10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2018

or

☐ 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.   ☐

As of October 31, 2018, there were 139,153,798 shares outstanding of the registrant’s common stock, par value $0.00001.

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I –FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	2
	Condensed Consolidated Statement of Changes in Shareholders’ Deficit for the Nine Months Ended September 30, 2018	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	51
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 6.	Exhibits	53
SIGNATURE		55

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	September 30,			December 31,
	2018			2017
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$	339,063		$	99,058
Receivables:
Oil and natural gas sales		49,482			45,443
Joint interest		16,493			19,754
Income taxes		65,240			13,006
Total receivables		131,215			78,203
Prepaid expenses and other assets (Note 1)		19,699			13,419
Total current assets		489,977			190,680
Oil and natural gas properties and other, net - at cost: (Note 1)		522,781			579,016
Restricted deposits for asset retirement obligations		20,577			25,394
Income taxes receivable		—			52,097
Other assets (Note 1)		69,014			60,393
Total assets	$	1,102,349		$	907,580
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	95,502		$	79,667
Undistributed oil and natural gas proceeds		34,225			20,129
Advances from joint interest partners		31,012			3,998
Asset retirement obligations		30,207			23,613
Current maturities of long-term debt: (Note 2)
Principal		189,829			—
Carrying value adjustments		34,985			22,925
Current maturities of long-term debt  - carrying value		224,814			22,925
Accrued liabilities (Note 1)		31,058			17,930
Total current liabilities		446,818			168,262
Long-term debt: (Note 2)
Principal		713,365			889,790
Carrying value adjustments		45,758			79,337
Long term debt, less current portion - carrying value		759,123			969,127
Asset retirement obligations, less current portion		283,009			276,833
Other liabilities (Note 1)		73,175			66,866
Commitments and contingencies (Note 11)		—			—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at    September 30, 2018 and December 31, 2017		—			—
Common stock, $0.00001 par value; 200,000,000 shares authorized;    142,022,971 issued and 139,153,798 outstanding at September 30, 2018 and    141,960,462 issued and 139,091,289 outstanding December 31, 2017		1			1
Additional paid-in capital		549,569			545,820
Retained earnings (deficit)		(985,179	)		(1,095,162	)
Treasury stock, at cost; 2,869,173 shares for both dates presented		(24,167	)		(24,167	)
Total shareholders’ deficit		(459,776	)		(573,508	)
Total liabilities and shareholders’ deficit	$	1,102,349		$	907,580

See Notes to Condensed Consolidated Financial Statements.

1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In thousands except per share data)
	(Unaudited)
Revenues:
Oil	$	119,482		$	78,055		$	333,406		$	248,648
NGLs		10,087			6,605			28,481			22,401
Natural gas		22,641			24,113			71,485			83,129
Other		1,249			1,508			3,912			3,819
Total revenues		153,459			110,281			437,284			357,997
Operating costs and expenses:
Lease operating expenses		37,430			35,134			109,855			106,817
Production taxes		432			340			1,326			1,304
Gathering and transportation		5,779			4,108			15,764			15,635
Depreciation, depletion, amortization and accretion		36,969			36,489			114,807			116,843
General and administrative expenses		15,990			15,631			45,248			45,379
Derivative (gain) loss		(288	)		2,879			5,931			(4,765	)
Total costs and expenses		96,312			94,581			292,931			281,213
Operating income		57,147			15,700			144,353			76,784
Interest expense		11,630			11,554			35,100			34,284
Gain on exchange of debt		—			—			—			7,811
Other (income) expense, net		(885	)		(41	)		(1,093	)		5,073
Income before income tax expense (benefit)		46,402			4,187			110,346			45,238
Income tax expense (benefit)		142			5,484			363			(11,079	)
Net income (loss)	$	46,260		$	(1,297	)	$	109,983		$	56,317
Basic and diluted earnings (loss) per common share	$	0.32		$	(0.01	)	$	0.76		$	0.39

See Notes to Condensed Consolidated Financial Statements.

2

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ DEFICIT

	Common Stock Outstanding				Additional Paid-In			Retained Earnings			Treasury Stock					Total Shareholders’
	Shares		Value		Capital			(Deficit)			Shares		Value			Deficit
	(In thousands)
	(Unaudited)
Balances at 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		—		—		(59	)		—			—		—			(59	)
Net income		—		—		—			109,983			—		—			109,983
Balances at September 30, 2018		139,154	$	1	$	549,569		$	(985,179	)		2,869	$	(24,167	)	$	(459,776	)

See Notes to Condensed Consolidated Financial Statements.

3

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
	2018			2017
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	109,983		$	56,317
Adjustments to reconcile net income to net cash provided by    operating activities:
Depreciation, depletion, amortization and accretion		114,807			116,843
Gain on exchange of debt		—			(7,811	)
Amortization of debt items and other items		1,796			1,271
Share-based compensation		3,808			5,449
Derivative (gain) loss		5,931			(4,765	)
Cash receipts (payments) on derivative settlements, net		(3,091	)		3,924
Deferred income taxes		363			321
Changes in operating assets and liabilities:
Oil and natural gas receivables		(4,039	)		3,906
Joint interest receivables		3,261			8
Insurance reimbursements		—			31,740
Income taxes		(139	)		320
Prepaid expenses and other assets		(8,467	)		2,194
Escrow deposit - Apache lawsuit		—			(49,500	)
Asset retirement obligation settlements		(22,764	)		(56,226	)
Cash advances from JV partners		27,014			(786	)
Accounts payable, accrued liabilities and other		66,389			27,115
Net cash provided by operating activities		294,852			130,320
Investing activities:
Investment in oil and natural gas properties and equipment		(59,161	)		(79,088	)
Changes in operating assets and liabilities associated with investing activities		(20,261	)		5,679
Acquisition of property interest		(16,782	)		—
Proceeds from sale of assets		50,474			—
Purchases of furniture, fixtures and other		—			(905	)
Net cash used in investing activities		(45,730	)		(74,314	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,171	)		(6,170	)
Payment of interest on 2nd Lien PIK Toggle Notes		(2,920	)		(7,335	)
Payment of interest on 3rd Lien PIK Toggle Notes		—			(6,201	)
Other		(26	)		(372	)
Net cash used in financing activities		(9,117	)		(20,078	)
Increase  in cash  and cash equivalents		240,005			35,928
Cash and cash equivalents, beginning of period		99,058			70,236
Cash and cash equivalents, end of period	$	339,063		$	106,164

See Notes to Condensed Consolidated Financial Statements.

4

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

1.  Basis of Presentation

Operations.  W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico.  The Company is active in the exploration, development and acquisition of oil and natural gas properties.  Our interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”) 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, 2017.

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.

Recent Events.  The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth.  The average realized prices of crude oil and NGLs improved during the nine months ended September 30, 2018 compared to the average realized prices in the nine months ended September 30, 2017.  

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”) which substantially changed our capital structure.  The Senior Second Lien Notes were issued at par and have a maturity date of November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “New Revolving Credit Agreement”) which provides us with a revolving bank credit facility with an initial borrowing base of $250.0 million (increasing from $150.0 million under our prior facility).  Letters of credit may be issued in amounts up to $30.0 million provided availability exists.  The New Revolving Credit Agreement matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  We refer to these transactions and the related repurchases and retirements, repayments and redemptions of all of our outstanding notes and term loans collectively as the “2018 Refinancing Transaction.”  See Note 12, Subsequent Events, for additional information.  

We believe we will have adequate available liquidity to fund our operations through November 2019, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or future Bureau of Ocean Energy Management (“BOEM”) bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

5

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

See our Annual Report on Form 10-K for the year ended December 31, 2017 concerning risks related to our business and events occurring during 2017 and other information and the Notes herein for additional information.  

Accounting Standard Updates Effective January 1, 2018:

   Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018.  The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business.  In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business.          

Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us in the period ending March 31, 2018.  We reviewed our contracts using the five-step revenue recognition model, which did not identify any changes required as to the amount or timing of revenue recognition.  We adopted the new standard using the modified retrospective approach which did not result in any cumulative-effect adjustment on the date of adoption.  The implementation of ASU 2014-09 resulted in a change in our reporting in the Condensed Consolidated Statement of Operations so that we now report revenue streams separately for crude oil, NGLs, natural gas and other revenues in compliance with the new standard.     

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

Reclassification.  Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows:  Within the Net Cash Provided by Operating Activities of the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items, of which did not change the total amount previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets or the Condensed Consolidated Statements of Operations.

