~~March 31,~~September 30, 2019.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

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

(Unaudited)

5.	Asset Retirement Obligations

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):

Balance, December 31, 2018	$	310,137
Balances, December 31, 2018				$	310,137
Liabilities settled		(254	)		(7,740	)
Accretion of discount		4,588			14,086
Liabilities assumed through purchase					21,619
Liabilities incurred		44			426
Revisions of estimated liabilities		(353	)		5,967
Balance, March 31, 2019		314,162
Balances, September 30, 2019					344,495
Less current portion		24,799			23,095
Long-term	$	289,363		$	321,400

6.	Derivative Financial Instruments

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 ~~were~~are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”). The natural gas contracts ~~are~~were based on Henry Hub natural gas prices as quoted off the ~~NYMEX.~~NYMEX and expired during the second quarter of 2019. The open contracts as of ~~March 31,~~September 30, 2019 are presented in the following tables:

Crude Oil: Swap, Priced off WTI (NYMEX)	Crude Oil: Swap, Priced off WTI (NYMEX)							Crude Oil: Swap, Priced off WTI (NYMEX)
Termination Period		Notional Quantity (Bbls/day) ⁽¹⁾		Notional Quantity (Bbls) ⁽¹⁾		Strike Price			Notional Quantity (Bbls/day) (1)	Notional Quantity (Bbls) (1)	Strike Price
May 2020			1,500		640,500	$	60.80		1,500	366,000	$	60.80
May 2020			5,000		2,135,000		61.00		5,000	1,220,000		61.00
May 2020			3,500		1,494,500		60.85		3,500	854,000		60.85

(1)

Bbls = Barrels

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Natural Gas: Two-way collars, Priced off Henry Hub (NYMEX)

Termination Period

Notional Quantity (MMBtu/day) ⁽¹⁾

Notional Quantity (MMBtu) ⁽¹⁾

Put Option
Strike Price
(Bought)

Call Option
Strike Price
(Sold)

June 2019

50,000

3,050,000

$
2.49

$
3.975

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

~~(1)~~

~~MMBtu – Million British Thermal Units~~

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):

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Prepaid expenses and other assets	$	16,959	$	60,687	$	23,150	$	60,687
Other assets (non-current)		4,169		21,275		—		21,275

Three Months Ended

March 31,

2019

2018

Derivative loss
$
48,886

$
—

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019		2018
Derivative (gain) loss	$	(5,853	)	$	(288	)	$	41,228	$	5,931

Three Months Ended

March 31,

2019

2018

Cash receipts on derivative settlements, net
$
11,948

$
—

	Nine Months Ended September 30,
	2019		2018
Cash receipts (payments) on derivative settlements, net	$	17,583	$	(3,091	)

7.	Oil and Gas Property Acquisitions and Divestiture

Mobile Bay 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 offshore Alabama and a related processing facility for $200.0 million. On August 30, 2019, we closed on the purchase with ExxonMobil, and after taking into account customary closing adjustments and an effective date of January 1, 2019, cash consideration paid by us was $167.6 million, including a previously-funded $10.0 million deposit. The transaction is referred to as the "Mobile Bay Acquisition". The acquisition was funded from cash on hand and borrowings under the Credit Agreement, which was previously undrawn. We also assumed the related ARO and certain other obligations associated with these assets. The properties include working interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing properties owned and operated by us.

We determined that the assets acquired did not meet the definition of a business under GAAP; therefore, the transaction was accounted for as an asset acquisition. The recorded values were determined using the cash paid to the seller and expenses incurred related to the transaction. Values for the liabilities assumed for ARO and certain other obligations were determined using the same methodology used to estimate other similar obligations of the Company. The components of the cash paid to the seller at closing and the amounts recorded on the Condensed Consolidated Balance Sheet for the purchase price allocation and liabilities assumed are presented in the following tables (in thousands):

Cash paid to seller at close date:
Cash on hand	$	7,569
Performance deposit previously funded		10,000
Cash funded by the Credit Agreement (increase in long-term debt)		150,000
Total - cash paid to seller	$	167,569

	August 30, 2019 (Close Date)
Oil and natural gas properties and other, net - at cost:	$	191,450
Other assets		4,838

Current liabilities		2,819
Asset retirement obligations		21,619
Other liabilities		4,132

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W&T OFFSHORE, INC. AND SUBSIDIARIES

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

(Unaudited)

7. ~~Share-Based Compensation~~Heidelberg Field

On April 5, 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and ~~Cash-Based Incentive Compensation~~904. The gross purchase price was $31.1 million which was adjusted for certain closing items and an effective date of January 1, 2018. Cash flows generated by the acquired interest between the effective date and the closing date reduced the net purchase price to $16.8 million. We determined that the assets acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition.

Permian Basin

On September 28, 2018, we closed on the divestiture of substantially all of our ownership in an overriding royalty interests in the Permian Basin. The net proceeds received were $56.6 million, which was recorded as a reduction to our full-cost pool.

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 non-lease 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. We identified no finance leases. The implementation of ASU 2016-02 resulted in establishing an ROU asset and lease liability of $5.0 million during the first quarter of 2019. 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.

During the nine months ended September 30, 2019, various pipeline rights-of-way contracts and a land lease were acquired, assumed, renewed or otherwise entered into, primarily in conjunction with the Mobile Bay Acquisition. For these contracts, an ROU asset and a corresponding lease liability was calculated based on our assumptions of the term, inflation rates and incremental borrowing rates. The term of each pipeline right-of-way contract is 10 years with various effective dates, and each has an option to renew for up to another ten years. It is expected renewals beyond 10 years can be obtained as renewals were granted to the previous lessees. The land lease has an option to renew every five years extending to 2085. The expected term of the rights-of way and land leases was estimated to approximate the life of the related reserves.

Minimum future lease payments were estimated assuming expected terms of the leases and estimated inflation escalations of payments for certain leases. Undiscounted future minimum payments as of September 30, 2019 are as follows: 2019 - $0.8 million; 2020 - $1.9 million; 2021 - $1.9 million; 2022 - $2.0 million; 2023 - $0.5 million; and 2024 and beyond - $13.2 million. During the nine months ended September 30, 2019 and 2018, expense recognized related to these leases was $2.0 million for each period.

As of September 30, 2019, we recorded ROU assets and lease liabilities using a discount rate of 9.75% for the Houston office lease and 10.75% for the other leases. 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 Houston office lease. For the other lease contracts, a higher discount rate was used as the incremental borrowing rate due to longer expected termination dates. The expected terms of the leases ranged between three and 20 years, with no early terminations assumed.

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

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

	September 30, 2019
ROU (net):
Other assets	$	10,239

Lease liability:
Accrued liabilities	$	1,877
Other liabilities		7,883
Total lease liability	$	9,760

Lease incentives:
Other assets (contra-asset)	$	(907	)

During the nine months ended September 30, 2019, we incurred short-term lease costs related to drilling rigs of $13.3 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 non-lease and lease components for these short-term leases.

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 ~~were~~may be used as a short-term and long-term compensation ~~component~~components of the ~~2018~~ awards, and ~~were~~are subject to satisfaction of certain predetermined performance criteria.

As of ~~March 31,~~September 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~~are 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 ~~which~~ were subject to predetermined performance criteria applied against the applicable performance period. ~~These~~All the RSUs ~~continue to be~~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.

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 ~~three~~nine months ended ~~March 31,~~September 30, 2019 is as follows:

	Restricted Stock Units					Restricted Stock Units
				Weighted Average					Weighted Average
				Grant Date Fair					Grant Date Fair
	Units			Value Per Unit		Units			Value Per Unit
Nonvested, December 31, 2018		3,355,917		$	3.90		3,355,917		$	3.90
Granted							990,608			4.51
Forfeited ⁽¹⁾		(856,718	)		2.77		(1,075,864	)		3.12
Nonvested, March 31, 2019		2,499,199			4.28
Nonvested, September 30, 2019							3,270,661			4.34

(1)

Primarily related to a former ~~executive’s~~executives' forfeitures.

	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, September 30, 2019		123,180			4.55

(1)

For the nine months ended September 30, 2019, ~~period, the net credit is due to a~~share-based compensation expense includes adjustments for former ~~executive’s~~executives' forfeitures.

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 short-term, 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 short term, cash-based awards were paid during March 2018.

10.	Income Taxes

8. ~~Income Taxes~~

~~Our~~Tax Benefit and Tax Rate. We recorded an income tax ~~expense~~benefit of $55.5 million and $67.0 million for the three and nine months ended September 30, 2019, respectively. During the three months ended ~~March 31,~~September 30, 2019, ~~and 2018~~we released a portion of the valuation allowance on our net deferred tax assets based on the Company’s quarterly assessment of the realizability of net deferred tax assets, resulting in an income tax benefit of $55.8 million. During the nine months ended September 30, 2019, we reversed a liability related to an uncertain tax position that was ~~$0.2 million and $0.1 million, respectively.~~effectively settled with the Internal Revenue Service ("IRS"), resulting in an income tax benefit of $11.5 million. Our effective tax rate was not meaningful for the periods presented ~~as we continue~~due to ~~record a full valuation allowance on net deferred tax assets.~~ these changes.

~~During the three months ended March 31, 2019 and 2018, we did not receive any income tax refunds or make any income tax payments of significance.~~

~~As of March 31, 2019 and December 31, 2018, our valuation allowance was $127.8 million and $117.8 million, respectively, related to net federal and state deferred tax assets.~~ Valuation Allowance. Net deferred tax assets ~~were recorded related~~relate to net operating ~~losses~~loss carryforwards, interest expense carryforwards and other 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 federal and state tax jurisdictions in which those temporary differences ~~or net operating losses~~ are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of ~~them~~our deferred tax assets will not be realized. At December 31, 2018, our valuation allowance was $117.8 million, which offset substantially all net deferred tax assets as of such date.