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

	September 30,		December 31,
	2018		2017
Prepaid/accrued insurance	$	4,214	$	2,401
Surety bond unamortized premiums		2,847		2,676
Prepaid deposits related to royalties		9,698		6,456
Advances for capital expenditures		860		—
Derivative contract premiums		791		—
Other		1,289		1,886
Prepaid expenses and other assets	$	19,699	$	13,419

6

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

Oil and Natural Gas Properties and Other, Net – at cost.  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Oil and natural gas properties and equipment	$	8,146,742	$	8,102,044
Furniture, fixtures and other		20,227		21,831
Total property and equipment		8,166,969		8,123,875
Less accumulated depreciation, depletion    and amortization		7,644,188		7,544,859
Oil and natural gas properties and other, net	$	522,781	$	579,016

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

	September 30,		December 31,
	2018		2017
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Appeal bond deposits		6,925		6,925
Investment in White Cap, LLC		2,648		2,511
Deposit related to letters of credit		4,702		—
Unamortized brokerage fee for Monza		1,981		—
Proportional consolidation of Monza's    other assets  (Note 4)		2,212		—
Other		1,046		1,457
Total other assets	$	69,014	$	60,393

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

	September 30,		December 31,
	2018		2017
Accrued interest	$	15,041	$	4,200
Accrued salaries/payroll taxes/benefits		2,291		2,454
Incentive compensation plans		6,452		7,366
Litigation accruals		3,604		3,480
Derivative contracts		3,252		84
Other		418		346
Total accrued liabilities	$	31,058	$	17,930

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

	September 30,		December 31,
	2018		2017
Apache lawsuit	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		11,379		11,015
Dispute related to royalty deductions		4,687		—
Dispute related to royalty-in-kind		2,100		914
Other		5,509		5,437
Total other liabilities (long-term)	$	73,175	$	66,866

7

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

Recent Accounting Developments.  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months.  Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a financing or operating lease.  However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space, which is primarily in Houston, Texas, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases nor do we have any leases recorded on the Condensed Consolidated Balance Sheets.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

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

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

8

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

2.  Long-Term Debt

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

	September 30, 2018								December 31, 2017
			Adjustments to								Adjustments to
			Carrying			Carrying					Carrying			Carrying
	Principal		Value (1)			Value			Principal		Value (1)			Value
11.00% 1.5 Lien Term Loan,      due November 2019:
Principal	$	75,000	$	—		$	75,000		$	75,000	$	—		$	75,000
Future interest payments		—		9,425			9,425			—		15,596			15,596
Subtotal		75,000		9,425			84,425			75,000		15,596			90,596
9.00 % Second Lien Term Loan,     due May 2020:		300,000		—			300,000			300,000		—			300,000
9.00%/10.75% Second Lien     PIK Toggle Notes, due May 2020:
Principal		177,513		—			177,513			171,769		—			171,769
Future payments-in-kind		—		—			—			—		5,745			5,745
Future interest payments		—		31,952			31,952			—		34,872			34,872
Subtotal		177,513		31,952			209,465			171,769		40,617			212,386
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		160,852		—			160,852			153,192		—			153,192
Future payments-in-kind		—		3,664			3,664			—		11,323			11,323
Future interest payments		—		38,682			38,682			—		38,682			38,682
Subtotal		160,852		42,346			203,198			153,192		50,005			203,197
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(2,980	)		(2,980	)		—		(3,956	)		(3,956	)
Total long-term debt		903,194		80,743			983,937			889,790		102,262			992,052
Current maturities of long-term debt (2)		189,829		34,985			224,814			—		22,925			22,925
Long term debt, less current    maturities	$	713,365	$	45,758		$	759,123		$	889,790	$	79,337		$	969,127

(1) Future interest payments and future payments-in-kind are recorded on an undiscounted basis.

(2) Represents principal of the 8.50% Unsecured Senior Notes due June 15, 2019 and future interest payments on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes due within twelve months.

9

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

Debt Issuance, Repayment of Long-Term Debt and the New Revolving Credit Agreement

As described in Note 12, Subsequent Events, on October 18, 2018, we issued the Senior Second Lien Notes and entered into the New Revolving Credit Agreement.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  

The following discussion and descriptions relate to our long-term debt as of September 30, 2018:  

Accounting for Certain Debt Instruments

We accounted for a transaction executed on September 7, 2016 as a Troubled Debt Restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the 9.00/ 10.75% Second Lien Payment-In-Kind (“PIK”) Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); the 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”) and the 11.00% 1.5 Lien Term Loan, due November 15, 2019 (the “1.5 Lien Term Loan”) (collectively, the “2016 Restructuring Transactions”) are measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the 2016 Restructuring Transactions in the Condensed Consolidated Statements of Operations for the periods presented.  Additionally, no interest expense related to the 2016 Restructuring Transactions will be recorded in the fourth quarter of 2018 as payments of interest on the 2016 Restructuring Transactions will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments.  Under ASC 470-60, payments related to the 2016 Restructuring Transactions are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.

The primary terms of our long-term debt are described below:    

Prior Credit Agreement.  The Fifth Amended and Restated Credit Agreement, (the “Prior Credit Agreement”) provided a revolving bank credit facility and would have expired by its term on November 8, 2018.  The primary items of the Prior Credit Agreement are as follows, with certain terms defined under the Prior Credit Agreement:

• The Borrowing Base of $150.0 million.

• Letters of credit limit of up to $150.0 million, provided availability under the revolving bank credit facility exists.      

• The First Lien Leverage Ratio limit of 2.00 to 1.00.

• The Current Ratio, as defined in the Prior Credit Agreement, was required to be greater than 1.00 to 1.00.

• Deposit accounts could only be established with banks under the Prior Credit Agreement with certain exceptions.

• We could not have unrestricted cash balances above $35.0 million if outstanding balances under the Prior Credit Agreement (including letters of credit) are greater than $5.0 million.

• To the extent there are borrowings, they were primarily executed as Eurodollar Loans, and the applicable margins range from 3.00% to 4.00%.

• The commitment fee was 50 basis points for all levels of utilization.

  As of September 30, 2018 and December 31, 2017, we did not have any borrowings outstanding under the Prior Credit Agreement and had $9.7 million and $0.3 million of letters of credit outstanding, respectively.  Available credit as of September 30, 2018 was $140.3 million.  As of September 30, 2018, we had on deposit $4.7 million with the lead bank in compliance with the terms of the Prior Credit Agreement, as letters of credit are considered borrowings and our unrestricted cash balance exceeded $35.0 million.  On October 18, 2018, the Prior Credit Agreement was replaced by the New Revolving Credit Agreement, as described in Note 12,Subsequent Events.  

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

1.5 Lien Term Loan.  In September 2016, we entered into the 1.5 Lien Term Loan with a maturity date of November 15, 2019.    Interest accrued at 11.00% per annum and is payable quarterly in cash.  The 1.5 Lien Term Loan was secured by a 1.5 priority lien on all of our assets pledged under the Prior Credit Agreement.  The lien securing the 1.5 Lien Term Loan was subordinated to the liens securing the Prior Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows as of September 30, 2018 have been included in the carrying value under ASC 470-60.  On October 18, 2018, the 1.5 Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.

Second Lien Term Loan.  In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which had an annual interest rate of 9.00%.  The Second Lien Term Loan was issued at a 1.0% discount to par with a maturity date of May 15, 2020 and has been recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs as of September 30, 2018.  Interest on the Second Lien Term Loan was payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan was 9.6%, which included amortization of debt issuance costs and discounts.  The Second Lien Term Loan was secured by a second-priority lien on all of our assets that are secured under the Prior Credit Agreement.  The Second Lien Term Loan was effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan (discussed above) and was effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).   On October 18, 2018, the Second Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.    

Second Lien PIK Toggle Notes.  In September 2016, we issued Second Lien PIK Toggle Notes with a maturity date of May 15, 2020.  Interest was payable on May 15 and November 15 of each year.  For the interest period from November 15, 2017 up to and including March 6, 2018, we had the option to pay all or a portion of interest in-kind at the rate of 10.75% per annum, which if so exercised, is added to the principal amount.  After March 6, 2018, interest was payable in cash at the rate of 9.00% per annum.  The Second Lien PIK Toggle Notes were secured by a second-priority lien on all of our assets that are pledged under the Prior Credit Agreement.  The Second Lien PIK Toggle Notes were effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan and were effectively pari passu with the Second Lien Term Loan.  On October 18, 2018, all of the outstanding Second Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.