Throughout 2019, the Company has been in a cumulative three year pre-tax income position and has been assessing the realizeability of our deferred tax assets. During the quarter ended September 30, 2019, the Company’s assessment included consideration of the Company’s operating history and our forecasted taxable income using all available information. Based on the assessment, we determined that the Company’s ability to maintain long-term profitability despite near-term changes in commodity prices and capital and operating costs demonstrated that a portion of the Company’s net deferred tax assets would more likely than notbe realized. We released $55.8 million of the valuation allowance, resulting in an income tax benefit in the quarter ended September 30, 2019. As of ~~March 31,~~September 30, 2019, the Company’s valuation allowance was $62.9 million.

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

Income Taxes Receivable. As of September 30, 2019 and December 31, 2018, we had current income taxes receivable of $36.9 million and $54.1 million, ~~which~~respectively, related 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~~(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~~During the three and nine months ended September 30, 2019, we received $16.9 million in income tax refunds. During the same periods, we recorded interest income of $0.5 million and $4.5 million related to these income tax claims, ~~require a review by~~respectively. During October 2019, we received $34.9 million in additional income tax refunds in addition to the ~~Congressional Joint Committee on Taxation which~~$4.5 million in interest income and we expect to receive the remaining balance of claims of approximately $2.0 million in ~~2019.~~the first half of 2020.

During the three and nine months ended September 30, 2018, we did not receive any income tax claims or make any income tax payments of significance.

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

11.	Earnings Per Share

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

Three Months Ended

March 31,

2019

2018

Net (loss) income
$
(47,761
)

$
27,640

Less portion allocated to nonvested shares

—

1,145

Net (loss) income allocated to common shares
$
(47,761
)

$
26,495

Weighted average common shares outstanding

140,462

138,845

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

$
0.19

Shares excluded due to being anti-dilutive (weighted-average)

3,342

—

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net income	$	75,899	$	46,260	$	64,527	$	109,983
Less portion allocated to nonvested shares		1,345		1,860		1,272		4,489
Net income allocated to common shares	$	74,554	$	44,400	$	63,255	$	105,494
Weighted average common shares outstanding		140,567		138,972		140,520		138,917

Basic and diluted earnings per common share	$	0.53	$	0.32	$	0.45	$	0.76

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

12.	Contingencies

~~10.~~ ~~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. ~~Oral arguments occurred on December 4, 2018, but as the filing date~~On July 16, 2019, a panel of ~~this Form 10-Q, a decision had not been rendered by~~ the U.S. Court of Appeals for the Fifth ~~Circuit.~~ Circuit rendered its opinion that affirmed the trial court's judgment against the Company. R

equests for rehearing and rehearing en banc subsequently were denied. The deposit ~~of $49.5 million~~ with the registry of the court iswas distributed during the third quarter of 2019 pursuant to an agreement with Apache, which does not hinder the Company's continuing right to seek United States Supreme Court review. The Company intends to pursue vigorously all available legal recourse.

As funds were distributed during the third quarter of 2019, no amounts were recorded in ~~Other assets (long-term)~~ on the Condensed Consolidated Balance ~~Sheets~~Sheet as of ~~March 31,~~September 30, 2019 ~~and December 31, 2018. Although we are appealing the decision, based solely~~related to this matter. Interest income of $1.9 million was recorded in Interest expense, net on the ~~decision rendered, we have recorded~~Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2019. The deposit of $49.5 million made with the registry of the court was recorded in Other assets (long-term) and $49.5 million was recorded in Other liabilities (long-term) on the Condensed Consolidated Balance ~~Sheets~~Sheet as of ~~March 31, 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;~~disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which 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.~~ 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. Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log. The government recently provided that privilege log and we are evaluating whether to move to compel production of any of the documents listed on the log. After these issues concerning the record are resolved, the parties will file cross-motions for summary judgment.

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

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 ~~March 31,~~September 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 oral argument was held on October 9, 2019, and ~~oral arguments, if held,~~we are ~~expected to be completed in 2019.~~

awaiting a final ruling from the Fifth Circuit. Based on the briefs filed, W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)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 ~~three~~nine months ended ~~March 31,~~September 30, 2019 and 2018, we paid ~~$0.1~~$0.4 million and ~~$0.1~~$0.6 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 ~~three~~nine months ended ~~March 31,~~September 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 ~~March 31,~~September 30, 2019 and December 31, 2018, we have accrued approximately ~~$3.4~~$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.

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.

Table of Contents

Three Months Ended

March 31,

2019

2018

Change

%

(In thousands, except percentages and per share data)

Financial:

Revenues:

Oil
$
86,703

$
97,306

$
(10,603
)

(10.9
)%
NGLs

6,448

9,660

(3,212
)

(33.3
)%
Natural gas

21,838

25,867

(4,029
)

(15.6
)%
Other

1,091

1,380

(289
)

(20.9
)%
Total revenues

116,080

134,213

(18,133
)

(13.5
)%
Operating costs and expenses:

Lease operating expenses

43,456

36,843

6,613

17.9
%
Production taxes

416

455

(39
)

(8.6
)%
Gathering and transportation

6,423

5,057

1,366

27.0
%
Depreciation, depletion, amortization and accretion

33,766

38,081

(4,315
)

(11.3
)%
General and administrative expenses

14,109

15,038

(929
)

(6.2
)%
Derivative loss

48,886

—

48,886

NM

Total costs and expenses

147,056

95,474

51,582

54.0
%
Operating (loss) income

(30,976
)

38,739

(69,715
)

NM

Interest expense, net

16,282

10,962

5,320

48.5
%
Other expense, net

331

28

303

NM

(Loss) income before income tax expense

(47,589
)

27,749

(75,338
)

NM

Income tax expense

172

109

63

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

$
27,640

$
(75,401
)

NM

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

$
0.19

$
(0.53
)

NM

(1)

The conversion to ~~Boe~~barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to ~~rounding.~~

rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2)

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

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

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Three Months Ended ~~March 31,~~September 30, 2019 Compared to the Three Months Ended ~~March 31,~~September 30, 2018

The Mobile Bay Acquisition will have an effect on our results of operations and these effects are not fully reflected in the following results of operations for the three months ended September 30, 2019 since the acquisition was not completed until the end of August 2019.

Revenues. Total revenues decreased ~~$18.1~~$21.2 million, or ~~13.5%~~13.8%, to ~~$116.1~~$132.2 million for the three months ended ~~March 31,~~September 30, 2019 as compared to the three months ended ~~March 31,~~September 30, 2018. Oil revenues decreased ~~$10.6~~$16.7 million, or ~~10.9%~~14.0%, NGLs revenues decreased ~~$3.2~~$5.7 million, or ~~33.3%~~56.6%, natural gas revenues ~~decreased $4.0~~increased $1.0 million, or ~~15.6%~~4.6%, and other revenues ~~decreased $0.3~~increased $0.1 million. The decrease in oil revenues was attributable to a ~~6.2%~~14.8% decrease in the average realized sales price to ~~$58.66~~$59.24 per barrel for the three months ended ~~March 31,~~September 30, 2019 from ~~$62.52~~$69.57 per barrel for the three months ended ~~March 31,~~September 30, 2018, ~~and~~partially offset by a 1.0% increase sales volumes ~~decreased 5.1%~~. The decrease in NGLs revenues was attributable to a ~~24.2%~~51.3% decrease in the average realized sales price to ~~$20.88~~$15.45 per barrel for the three months ended ~~March 31,~~September 30, 2019 from ~~$27.54~~$31.70 per barrel for the three months ended ~~March 31,~~September 30, 2018 and an 11.0% decrease in sales ~~volumes decreased 12.0%.~~volumes. The ~~decrease~~increase in natural gas revenues was attributable to a ~~decrease~~33.6% increase in sales volumes, ~~of 1.2 billion cubic feet (“Bcf”), or 14.5% and~~partially offset by a ~~1.0%~~21.8% decrease in the average realized price to ~~$3.00~~$2.23 per Mcf for the three months ended ~~March 31,~~September 30, 2019 from ~~$3.03~~$2.85 per Mcf for the three months ended ~~March 31,~~September 30, 2018. Overall, production volumes ~~decreased 9.8%~~increased 12.7% on a Boe basis. The largest production increases for the three months ended ~~March 31,~~September 30, 2019 compared to the three months ended ~~March 31,~~September 30, 2018 were from ~~our interest in~~ the ~~Heidelberg field, which was acquired in April 2018, and increases in production at our~~Mobile Bay Acquisition, Ship Shoal 349 (Mahogany) field, ~~(Mahogany).~~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 ~~planned~~weather and repair and maintenance ~~well servicing and rig movements~~issues at certain platforms and third-party pipelines. Our estimate of deferred production for the three months ended ~~March 31,~~September 30, 2019 was ~~approximately 7,200~~approximately 5,500 Boe per day as compared to ~~4,200~~4,100 Boe per day for the three months ended March 31, 2018, which comprises 83% of the production volume variance between the two periods. In April 2019, a majority of the pipeline and facility maintenance was completed and improved well performance and continued ramp up of new wells enabled the mid-April production rate to increase to over 37,000 Boe/day. September 30, 2018.