Third Lien PIK Toggle Notes.  In September 2016, we issued Third Lien PIK Toggle Notes with a maturity date of June 15, 2021.  For the interest periods up to and including September 6, 2018, if we so elected, we had the option to pay all or a portion of interest in-kind at a rate of 10.00% per annum.  If so elected, such in-kind were added to the principal amount.  After September 6, 2018, interest was payable in cash at the rate of 8.50% per annum.  The Third Lien PIK Toggle Notes were secured by a third-priority lien on all of our assets that were secured under the Prior Credit Agreement.  The Third Lien PIK Toggle Notes were effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  On October 18, 2018, all of the outstanding Third Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Unsecured Senior Notes.  Our 8.500% Unsecured Senior Notes outstanding, which had an annual interest rate of 8.50% and maturity date of June 15, 2019, (the “Unsecured Senior Notes”), were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes was payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes was 8.4%, which included amortization of premiums and debt issuance costs.  On October 18, 2018, all of the outstanding Unsecured Senior Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Covenants.  We were in compliance with all applicable covenants for all of our debt instruments as of September 30, 2018.

For information about fair value measurements for our long-term debt, refer to Note 3, Fair Value Measurements.

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

3.  Fair Value Measurements  

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 fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as only one entity has been the holder of the 1.5 Lien Term Loan.  The fair values of our Second Lien Term Loan, Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and Unsecured Senior Notes were based on quoted prices, although the market is not a very active market; therefore, the fair value is classified within Level 2.  

The following table presents the fair value of our long-term debt, all of which are classified as Level 2 within the valuation hierarchy (in thousands):

	Hierarchy	September 30, 2018		December 31, 2017
11.00% 1.5 Lien Term Loan, due November 2019	Level 2	$	75,000	$	75,000
9.00 % Second Lien Term Loan, due May 2020	Level 2		303,000		288,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020	Level 2		179,289		162,322
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021	Level 2		165,677		119,490
8.50% Unsecured Senior Notes, due June 2019	Level 2		188,880		178,439

The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2, Long-Term Debt.  See Note 7, Derivative Financial Instruments, for the fair value of our open derivative contracts, which is classified as Level 2 in the reporting hierarchy and is reported in the Condensed Consolidated Balance Sheets using fair value.

4.  Drilling Program Joint Venture

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza Energy LLC, a Delaware limited liability company, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico over the next three years.  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.  The Monza board has approved the substitution of one of these identified undeveloped drilling projects, the Viosca Knoll 823 (“VK 823”) A-14 well, with the VK 823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well.  The interest in the VK823 A-14 well is in process of being reconveyed to W&T.  Since the initial closing, additional investors have joined as members of Monza and as of September 30, 2018, total commitments by all members, including W&T, are $361.4 million.  Monza has closed off funding from additional investors.  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.  For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well.  W&T will be the operator of each well in the JV Drilling Program unless there is already a designated third-party operator.

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.  

At the inception of Monza, W&T received a net reimbursement of approximately $20 million for the capital expenditures incurred prior to the close date for projects in the JV Drilling Program.  W&T may be obligated to fund certain cost overruns, subject to certain exceptions, on JV Drilling Program wells above budgeted and contingency amounts.  As of September 30, 2018, members of Monza made partner capital contribution payments to Monza totaling $114.7 million.

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

Information on the structure and relationship follows:

Board Structure and Authority.  Under the Monza limited liability agreement, the business and affairs of Monza are managed by a board of five directors, which will consist of three directors selected by the third-party investors, Mr. Krohn, and an additional independent director will be selected by a majority of the third-party investors in Monza subject to consent by W&T.  The independent director and one of the directors to be selected by the investors have not yet been selected.  The day-to-day operations of Monza are being managed by W&T, under the direction of the Monza board, pursuant to a services agreement.  W&T has no control over the decisions of the Monza board.  W&T has veto rights for certain decisions, but does not have the ability to unilaterally make decisions for Monza, except for day-to-day decisions as permitted under the services agreement.  The Monza board is responsible for the management of Monza and for making decisions with respect to its interest in the 14 drilling projects, including approval of the budgets.    

Accounting Methodology and Carrying Amounts.  Our interest in Monza is considered to be a variable interest entity that we account for using proportional consolidation.  We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interest in the Monza properties.  As of September 30, 2018, in the Condensed Consolidated Balance Sheet, we recorded $7.5 million, net, in oil and natural gas properties, $2.2 million in other assets and $2.6 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  For the nine months ended September 30, 2018, we recorded $2.2 million in revenue, $1.1 million in operating expense and $0.3 million, net, in other expense in connection with our proportional interest in Monza’s operations.

Maximum Exposure. Our contribution to Monza as of September 30, 2018 was $53.5 million, which consisted of cash and the conveyance of the Company’s working interest in the 14 projects.  We may also take responsibility for certain drilling and completion cost overruns, subject to certain limitations and certain exceptions, of which the total exposure cannot be estimated at this time.

5. Acquisitions and Divestitures  

  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 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.  In connection with this transaction, we were required to furnish a letter of credit of $9.4 million to a pipeline company as consignee.  We recognized asset retirement obligations (“ARO”) of $3.6 million as a component of the transaction.  In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.  

Permian Basin.  On September 28, 2018, we closed on the divestiture of all of our ownership in an overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.    

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

6.  Asset Retirement Obligations

Our ARO primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives.  

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

Balance, December 31, 2017	$	300,446
Liabilities settled		(22,764	)
Accretion of discount		13,872
Liabilities assumed through purchase		3,597
Revisions of estimated liabilities (1)		18,065
Balance, September 30, 2018		313,216
Less current portion		30,207
Long-term	$	283,009

(1) Upward revisions were primarily related to a non-operated field covering multiple wells, which experienced difficulties during the remediation process coupled with scope change due to the size of its platform.  In addition, another non-operated field experienced difficulties with a sub-contractor that had gone bankrupt and a replacement sub-contractor is attempting to re-negotiate the contract.  We do not have control over the remediation projects for non-operated properties.  Along with these two non-operated fields, we had upward revisions at two fields that were operated by us which experienced sustained casing pressure issues during the remediation process.

7.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our crude oil and natural gas.  Some of the derivative counterparties are also lenders or affiliates of lenders participating in our Prior 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.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, 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 the second quarter of 2018, we entered into crude oil derivative contracts which relate to a portion of our expected crude oil production from May 2018 to December 2018.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  During the first quarter of 2017, we entered into commodity contracts for crude oil and natural gas, all of which had expired as of December 31, 2017.

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

As of September 30, 2018, our open crude oil derivative contracts were as follows:  

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Strike
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		2,000		184,000	$	63.80
Crude Oil:  Puts,  Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Put
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		5,000		460,000	$	60.00
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional		Notional		Contract Prices
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day) (1)		(Bbls) (1)		(Bought)		(Sold)
2018	December		2,000		184,000	$	60.00	$	69.50
2018	December		2,000		184,000	$	55.00	$	72.75

(1) bbls = barrels

The swap and two-way collars were “cost-less” contracts, in that no premiums were paid or received.  For the put option contract, the $2.1 million premium is being amortized over the life of the contract and recorded in Prepaid and other assets on the Condensed Consolidated Balance Sheet.  See Note 1, Basis of Presentation.

Our open and closed (not settled) commodity derivative contracts were recorded within the line Accrued liabilities on the Condensed Consolidated Balance Sheet summarized in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Open contracts	$	2,840	$	—
Closed contracts - not settled		412		84
Total contracts	$	3,252	$	84

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018		2017
Derivative (gain) loss	$	(288	)	$	2,879	$	5,931	$	(4,765	)

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

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

	Nine Months Ended
	September 30,
	2018			2017
Cash receipts (payments) on derivative settlements, net	$	(3,091	)	$	3,924

Offsetting Commodity Derivatives

All our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our Prior Credit Agreement, that event may also trigger an acceleration of settlement of some of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.  As of September 30, 2018, there would have been no difference in the presentation of our commodity derivatives on a gross or net basis.

8.  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 2018, 2017 and 2016, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees.  RSUs are a long-term compensation component and are granted to certain employees, 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 are both a short-term and long-term compensation component and are subject to satisfaction of certain predetermined performance criteria.