Revenues from oil and NGLs as a percent of our total revenues were ~~80.2%~~81.0% for the three months ended ~~March 31,~~September 30, 2019 compared to ~~79.7%~~84.4% for the three months ended ~~March 31,~~September 30, 2018. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to ~~35.6%~~26.1% for the three months ended ~~March 31,~~September 30, 2019 compared to ~~44.0%~~45.6% for the three months ended ~~March 31,~~September 30, 2018. Revenues from the Mobile Bay Acquisition consist primarily of revenues from sales of natural gas and NGLs.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased ~~$6.6~~$9.8 million, or ~~17.9%~~26.1%, to ~~$43.5~~$47.2 million infor the three months ended ~~March 31,~~September 30, 2019 compared to the three months ended ~~March 31,~~September 30, 2018. On a component basis, base lease operating ~~expenses~~expenses increased ~~$1.4~~$5.6 million, workover expenses increased ~~$2.3~~$2.6 million and facilities maintenance ~~expense~~expenses increased ~~$2.9~~$1.6 million. Base lease operating expenses increased primarily due to the ~~addition of the Heidelberg field interest, acquired~~Mobile Bay Acquisition, and to a lesser extent, increases in ~~April 2018,~~transportation and ~~had base lease operating~~contract labor expenses ~~of $1.7 million for the three months ended March 31, 2019.~~at certain fields. The increase in workover expense was primarily due to ~~2019 projects at our Mahogany field. The facility maintenance expense increase was primarily attributable to work performed in 2019~~project expenses at our Mahogany field, ~~combined with multiple~~which were partially offset by lower project expenses incurred at other fields. The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Matterhorn field.

Gathering and transportation. Gathering and transportation expenses increased ~~$1.4~~$0.2 million to ~~$6.4~~$6.0 million for the three months ended ~~March 31,~~September 30, 2019 compared to the three months ended ~~March 31,~~September 30, 2018 primarily related to the ~~East Cameron 321 field due to a change in our customer where transportation costs were separately billed and recorded as such beginning in~~acquisition of the ~~second half of 2018, and are offset by higher realized prices recorded for crude oil. In addition, expenses increased due to the Heidelberg field.~~ Mobile Bay Acquisition.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, decreased to ~~$11.25~~$10.26 per Boe for the three months ended ~~March 31,~~September 30, 2019 from ~~$11.44~~$11.01 per Boe for the three months ended ~~March 31, 2018.~~September 30, 2018 primarily due to the Mobile Bay Acquisition, which the related incremental costs and related incremental reserves produced a lower rate per Boe than the historical full-cost pool rate per Boe. On a nominal basis, DD&A ~~decreased~~increased to ~~$33.8~~$38.8 million (or ~~11.3%~~5.1%) for the three months ended ~~March 31,~~September 30, 2019 from ~~$38.1~~$37.0 million for the three months ended ~~March 31,~~September 30, 2018. DD&A on a nominal basis ~~decreased~~increased primarily due to ~~lower~~increased production. ~~Other factors~~Factors affecting the DD&A rate are ~~production,~~ capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

General and administrative expenses (“G&A”). G&A was ~~$14.1~~$10.1 million for the three months ended ~~March 31,~~September 30, 2019, decreasing ~~6.2%~~36.8% from ~~$15.0~~$16.0 million for the three months ended ~~March 31,~~September 30, 2018. The decrease was primarily due to ~~a decrease in incentive compensation.~~increased charges (credits) to counterparties related to joint interest arrangements and lower compensation expenses. G&A on a per Boe basis was ~~$4.70~~$2.67 per Boe for the three months ended ~~March 31,~~September 30, 2019 compared to ~~$4.52~~$4.76 per Boe for the three months ended ~~March 31,~~September 30, 2018.

Derivative ~~loss.~~ gain. The three months ended ~~March 31,~~September 30, 2019 reflects a ~~$48.9~~$5.8 million derivative ~~loss~~gain primarily due to ~~increased~~decreased crude oil ~~prices during March~~future pricing used to value our derivative contracts at September 30, 2019 as compared to ~~oil prices during December 2018,~~June 30, 2019, which ~~decreased~~increased the estimated fair value of our open crude oil contracts between the two measurement dates. For the three months ended ~~March 31,~~September 30, 2018, we ~~did not have any gains or losses~~recorded a net gain of $0.3 million from derivative contracts.

Interest expense, net. Interest expense, net, was ~~$16.3~~$14.4 million and ~~$11.0~~$10.7 million for the three months ended ~~March 31,~~September 30, 2019 and 2018, respectively, which includes netting of interest income of $2.7 million and $0.9 million, respectively. During the three months ended September 30, 2019, interest income of $1.9 million was recorded due to the distribution of funds related to the Apache lawsuit. During the three months ended September 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 ~~March 31,~~September 30, 2018 and affects the comparability.

Income tax (benefit) expense. Our income tax benefit for the three months ended September 30, 2019 was $55.5 million and our income tax expense for the three months ended ~~March 31, 2019 and~~September 30, 2018 was ~~$0.2 million and~~ $0.1 ~~million, respectively.~~million. We partially reversed a valuation allowance related to our deferred tax assets resulting in a non-cash tax benefit for the three months ended September 30, 2019. Immaterial deferred income tax expense was recorded for the three months ended ~~March 31, 2019~~September 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 March 31, 2019, our valuation allowance was $127.8 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 810 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

The Mobile Bay Acquisition will have an effect on our results of operations and these effects are not fully reflected in the following results of operations for the nine months ended September 30, 2019 since the acquisition was not completed until the end of August 2019.

Revenues. Total revenues decreased $54.3 million, or 12.4%, to $383.0 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Oil revenues decreased $34.7 million, or 10.4%, NGLs revenues decreased $13.0 million, or 45.7%, natural gas revenues decreased $6.4 million, or 8.9%, and other revenues decreased $0.1 million. The decrease in oil revenues was attributable to an 8.3% decrease in the average realized sales price to $61.00 per barrel for the nine months ended September 30, 2019 from $66.52 per barrel for the nine months ended September 30, 2018 and a 2.3% decrease in sales volumes. The decrease in NGLs revenues was attributable to a 37.5% decrease in the average realized sales price to $18.07 per barrel for the nine months ended September 30, 2019 from $28.91 per barrel for the nine months ended September 30, 2018 and a 13.1% decrease in sales volumes. The decrease in natural gas revenues was attributable to an 11.4% decrease in the average realized price to $2.57 per Mcf for the nine months ended September 30, 2019 from $2.90 per Mcf for the nine months ended September 30, 2018 and partially offset by a 2.8% increase in sales volumes. Overall, production volumes decreased 1.3% on a Boe basis. The largest production increases for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 were from the Mobile Bay Acquisition, Mahogany field, Ship Shoal 028 field and Fairway field. Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to weather and repair and maintenance issues at certain platforms and pipelines. Our estimate of deferred production for the nine months ended September 30, 2019 was approximately 5,900 Boe per day as compared to 4,300 Boe per day for the nine months ended September 30, 2018.

Revenues from oil and NGLs as a percent of our total revenues were 82.0% for the nine months ended September 30, 2019 compared to 82.8% for the nine months ended September 30, 2018. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 29.6% for the nine months ended September 30, 2019 compared to 43.5% for the nine months ended September 30, 2018. Revenues from the Mobile Bay Acquisition consist primarily of revenues from sales of natural gas and NGLs.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $21.1 million, or 19.2%, to $131.0 million in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. On a component basis, base lease operating expenses increased $8.9 million, facilities maintenance expense increased $7.9 million and workover expenses increased $4.3 million. Base lease operating expenses increased primarily due to the Mobile Bay Acquisition and to the addition of the Heidelberg field, acquired in April 2018. In addition, base lease operating expenses increased due to lower charges to joint interest partners at our Mississippi Canyon 243 ("Matterhorn") field, which are recorded as credits to expense. 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 $3.7 million, or 23.4%, to $19.4 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The increase was primarily related to rate changes from certain third-party pipelines which became effective during the nine months ended September 30, 2019.

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, decreased to $11.09 per Boe for the nine months ended September 30, 2019 from $11.36 per Boe for the nine months ended September 30, 2018 primarily due to the Mobile Bay Acquisition, which the related incremental costs and related incremental reserves produced a lower rate per Boe than the previous full-cost pool rate per Boe. On a nominal basis, DD&A decreased to $110.7 million (or 3.6%) for the nine months ended September 30, 2019 from $114.8 million for the nine months ended September 30, 2018. DD&A on a nominal basis decreased primarily due to lower production. 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 $37.5 million for the nine months ended September 30, 2019, decreasing 17.0% from $45.2 million for the nine months ended September 30, 2018. The decrease was largely due to increased charges (credits) to counterparties related to joint interest arrangements, lower compensation expenses and lower premiums paid for surety bonds. G&A on a per Boe basis was $3.76 per Boe for the nine months ended September 30, 2019 compared to $4.48 per Boe for the nine months ended September 30, 2018.

Derivative loss. The nine months ended September 30, 2019 reflects a $41.2 million derivative loss primarily related to increased crude oil future pricing used to value our derivative contracts at September 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 nine months ended September 30, 2018, we recorded a net loss of $5.9 million from derivative contracts.

Interest expense, net. Interest expense, net, was $42.9 million and $33.5 million for the nine months ended September 30, 2019 and 2018, respectively, which includes netting of interest income of $7.5 million and $1.6 million, respectively. During the nine months ended September 30, 2019, we recorded interest income of $4.5 million related to income tax refunds and interest income of $1.9 million due to the distribution of funds related to the Apache lawsuit. During the nine months ended September 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 nine months ended September 30, 2019 was $67.0 million and our income tax expense for the nine months ended September 30, 2018 was $0.4 million. During the nine months ended September 30, 2019, we partially reversed a valuation allowance related to our deferred tax assets and we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, resulting in a non-cash tax benefit. Immaterial deferred income tax expense was recorded for the nine months ended September 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. 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 ~~property~~ acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, ~~make related interest payments~~operate our properties and satisfy our AROs. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings and expect to continue to do so in the future.

Credit Agreement. On October 18, 2018, we entered into the Credit Agreement, which matures on October 18, 2022. As of ~~March 31,~~September 30, 2019, we had ~~$21.0~~$105.0 million borrowings outstanding under the Credit Agreement and ~~$8.1~~$7.2 million of letters of credit issued ~~under the Credit Agreement. During the three months ended March 31, 2019, we did not have any additional borrowings or repayments~~ under the Credit Agreement. Availability under our Credit Agreement as of ~~March 31,~~September 30, 2019 was ~~$220.9~~$137.8 million.