As of September 30, 2018, there were 13,342,827 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 may be issued net of withholding tax if an awardee elects to satisfy his or her tax liability 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 2018, 2017 and 2016 grants, which are subject to predetermined performance criteria applied against the applicable performance period.  These RSUs continue to be 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 2018, 2017 and 2016 were determined using the Company’s closing price on the grant date.  We are also required to 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.  

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

A summary of activity related to RSUs during the nine months ended September 30, 2018 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2017		5,765,251		$	2.48
Granted		986,333			6.90
Vested		(28,503	)		2.38
Forfeited/adjustments		(113,014	)		2.45
Nonvested, September 30, 2018		6,610,067			3.14

For the RSUs that vested during 2018, the aggregate fair value at the grant dates was $0.1 million and the aggregate fair value at the vesting date was $0.2 million.

For the outstanding RSUs issued to the eligible employees as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):  

	Restricted Stock Units
2018		3,657,375
2019		1,966,359
2020		986,333
Total		6,610,067

Awards to Non-Employee Directors.  Under the W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, the “Director Compensation Plan”), shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during 2018, 2017 and 2016.  As of September 30, 2018, there were 128,980 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced on a one-to-one basis when Restricted Shares are granted.  

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

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

A summary of activity related to Restricted Shares is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2017		246,528		$	2.27
Granted		41,544			6.74
Vested		(106,240	)		2.64
Nonvested, September 30, 2018		181,832			3.08

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

For the Restricted Shares that vested during 2018, the aggregate fair value at the grant dates was $0.3 million and the aggregate fair value at the vesting date was $0.7 million.

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):

	Restricted Shares
2019		105,012
2020		62,972
2021		13,848
Total		181,832

Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  Share-based compensation was lower in the three and nine months ended September 30, 2018 compared to the prior year period due to timing of the grant date and changes in the 2018 program.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation expense from:
Restricted stock units	$	1,304	$	1,914	$	3,598	$	6,114
Restricted Shares		70		70		210		210
Total	$	1,374	$	1,984	$	3,808	$	6,324
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	289	$	694	$	800	$	2,213

Unrecognized Share-Based Compensation.As of September 30, 2018, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $8.3 million and $0.4 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2020 for RSUs and April 2021 for Restricted Shares.  

Cash-Based Incentive Compensation. In addition to share-based awards, cash-based awards were granted under the Plan to eligible employees in 2018, 2017 and 2016.  For 2018, there are two cash-based awards consisting of a long-term award and a short-term award.  All cash-based awards are performance-based awards consisting of predetermined performance criteria applied against the applicable performance period.  The 2018 long-term, cash-based awards will be eligible for payment on December 14, 2020 subject to participants meeting certain performance criteria.  The 2018 short-term, cash-based awards will be eligible for payment on or about March 15, 2019 subject to participants meeting certain eligibility criteria.  The cash-based awards for the 2018 short-term program, the 2017 program and the 2016 program include an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (as defined in the awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award as described below.  Expense for each program is recognized over the service period once the applicable financial condition is expected to be met, and the business criteria and individual performance criteria can be reasonably estimated for the applicable period.

• For the 2018 long-term, cash-based program, incentive compensation expense was based on estimates for full-year 2018 company performance metrics which were assessed as probable to be achieved and is being recognized over the September 2018 to November 2020 period.

• For the 2018 short-term, cash-based program, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was assessed as probable to be achieved; therefore, expense was recorded based on estimates for full-year 2018 Company metrics and historic individual performance measures, and is being recognized over the January 2018 to February 2019 period.

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

• For the 2017 cash-based awards, a portion of the business criteria and individual performance criteria were achieved.  The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2017 and in the first two months of 2018 for the 2017 cash-based awards.  Payments were made in March 2018.

• For the 2016 cash-based awards, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $300 million over four consecutive quarters was assessed as not being probable to be achieved; therefore no expense was recognized as of September 30, 2018.  The terms of the 2016 cash-based awards allow for the achievement of the financial condition up through December 31, 2018.  If the financial condition is achieved, payment is to be made within 30 days of achievement of the financial condition.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation included in:
General and administrative expenses	$	1,374	$	1,984	$	3,808	$	6,324
Cash-based incentive compensation included in:
Lease operating expense		837		930		2,240		1,324
General and administrative expenses		1,534		2,287		5,597		3,291
Total charged to operating income	$	3,745	$	5,201	$	11,645	$	10,939

9.  Income Taxes  

Our income tax expense for the three and nine months ended September 30, 2018 was $0.1 million and $0.4 million, respectively.  Our income tax expense for the three months ended September 30, 2017 was $5.5 million and our income tax benefit for the nine months ended September 30, 2017 was $11.1 million.  Our effective tax rate was not meaningful for the periods presented.  Based on a full year forecast, we are not expecting any current income tax expense.  In addition, immaterial deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance.  The income tax expense for the three months ended September 30, 2017 relates to revisions under GAAP using the annualized effective tax rate method in computing income tax expense or benefit for interim periods and the income tax benefit for the nine months ended September 30, 2017 relates to net operating loss carryback claims made pursuant to Internal Revenue Code (“IRC”) Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.

During the nine months ended September 30, 2018, we did not receive any income tax refunds and made no income tax payments of significance.  During the nine months ended September 30, 2017 we received $11.9 million of income tax refunds and made $0.2 million of income tax payments.          

As of September 30, 2018, we recorded current income taxes receivable of $65.2 million.  As of December 31, 2017, the balance sheet reflected current income taxes receivable of $13.0 million and non-current income taxes receivable of $52.1 million.  The receivable primarily relates to a net operating loss claim carried back for 2017 and net operating loss claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims require a review by the Congressional Joint Committee on Taxation.

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

As of September 30, 2018 and December 31, 2017, our valuation allowance was $148.3 million and $171.5 million, respectively, related to federal and state deferred tax assets.  Net deferred tax assets were recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  Although our net deferred tax assets and the related valuation allowance reflect the provisions of the Tax Cuts and Jobs Act (“TCJA”), due to the timing and the complexity of the provisions of the TCJA, further adjustments may be required during 2018 in determination of the final effect in our financial statements.  

The tax years 2013 through 2017 remain open to examination by the tax jurisdictions to which we are subject.   

10.  Earnings Per Share

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
Net income (loss)	$	46,260	$	(1,297	)	$	109,983	$	56,317
Less portion allocated to nonvested shares		1,860		—			4,489		2,349
Net income (loss) allocated to common shares	$	44,400	$	(1,297	)	$	105,494	$	53,968
Weighted average common shares outstanding		138,972		137,575			138,917		137,547
Basic and diluted earnings (loss) per common share	$	0.32	$	(0.01	)	$	0.76	$	0.39
Shares excluded due to being anti-dilutive (weighted-average)		—		7,709			—		—

11.  Contingencies  

Apache Lawsuit.  On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon (“MC”) 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, where oral argument is scheduled for December 4, 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.  

The deposit of $49.5 million with the registry of the court is recorded in Other assets (long-term) on the Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) as of September 30, 2018 and December 31, 2017.

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

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties.  We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision.  Because the IBLA still has not ruled on W&T’s request for reconsideration, the district court action has been suspended.  The court requires periodic reports concerning the status of the request for reconsideration pending before the IBLA.  Once the IBLA rules, the district court action will return to the court’s active docket.  

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 $2.1 million as of September 30, 2018.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals.        

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 nine months ended September 30, 2018 and 2017, we paid additional royalty payments of $0.6 million and $1.2 million, respectively.  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 nine months ended September 30, 2018 and 2017, 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 eight 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 the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.9 million.  We have accrued approximately $3.4 million as of September 30, 2018, 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.    

21

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

Surety Bond Collateral.  The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities.  We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion.  We did not receive any collateral demands from surety bond providers during the nine months ended September 30, 2018.

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

12.  Subsequent Events

On October 18, 2018, we entered into a series of transactions to effect a refinancing of substantially all of our outstanding indebtedness.  On such date, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023, which are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”).  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.  The Senior Second Lien Notes will be recorded at their carrying value consisting of principal and unamortized debt issuance costs.

   Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture).  In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date.

On and after November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.000% on November 1, 2022 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are guaranteed by Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  If we experience certain change of control events, we will be required to offer to repurchase the notes at 101.000% of the principal amount, plus accrued and unpaid interest, if any, to the repurchase date.

Certain entities controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the 2018 Refinancing Transaction.  The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes.  As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan liquidated as the loan was repaid in full.

22

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

TheSenior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the New Revolving 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 Indentureentered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).  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 theSenior Second Lien Notes.

Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement with a maturity date of October 18, 2022.  The primary items of the New Revolving Credit Agreement are as follows, with certain terms defined under the New Revolving Credit Agreement:

• The initial borrowing base and lending commitment is $250.0 million.

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

• The Leverage Ratio, as defined in the New Revolving Credit Agreement, is limited to 3.50 to 1.00 for quarters ending December 31, 2018 and March 31, 2019; 3.25 to 1.00 for quarters ending June 30, 2019 and September 30, 2019; and 3.00 to 1.00 for quarters ending December 31, 2019 and thereafter.  In the event of a Material Acquisition, as defined in the New Revolving Credit Agreement, the Leverage Ratio limit is 3.50 to 1.00 for the two quarters following a Material Acquisition.  

• The Current Ratio, as defined in the New Revolving Credit Agreement, must be greater than 1.00 to 1.00.

• We are required to have deposit accounts only with banks under the New Revolving Credit Agreement with certain exceptions.

• To the extent there are borrowings, the Applicable Margins, as defined in the New Revolving Credit Agreement, for Eurodollar Loans range from 2.50% to 3.50% per annum and the Applicable Margins for ABR loans range from 1.50% to 2.50% per annum.  The specific Applicable Margin rate is based on the Borrowing Base Utilization Percentage.  

• The commitment fee is 37.5 basis points if the Borrowing Base Utilization Percentage is below 50% and 50 basis points if the Borrowing Base Utilization Percentage is 50% or greater.

• By December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  We may enter into these derivative contracts with counter parties within the New Revolving Credit Agreement or with other counter parties meeting certain criteria described in the New Revolving Credit Agreement.

Availability under the New Revolving Credit Agreement is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  The first redetermination will be in the spring of 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the New Revolving Credit Agreement.  The New Revolving Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal property.  

23

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

The New Revolving Credit Agreement contains various customary covenants for certain financial tests, as defined in the New Revolving Credit Agreement, and these tests are measured as of the end of each quarter, and for customary events of default.  The customary events of default include: (i) default in the payment of interest on the Senior Second Lien Notes when due, continued for 30 days; (ii) default in payment of the principal of or premium, if any, on the Senior Second Lien Notes when due; (iii) failure by the Company or any of its restricted subsidiaries, if any, to comply with certain covenants relating to merger and consolidation and offers to purchase Senior Second Lien Notes in connection with certain change of control transactions or asset sales; (iv) failure by the Company to comply for 60 days after notice with any of the other agreements in the Indenture; (v) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Company or any of its restricted subsidiaries (or the payment of which is guaranteed by the Company or any of its restricted subsidiaries) if that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period provided in such indebtedness (a “Payment Default”); or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other such indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $50.0 million or more; (vii) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company; (viii) failure by the Company, or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, to pay final judgments aggregating in excess of $50.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (ix) any Security Document (as defined in the Indenture) ceases for any reason to be enforceable with respect to any collateral having a fair market value of not more than $25.0 million, which failure is not cured within 45 days; (x) any second lien purported to be granted under any Security Document on collateral, individually or in the aggregate, having a fair market value in excess of $25.0 million, ceases to be an enforceable and perfected second-priority lien, which failure is not cured within 45 days; and (xi) except as permitted by the Indenture, any future subsidiary guarantee entered into by one of the Company’s subsidiaries shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its subsidiary guarantee of the Senior Second Lien Notes.

After closing the 2018 Refinancing Transaction on October 18, 2018, we had $61.0 million borrowings outstanding, $9.7 million of letters of credit outstanding and our borrowing availability was $179.3 million under the New Revolving Credit Agreement.  We were in compliance with all applicable covenants of the New Revolving Credit Agreement and Senior Second Lien Notes after the 2018 Refinancing Transaction.

The funds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of the long-term debt instruments outstanding including accrued interest, tender offer premiums, redemption premiums and debt issuance costs.  The 2018 Refinancing Transaction is expected to result in a net gain of approximately $47.0 million that will be recorded in the consolidated statement of operations and approximately $17.9 million of additional capitalized debt issuance costs fees that will be recorded on the balance sheet during the fourth quarter of 2018.  As the 2018 Refinancing Transaction substantially changed our capital structure, the following table is provided to present the Condensed Consolidated Balance sheet on a pro forma basis as if the 2018 Refinancing Transaction occurred on September 30, 2018:

24

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

	September 30, 2018
	As Reported			Extinguishment of Debt Adjustments				Debt Issuance Adjustments				Pro Forma
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	(954,100	)	(1)	$	671,887		(7)	$	56,850
Total receivables		131,215			—				—				131,215
Prepaid expenses and other assets		19,699			2,138		(2)		—				21,837
Total current assets		489,977			(951,962	)			671,887				209,902
Oil and natural gas properties and other, net		522,781			—				—				522,781
Restricted deposits for ARO		20,577			—				—				20,577
Other assets		69,014			—				—				69,014
Total assets	$	1,102,349		$	(951,962	)		$	671,887			$	822,274
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	95,502		$	—			$	—			$	95,502
Undistributed oil and natural gas proceeds		34,225			—				—				34,225
Advances from joint interest partners		31,012			—				—				31,012
Asset retirement obligations		30,207			—				—				30,207
Current maturities of long-term debt:
Principal		189,829			(189,829	)	(3)		—				—
Carrying value adjustments		34,985			(34,985	)	(4)		—				—
Current maturities of long-term debt   - carrying value		224,814			(224,814	)			—				—
Accrued liabilities		31,058			(14,989	)	(5)		3,787		(8)		19,856
Total current liabilities		446,818			(239,803	)			3,787				210,802
Long-term debt:
Principal		713,365			(713,365	)	(3)		625,000		(9)		625,000
Borrowings on revolving bank credit facility		—			—				61,000		(10)		61,000
Carrying value adjustments		45,758			(45,758	)	(4)		(17,900	)	(11)		(17,900	)
Long term debt, less current portion   - carrying value		759,123			(759,123	)			668,100				668,100
Asset retirement obligations, less current portion		283,009			—				—				283,009
Other liabilities		73,175			—				—				73,175
Shareholders’ deficit:
Common stock		1			—				—				1
Additional paid-in capital		549,569			—				—				549,569
Retained earnings (deficit)		(985,179	)		46,964		(6)		—				(938,215	)
Treasury stock, at cost		(24,167	)		—				—				(24,167	)
Total shareholders’ deficit		(459,776	)		46,964				—				(412,812	)
Total liabilities and shareholders’ deficit	$	1,102,349		$	(951,962	)		$	671,887			$	822,274

25

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

Pro Forma Adjustments:

(1) Cash used to extinguish debt including principal, interest, tender offer premiums and redemption premiums.

(2) Prepaid interest related to the Second Lien Term Loan and the Unsecured Senior Notes.

(3) Payment of outstanding debt principal.

(4) Elimination of carrying value adjustments either through payments or write off of remaining balances.

(5) Payment of interest related to the Second Lien Loan and the Unsecured Senior Notes accrued as of September 30, 2018.

(6) Net gain from the write off of the remaining balances of carrying value adjustments, reduced for interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  In addition, the net gain was reduced for premiums related to repurchases pursuant to the early tender offer, redemptions premiums and certain prepayments paid on the existing notes and loans.

(7) Net proceeds from the issuance of the Senior Second Lien Notes and borrowings under the New Revolving Credit Agreement, less debt issuance costs paid of $14.1 million.

(8) Accrued debt issuance costs related to the Senior Second Lien Notes.

(9) Issuance of the Senior Second Lien Notes.

(10) Borrowings under the New Revolving Credit Agreement.

(11) Paid and accrued debt issuance costs related to the Senior Second Lien Notes and New Revolving Credit Agreement.

26

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

13.  Supplemental Guarantor Information

On September 30, 2018, our payment obligations under the Prior Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (collectively, the “Existing Notes”) were fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including the Guarantor Subsidiaries.  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Subsequent to the 2018 Refinancing Transaction, the New Revolving Credit Agreement and the Senior Second Lien Notes are fully and unconditionally guaranteed by Guarantor Subsidiaries.  Under the indentures governing the Existing Notes and the Senior Second Lien Notes, the guarantees of the Guarantor Subsidiaries can be released under certain circumstances, including:  

(1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale or other disposition does not violate the Asset Sale provisions (as such capitalized terms are defined in the New Revolving Credit Agreement and Senior Second Lien Notes);

(2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the Asset Sale provisions of the New Revolving Credit Agreement and Senior Second Lien Notes and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the New Revolving Credit Agreement and Senior Second Lien Notes;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the applicable indenture) or upon satisfaction and discharge of the New Revolving Credit Agreement and Senior Second Lien Notes;

(5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary as described in the New Revolving Credit Agreement and Senior Second Lien Notes, provided no event of default has occurred and is continuing.

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  As a result of the JV Drilling Program, we recorded proportional consolidation adjustments, which are not considered a guarantor asset under our debt agreements and, accordingly, are reported as non-guarantor adjustments in the following tables.  Due to the methodology of recording the ceiling-test write down in prior periods, consolidating adjustments are required to present the consolidated results appropriately.  The 2018 Refinancing Transaction substantially changed our capital structure.  See Note 12, Subsequent Events, for additional information.  

27

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

Condensed Consolidating Balance Sheet as of September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	—		$	—		$	—		$	339,063
Receivables:
Oil and natural gas sales		7,946			40,972			564			—			49,482
Joint interest		16,493			—			—			—			16,493
Income taxes		199,203			—			—			(133,963	)		65,240
Total receivables		223,642			40,972			564			(133,963	)		131,215
Prepaid expenses and other assets		16,707			2,956			36			—			19,699
Total current assets		579,412			43,928			600			(133,963	)		489,977
Oil and natural gas properties and other, net		372,660			111,907			49,476			(11,262	)		522,781
Restricted deposits for asset retirement obligations		20,577			—			—			—			20,577
Other assets		637,886			589,084			(51,316	)		(1,106,640	)		69,014
Total assets	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	90,260		$	7,318		$	(2,076	)	$	—		$	95,502
Undistributed oil and natural gas proceeds		32,806			1,419			—			—			34,225
Advances from joint interest partners		31,012			-			—			—			31,012
Asset retirement obligations		19,479			10,728			—			—			30,207
Current maturities of long-term debt:
Principal		189,829			—			—			—			189,829
Carrying value adjustments		34,985			—			—			—			34,985
Current maturities of long-term debt  -    carrying value		224,814			—			—			—			224,814
Accrued liabilities		31,076			133,945			—			(133,963	)		31,058
Total current liabilities		429,447			153,410			(2,076	)		(133,963	)		446,818
Long-term debt:
Principal		713,365			—			—			—			713,365
Carrying value adjustments		45,758			—			—			—			45,758
Long term debt, less current portion -   carrying value		759,123			—			—			—			759,123
Asset retirement obligations, less current portion		162,835			120,154			20			—			283,009
Other liabilities		708,461			—			—			(635,286	)		73,175
Shareholders’ equity (deficit):
Common stock		1			—			—			—			1
Additional paid-in capital		549,569			704,885			—			(704,885	)		549,569
Retained earnings (deficit)		(974,734	)		(233,530	)		816			222,269			(985,179	)
Treasury stock, at cost		(24,167	)		—			—			—			(24,167	)
Total shareholders’ equity (deficit)		(449,331	)		471,355			816			(482,616	)		(459,776	)
Total liabilities and shareholders’ equity (deficit)	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349

28

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

Condensed Consolidating Balance Sheet as of December 31, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	99,058		$	—		$	—		$	99,058
Receivables:
Oil and natural gas sales		5,665			39,778			—			45,443
Joint interest		19,754			—			—			19,754
Income taxes		128,835			—			(115,829	)		13,006
Total receivables		154,254			39,778			(115,829	)		78,203
Prepaid expenses and other assets		11,154			2,265			—			13,419
Total current assets		264,466			42,043			(115,829	)		190,680
Oil and natural gas properties and other, net		430,354			152,464			(3,802	)		579,016
Restricted deposits for asset retirement obligations		25,394			—			—			25,394
Income taxes receivable		52,097			—			—			52,097
Other assets		505,304			453,306			(898,217	)		60,393
Total assets	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	72,705		$	6,962		$	—		$	79,667
Undistributed oil and natural gas proceeds		18,762			1,367			—			20,129
Advances from joint interest partners		3,998			—			—			3,998
Asset retirement obligations		22,488			1,125			—			23,613
Current maturities of long-term debt  - carrying value		22,925			—			—			22,925
Accrued liabilities		18,058			115,701			(115,829	)		17,930
Total current liabilities		158,936			125,155			(115,829	)		168,262
Long-term debt:
Principal		889,790			—			—			889,790
Carrying value adjustments		79,337			—			—			79,337
Long term debt, less current portion - carrying value		969,127			—			—			969,127
Asset retirement obligations, less current portion		152,883			123,950			—			276,833
Other liabilities		566,375			—			(499,509	)		66,866
Shareholders’ equity (deficit):
Common stock		1			—			—			1
Additional paid-in capital		545,820			704,885			(704,885	)		545,820
Retained earnings (deficit)		(1,091,360	)		(306,177	)		302,375			(1,095,162	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(569,706	)		398,708			(402,510	)		(573,508	)
Total liabilities and shareholders’ equity (deficit)	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580

29

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

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Guarantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	79,740		$	71,964	$	1,755	$	—		$	153,459
Operating costs and expenses:
Lease operating expenses		22,188			15,182		60		—			37,430
Production taxes		432			—		—		—			432
Gathering and transportation		3,193			2,545		41		—			5,779
Depreciation, depletion, amortization    and accretion		19,170			15,568		514		1,717			36,969
General and administrative expenses		8,812			7,083		95		—			15,990
Derivative gain		(288	)		—		—		—			(288	)
Total costs and expenses		53,507			40,378		710		1,717			96,312
Operating income		26,233			31,586		1,045		(1,717	)		57,147
Earnings of affiliates		25,977			—		—		(25,977	)		—
Interest expense		11,630			—		—		—			11,630
Other (income) expense, net		(912	)		—		27		—			(885	)
Income before income tax    expense (benefit)		41,492			31,586		1,018		(27,694	)		46,402
Income tax expense (benefit)		(5,467	)		5,609		—		—			142
Net income	$	46,959		$	25,977	$	1,018	$	(27,694	)	$	46,260

30

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

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Gurantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	220,796		$	214,264	$	2,224	$	—		$	437,284
Operating costs and expenses:
Lease operating expenses		63,565			46,194		96		—			109,855
Production taxes		1,326			—		—		—			1,326
Gathering and transportation		8,730			6,983		51		—			15,764
Depreciation, depletion, amortization and accretion		58,544			48,125		678		7,460			114,807
General and administrative expenses		22,869			22,073		306		—			45,248
Derivative loss		5,931			—		—		—			5,931
Total costs and expenses		160,965			123,375		1,131		7,460			292,931
Operating income		59,831			90,889		1,093		(7,460	)		144,353
Earnings of affiliates		72,646			—		—		(72,646	)		—
Interest expense		35,100			—		—		—			35,100
Other (income) expense, net		(1,369	)		—		276		—			(1,093	)
Income before income tax   expense (benefit)		98,746			90,889		817		(80,106	)		110,346
Income tax expense (benefit)		(17,880	)		18,243		—		—			363
Net income	$	116,626		$	72,646	$	817	$	(80,106	)	$	109,983

31

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

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	51,981		$	58,300	$	—		$	110,281
Operating costs and expenses:
Lease operating expenses		18,796			16,338		—			35,134
Production taxes		340			—		—			340
Gathering and transportation		1,804			2,304		—			4,108
Depreciation, depletion, amortization and accretion		18,804			16,855		830			36,489
General and administrative expenses		7,131			8,500		—			15,631
Derivative loss		2,879			—		—			2,879
Total costs and expenses		49,754			43,997		830			94,581
Operating income		2,227			14,303		(830	)		15,700
Earnings of affiliates		13,251			—		(13,251	)		—
Interest expense		11,554			—		—			11,554
Other income, net		(41	)		—		—			(41	)
Income before income tax expense		3,965			14,303		(14,081	)		4,187
Income tax expense		4,432			1,052		—			5,484
Net income (loss)	$	(467	)	$	13,251	$	(14,081	)	$	(1,297	)