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, ~~with the~~which was initially set at $250.0 million and has not changed. The next redetermination is scheduled to be completed ~~by May~~around 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 ~~March 31,~~September 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~~– 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 ~~March 31,~~September 30, 2019.

~~BOEM~~

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.~~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.~~ Capital. Net cash ~~provided~~provided by operating activities for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and 2018 was ~~$84.8~~$186.6 million and ~~$75.0~~$294.9 million, respectively. Our combined average realized sales price per Boe decreased ~~4.0%~~by 11.4% for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 compared to the ~~three~~nine months ended ~~March 31,~~September 30, 2018, which caused total revenues to decrease ~~$8.0~~$44.7 million. Production volumes decreased by ~~9.8%~~1.3% measured on a BOE basis primarily from increases in downtime, which caused revenues to decrease by ~~$9.8~~$9.4 million. In addition, operating expenses impacting operating cash flows increased by ~~$8.3~~$18.5 million primarily for base lease operating expense, workover projects and facility projects.

Other items affecting operating cash flows ~~was~~were an increase of ~~$44.6~~$15.8 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to ~~$19.1~~an increase of $27.0 million for the ~~three~~nine months ended ~~March 31, 2018.~~September 30, 2018; ARO settlements were ~~$0.3~~$15.0 million ~~for~~lower between the ~~three months ended March 31, 2019, which decreased from $7.0 million for the three months ended March 31, 2018. During the three months ended March 31, 2019,~~two periods; cash derivative receipts, net, ~~were $11.9~~increased $20.7 million between the two periods primarily due to derivative oil ~~contracts.~~contracts; and a tax refund of $16.9 million was received during the nine months ended September 30, 2019. Working capital items accounted for the balance of the change in net cash provided by operating activities.

Net cash used in investing activities primarily represents our acquisition of and investments in oil and gas properties and equipment partially offset by sales of such assets. Net cash used in investing activities for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and 2018 was ~~$31.6~~$261.2 million and ~~$41.3~~$45.7 million, ~~respectively, which represents our investments in oil and gas properties and equipment. The majority of our~~respectively. Our capital expenditures for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 were split approximately 40% for investments in the deep waters of the Gulf of Mexico and ~~to a lesser extent,~~approximately 60% for investments on the conventional shelf of the Gulf of Mexico. ~~There were no material acquisitions or asset sales~~During the nine months ended September 30, 2019, the cash expenditure for the Mobile Bay Acquisition was $167.7 million, which is described in the ~~three~~Overview section of this Item. During the nine months ended ~~March 31, 2019~~September 30, 2018, the purchase of the interest in the Heidelberg field was consummated for $16.8 million and ~~a deposit~~the sale of ~~$3.0 million was made during~~our overriding royalty interests in the ~~three~~Permian Basin fields resulted in net proceeds of $50.5 million.

Net cash provided by financing activities for the nine months ended ~~March 31, 2018 related~~September 30, 2019 was $83.1 million. The net cash provided for the nine months ended September 30, 2019 included borrowings of $150.0 million under the Credit Agreement that were made to fund a portion of the ~~Heidelberg acquisition consummated in April 2018.~~

Mobile Bay Acquisition, and repayments of $66.0 million were made reducing the borrowings outstanding under the Credit Agreement. Net cash used by financing activities for the ~~three~~nine months ended ~~March 31, 2019 and~~September 30, 2018 ~~respectively~~ was ~~$0.4~~$9.1 million ~~and $2.1 million, respectively. The net cash used for the three months ended March 31, 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, ~~2018.~~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 ~~we expect to renew~~ 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 ~~three~~nine months ended ~~March 31,~~September 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):

	Three Months Ended
	March 31,					Nine Months Ended September 30,
	2019		2018			2019		2018
Exploration ⁽¹⁾	$	4,251	$	2,718		$	15,262	$	27,406
Development ⁽¹⁾		17,269		30,907			77,273		41,071
Mobile Bay Acquisition							169,831		—
Heidelberg field							—		16,782
Reimbursement from Monza for 2017 expenditures		—		(14,075	)		—		(14,075	)
Seismic and other		9,113		1,567			13,528		4,759
Investments in oil and gas property/equipment	$	30,633	$	21,117		$	275,894	$	75,943

(1)

Reported geographically in the subsequent table.


*		Filed or Furnished herewith.