32

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

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	163,105		$	194,892	$	—		$	357,997
Operating costs and expenses:
Lease operating expenses		59,823			46,994		—			106,817
Production taxes		1,304			—		—			1,304
Gathering and transportation		6,948			8,687		—			15,635
Depreciation, depletion, amortization and accretion		59,391			55,103		2,349			116,843
General and administrative expenses		20,569			24,810		—			45,379
Derivative gain		(4,765	)		—		—			(4,765	)
Total costs and expenses		143,270			135,594		2,349			281,213
Operating income		19,835			59,298		(2,349	)		76,784
Earnings of affiliates		49,719			—		(49,719	)		—
Interest expense		34,284			—		—			34,284
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,073			—		—			5,073
Income before income tax expense (benefit)		38,008			59,298		(52,068	)		45,238
Income tax expense (benefit)		(20,658	)		9,579		—			(11,079	)
Net income	$	58,666		$	49,719	$	(52,068	)	$	56,317

33

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

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	116,626		$	72,646		$	817		$	(80,106	)	$	109,983
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		58,544			48,125			678			7,460			114,807
Amortization of debt items and other items		1,796			—			—			—			1,796
Share-based compensation		3,808			—			—			—			3,808
Derivative loss		5,931			—			—			—			5,931
Cash receipts on derivative settlements, net		(3,091	)		—			—			—			(3,091	)
Deferred income taxes		363			—			—			—			363
Earnings of affiliates		(72,646	)		—			—			72,646			—
Changes in operating assets and liabilities:											—
Oil and natural gas receivables		(2,281	)		(1,194	)		(564	)		—			(4,039	)
Joint interest receivables		3,261			—			—			—			3,261
Income taxes		(18,382	)		18,243			—			—			(139	)
Prepaid expenses and other assets		(36,764	)		(116,777	)		9,297			135,777			(8,467	)
Asset retirement obligation settlements		(15,860	)		(6,904	)		—			—			(22,764	)
Cash advances from JV partners		27,014			—			—			—			27,014
Accounts payable, accrued liabilities and other		196,880			8,157			(2,871	)		(135,777	)		66,389
Net cash provided by operating activities		265,199			22,296			7,357			—			294,852
Investing activities:
Investment in oil and natural gas properties and equipment		(36,462	)		(14,547	)		(8,152	)		—			(59,161	)
Changes in operating assets and liabilities associated with    investing activities		(13,307	)		(7,749	)		795			—			(20,261	)
Acquisition of property interest		(16,782	)		—			—			—			(16,782	)
Proceeds from sale of assets		50,474			—			—			—			50,474
Net cash used in investing activities		(16,077	)		(22,296	)		(7,357	)		—			(45,730	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,171	)		—			—			—			(6,171	)
Payment of interest on 2nd Lien PIK Toggle Notes		(2,920	)		—			—			—			(2,920	)
Other		(26	)		—			—			—			(26	)
Net cash used in financing activities		(9,117	)		—			—			—			(9,117	)
Increase in cash and cash equivalents		240,005			—			—			—			240,005
Cash and cash equivalents, beginning of period		99,058			—			—			—			99,058
Cash and cash equivalents, end of period	$	339,063		$	—		$	—		$	—		$	339,063

34

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

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	58,666		$	49,719		$	(52,068	)	$	56,317
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		59,391			55,103			2,349			116,843
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		1,271			—			—			1,271
Share-based compensation		5,449			—			—			5,449
Derivative gain		(4,765	)		—			—			(4,765	)
Cash receipts on derivative settlements		3,924			—			—			3,924
Deferred income taxes		321			—			—			321
Earnings of affiliates		(49,719	)		—			49,719			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(2,694	)		6,600			—			3,906
Joint interest receivables		8			—			—			8
Insurance reimbursements		31,740			—			—			31,740
Income taxes		(9,259	)		9,579			—			320
Prepaid expenses and other assets		1,326			(95,523	)		96,391			2,194
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligations		(41,381	)		(14,845	)		—			(56,226	)
Cash advances from JV partners		(786	)		—			—			(786	)
Accounts payable, accrued liabilities and other		127,387			(3,881	)		(96,391	)		27,115
Net cash provided by operating activities		123,568			6,752			—			130,320
Investing activities:
Investment in oil and natural gas properties and equipment		(68,831	)		(10,257	)		—			(79,088	)
Changes in operating assets and liabilities associated with    investing activities		2,174			3,505			—			5,679
Purchases of furniture, fixtures and other		(905	)		—			—			(905	)
Net cash used in investing activities		(67,562	)		(6,752	)		—			(74,314	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,170	)		—			—			(6,170	)
Payment of interest on 2nd Lien PIK Toggle Notes		(7,335	)		—			—			(7,335	)
Payment of interest on 3rd Lien PIK Toggle Notes		(6,201	)		—			—			(6,201	)
Other		(372	)		—			—			(372	)
Net cash used in financing activities		(20,078	)		—			—			(20,078	)
Increase in cash, cash equivalents and restricted cash		35,928			—			—			35,928
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	106,164		$	—		$	—		$	106,164

35

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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q.  The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements involve risks, uncertainties and assumptions.  If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, 2017 and may be discussed or updated from time to time in subsequent reports filed with the SEC.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend to update these forward-looking statements.  Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries and references to “Parent Company” are solely to W&T Offshore, Inc.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 48 offshore producing fields in federal and state waters (45 producing and three fields capable of producing).  We currently have under lease approximately 650,000 gross acres, with approximately 440,000 gross acres on the shelf and approximately 210,000 gross acres in the deepwater (water depths in excess of 500 feet).  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc., and our wholly-owned subsidiary, W & T Energy VI, LLC, and by Monza, which we proportionately consolidate in our condensed consolidated financial statements.  

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the nine months ended September 30, 2018 were comprised of 49.6% crude oil and condensate, 9.7% NGLs and 40.7% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one barrel of equivalent (“Boe”) for crude oil, NGLs and natural gas has differed significantly in the past.  For the nine months ended September 30, 2018, revenues from the sale of crude oil and NGLs made up 82.8% of our total revenues compared to 75.7% for the nine months ended September 30, 2017.  For the nine months ended September 30, 2018, our combined total production expressed in equivalent volumes was 9.1% lower than for the nine months ended September 30, 2017, with natural gas having the largest decline.  For the nine months ended September 30, 2018, our total revenues were 22.1% higher than the nine months ended September 30, 2017 due to significantly higher realized prices for crude oil and NGLs.  See Results of Operations – Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017 in this Item 2 for additional information.

36

On October 18, 2018, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement, which provides a revolving bank credit facility and letter of credit facility with an increased initial lending commitment and borrowing base of $250.0 million that matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  See Financial Statements – Note 12 –Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information, including the pro forma impact of the 2018 Refinancing Transaction on our Condensed Consolidated Balance Sheet as of September 30, 2018.

On September 28, 2018, we closed on the divestiture of our overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects in the Gulf of Mexico over the next three years.  We refer to these projects herein as the JV Drilling Program.  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.  The Monza board approved the substitution of one of these identified undeveloped drilling projects, the VK823 A-14 well, with the VK823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well.  The interest in the VK823 A-14 well is in process of being reconveyed to W&T.  Since the initial closing, additional investors have joined as members of Monza and total commitments by all members, including W&T, are $361.4 million.  Monza closed off funding from additional investors during June 2018.  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.  For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well.  See Financial Statements – Note 4 – JV Drilling Program under Part I, Item 1 of this Form 10-Q for additional information.

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 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 were required to furnish a letter of credit in the amount of $9.4 million to a pipeline company as consignee.  In addition, we recognized ARO of $3.6 million as a component of the transaction.  

Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  During the nine months ended September 30, 2018, our average realized crude oil price was $66.52 per barrel.  This is an increase over our average realized crude oil price of $45.81 per barrel for the nine months ended September 30, 2017 and an increase over our average realized crude oil price of $48.13 per barrel for the year 2017.  In addition, our average realized prices of NGLs for the nine months ended September 30, 2018 were higher than average realized prices for the nine months ended September 30, 2017 and the year 2017.  

Selected issues and data points related to crude oil, NGLs and natural gas markets are described below.

As reported by the U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in September 2018 (“STEO”), the forecast for global liquid fuels inventories is being relatively stable for 2018 and 2019.  Crude oil prices for 2018 are expected to be above 2017 levels and crude oil prices for 2019 are expected to be relatively equal to 2018.  

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The EIA reported worldwide total crude oil and petroleum liquids inventories have decreased during the first three quarters of 2018 by 0.4 million barrels per day, which is less than 0.5 % of daily production.  In a previous EIA report issued in May 2018, both U.S. and the Organization for Economic Cooperation and Development (“OECD”) commercial crude oil and other liquids inventories were approximately at the same level as the five year average for these categories.  EIA forecasts commercial crude oil and other liquids inventory levels in the U.S. and the OECD to increase in 2019 by 7% and 3%, respectively.  