†	Management Contract or Compensatory Plan or Arrangement, filed herewith

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on ~~May 2,~~October 31, 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

	Three Months Ended						Nine Months Ended
	March 31,						September 30,
	2019			2018			2019			2018
Operating activities:
Net (loss) income	$	(47,761	)	$	27,640
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Net income							$	64,527		$	109,983
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		33,766			38,081			110,680			114,807
Amortization of debt items and other items		1,152			466			3,914			1,796
Share-based compensation		(78	)		1,219			2,429			3,808
Derivative loss		48,886			—			41,228			5,931
Cash receipts on derivative settlements, net		11,948			—
Deferred income taxes		172			109
Cash receipts (payments) on derivative settlements, net								17,583			(3,091	)
Income taxes								(55,764	)		363
Changes in operating assets and liabilities:
Oil and natural gas receivables		6,496			501			(3,822	)		(4,039	)
Joint interest receivables		(2,986	)		1,919			(15,850	)		3,261
Prepaid expenses and other assets		(4,269	)		(6,391	)		(14,211	)		(8,467	)
Income tax receivables								17,165			(139	)
Asset retirement obligation settlements		(254	)		(7,022	)		(7,740	)		(22,764	)
Cash advances from JV partners		44,644			19,147			15,847			27,014
Accounts payable, accrued liabilities and other		(6,871	)		(688	)		10,610			66,389
Net cash provided by operating activities		84,845			74,981			186,596			294,852
Investing activities:
Investment in oil and natural gas properties and equipment		(31,581	)		(38,271	)		(93,482	)		(79,422	)
Deposit for acquisition		—			(3,000	)
Acquisition of property interest								(167,718	)		(16,782	)
Proceeds from sale of assets								—			50,474
Purchases of furniture, fixtures and other								(20	)		—
Net cash used in investing activities		(31,581	)		(41,271	)		(261,220	)		(45,730	)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility								150,000			—
Repayments of long-term debt - revolving bank credit facility								(66,000	)		—
Payment of interest on 1.5 Lien Term Loan		—			(2,057	)		—			(6,171	)
Debt issuance costs		(441	)		—
Net cash used in financing activities		(441	)		(2,057	)
Payment of interest on 2nd Lien PIK Toggle Notes								—			(2,920	)
Debt issuance costs and other								(928	)		(26	)
Net cash provided by (used in) financing activities								83,072			(9,117	)
Increase in cash and cash equivalents		52,823			31,653			8,448			240,005
Cash and cash equivalents, beginning of period		33,293			99,058			33,293			99,058
Cash and cash equivalents, end of period	$	86,116		$	130,711		$	41,741		$	339,063

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Oil and natural gas properties and equipment	$	8,198,394	$	8,169,871	$	8,471,973	$	8,169,871
Furniture, fixtures and other		20,228		20,228		20,247		20,228
Total property and equipment		8,218,622		8,190,099		8,492,220		8,190,099
Less accumulated depreciation, depletion and amortization		7,703,857		7,674,678		7,771,269		7,674,678
Oil and natural gas properties and other, net	$	514,765	$	515,421	$	720,951	$	515,421

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Derivative assets		4,169		21,275
Appeal bond deposits		6,925		6,925	$	6,925	$	6,925
Unamortized debt issuance costs		4,511		4,773		4,138		4,773
Investment in White Cap, LLC		2,546		2,586		2,885		2,586
Unamortized brokerage fee for Monza		3,746		2,277		4,131		2,277
Proportional consolidation of Monza's other assets (Note 4)		3,299		3,275		3,660		3,275
Right-of Use (Note 8)						10,239		—
Escrow deposit - Apache lawsuit (Note 12)						—		49,500
Derivative assets						—		21,275
Other		4,309		936		886		936
Total other assets (long-term)	$	79,005	$	91,547	$	32,864	$	91,547

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Accrued interest	$	27,624	$	12,385	$	25,414	$	12,385
Accrued salaries/payroll taxes/benefits		2,425		2,320		2,267		2,320
Incentive compensation plans		—		10,817		3,667		10,817
Litigation accruals		3,673		3,673		3,673		3,673
Lease liability (Note 8)						1,877		—
Other		1,475		416		356		416
Total accrued liabilities	$	35,197	$	29,611	$	37,254	$	29,611

	Three Months Ended
	March 31,					Three Months Ended September 30,				Nine Months Ended September 30,
	2019			2018		2019		2018		2019		2018
Share-based compensation included in:
General and administrative expenses	$	(78	)	$	1,219	$	1,248	$	1,373	$	2,429	$	3,808
Cash-based incentive compensation included in:
Lease operating expense ⁽¹⁾		(123	)		860		672		837		951		2,240
General and administrative expenses ⁽¹⁾		2,095			2,672		1,679		1,534		5,017		5,597
Total charged to operating income	$	1,894		$	4,751	$	3,599	$	3,744	$	8,397	$	11,645

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

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

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

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

	March 31, 2019				December 31, 2018				September 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Credit Agreement	$	21,000	$	21,000	$	21,000	$	21,000	$	105,000	$	105,000	$	21,000	$	21,000
Senior Second Lien Notes		613,005		623,256		612,535		546,875		613,949		610,225		612,535		546,875

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. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed August 1, 2019 (File No. 001-32414)

10.2 *†		Form of Executive Annual Incentive Award Agreement for Fiscal Year 2019.

10.3 *†		Form of 2019 Executive Long Term Incentive Plan Agreement.

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.