The EIA forecasts an increase in worldwide production in the fourth quarter of 2018 and in each of the quarters in 2019 to increase quarter over quarter.  Yearly worldwide production for 2018 and 2019 is expected to increase by 2.0% year over year.  The increase is due primarily to increases in production in the U.S., Canada and Brazil.  Consumption for 2018 and 2019 is estimated to increase by 1.5% on a year over year basis, with China, other Asian countries and the U.S. being the primary contributors to the increase in consumption.  

According to EIA’s STEO, 2018 U.S. crude oil production (excluding other petroleum liquids) is expected to increase by 14% over 2017 and increase by 8% in 2019 over 2018 levels.  These production levels have pushed pipeline capacities to the maximum levels in the Permian Basin, which may limit short-term growth until pipeline capacity can be increased.  Net imports of crude oil in the U.S. are expected to decrease by 11% in 2018 compared to 2017 and further decrease by 9% in 2019 compared to 2018.  As noted below, the number of onshore rigs drilling for oil has increased from 2017 levels.  

Geopolitical events could greatly affect the prices for crude oil, natural gas and other petroleum products.  While these events are difficult to predict, countries like Venezuela, Nigeria, Libya, and many Middle East countries have had, and could continue to have, disruptions due to political and economic factors outside of production issues.  

The two primary benchmarks for our average realized crude oil sales prices are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $66.93 per barrel for the nine months ended September 30, 2018, up from $49.30 per barrel (35.8% higher) for the nine months ended September 30, 2017.  Brent crude oil prices averaged $72.17 per barrel for the nine months ended September 30, 2018, up from $51.75 per barrel (39.5% higher) for the nine months ended September 30, 2017.  The rising U.S. crude oil production puts upward price pressure on the Brent-to-WTI premium, which increased 114% to an average of $5.23 per barrel for the nine months ended September 30, 2018 compared to an average of $2.44 per barrel for the nine months ended September 30, 2017.  

For the nine months ended September 30, 2018, our average realized crude oil sales price was $66.52 per barrel compared to a WTI benchmark price of $66.93 per barrel.  Our average realized crude oil sales price differs from the benchmark crude prices due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors.  Crude oil quality adjustments can vary significantly by field.  For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Ship Shoal 349 field (“Mahogany”) normally receives a negative quality adjustment.  All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the nine months ended September 30, 2018 improved on average by approximately $2.00 per barrel compared to the nine months ended September 30, 2017 for these types of crude oils.  

Despite the projection by the EIA that crude oil inventories will remain fairly level on an end-of-year comparison for 2018 to 2017, the EIA projects average crude oil prices for both WTI and Brent to increase by approximately $16.00 and $19.00 per barrel, respectively, for the year 2018 compared to 2017.  EIA’s forecast of crude oil prices for both WTI and Brent are expected to be relatively flat for the year 2019 compared to 2018.  EIA projects that worldwide demand is forecasted to increase approximately 1.5% year-over-year for both 2018 and 2019.  

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During the nine months ended September 30, 2018, our average realized NGLs sales price increased by 32.1% compared to the nine months ended September 30, 2017.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During the nine months ended September 30, 2018, average prices for domestic ethane increased by 21% and average domestic propane prices increased by 28% from the nine months ended September 30, 2017.  Average price changes for other domestic NGLs components increased 19% to 37% between the two periods.  We believe the increase in prices for NGLs is mostly a function of the change in crude oil prices and propane usage during the recent winter season.  Per EIA, production of ethane is expected to increase by 20% in 2018 compared to 2017 and increase by 12% in 2019 compared to 2018.  Propane production is expected to increase by 10% in 2018 compared to 2017 and by 9% in 2019 compared to 2018.  Ethane inventories decreased 11% as of September 2018 compared to September 2017.  Ethane usage is not impacted by weather, but primarily by demand from petrochemical plants.  Additional ethane steam crackers coming on line is impacting the usage of ethane, which is believed to positively impact the price.  Propane usage is affected by weather as it is used for house heating fuel in certain areas and for crop drying, along with other uses.  Propane inventory levels are 7% higher at the end of the third quarter of 2018 compared to the same period last year.  Heating degree days were 16% higher in the first half of 2018 compared to the same period last year.

During the nine months ended September 30, 2018, our average realized natural gas sales price decreased 2.4% compared to the nine months ended September 30, 2017.  According to data from EIA’s web site, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 3.6% lower in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation.  Natural gas inventories at the end of the third quarter of 2018 were 17% lower than the prior year period and were 14% below the five-year average for the previous five years.  

Despite good demand for natural gas, the average price of natural gas continues to be weak from an overall economic standpoint as to making an adequate rate of return on wells that produce only natural gas.  The forward price curve that goes out several years shows natural gas prices below $3.00 per Mcf.  Accordingly, the market expects continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas continuing to be produced as a by-product of oil drilling,  (iii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iv) re-injecting ethane from time to time into the natural gas stream, which increases the natural gas supply.

EIA projects natural gas prices to be flat in 2018 compared to 2017 and to increase 4% in 2019 compared to 2018.  U.S. supply is projected to be lower than consumption in 2018 and 2019, resulting in inventory withdrawals.  EIA’s forecast of fuel used for electrical power generation has natural gas consumption increasing in 2018 to 34% from 32% in 2017, and further increasing in 2019 to 35%.  Electrical power generation from coal is forecast to decrease to 28% in 2018 from 30% in 2017.  Electrical power from renewable sources such as hydropower and wind is expected to be 17% in both 2018 and 2017.  

As of September 30, 2018, the number of working rigs drilling for oil and natural gas in the U.S. was higher than year ago levels for land based rigs (increase of 113 rigs, or 12%), but lower in offshore waters (decrease of two rigs or 10%).  According to Baker Hughes, the oil rig count at the end of September 2018, December 2017 and September 2017 was 863, 747 and 750, respectively.  The U.S. natural gas rig count at the end of September 2018, December 2017 and September 2017 was 189, 182 and 189, respectively.  In the Gulf of Mexico, the number of working rigs was 18 rigs (16 oil and two natural gas rigs) at the end of September 2018; 18 rigs (14 oil and four natural gas) at the end of December 2017; and 22 rigs (18 oil and four natural gas rigs) at the end of September 2017.

With the completion of the 2018 Refinancing Transaction, our capital structure and liquidity has improved substantially from the prior quarter.  Subsequent to the 2018 Refinancing Transaction, our liquidity was over $200 million, which consisted of cash on hand and availability on our New Revolving Credit Agreement.  See the Liquidity and Capital Resources section of this Item 2 for a discussion of our current liquidity position.  

Our current 2018 capital expenditure forecast for 2018 is approximately $95 million, which excludes the Heidelberg field transaction and excludes other potential acquisitions.  The forecast also incorporates our capital spending relating to the JV Drilling Program (net to our interest).  Our 2018 capital expenditure program includes participation in 10 wells, seven of which are included in the 2018 JV Drilling Program.  We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.  

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Our current focus is on making profitable investments with short payback time frames while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our obligations.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.  See our Annual Report on Form 10-K for the year ended December 31, 2017, Item 1A, Risk Factors, for additional information.  

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Results of Operations

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

	Three Months Ended												Nine Months Ended
	September 30,												September 30,
	2018			2017			Change			%			2018			2017			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	119,482		$	78,055		$	41,427			53.1	%	$	333,406		$	248,648		$	84,758			34.1	%
NGLs		10,087			6,605			3,482			52.7	%		28,481			22,401			6,080			27.1	%
Natural gas		22,641			24,113			(1,472	)		(6.1	)%		71,485			83,129			(11,644	)		(14.0	)%
Other		1,249			1,508			(259	)		(17.2	)%		3,912			3,819			93			2.4	%
Total revenues		153,459			110,281			43,178			39.2	%		437,284			357,997			79,287			22.1	%
Operating costs and expenses:
Lease operating expenses		37,430			35,134			2,296			6.5	%		109,855			106,817			3,038			2.8	%
Production taxes		432			340			92			27.1	%		1,326			1,304			22			1.7	%
Gathering and transportation		5,779			4,108			1,671			40.7	%		15,764			15,635			129			0.8	%
Depreciation, depletion,    amortization and accretion		36,969			36,489			480			1.3	%		114,807			116,843			(2,036	)		(1.7	)%
General and administrative    expenses		15,990			15,631			359			2.3	%		45,248			45,379			(131	)		(0.3	)%
Derivative (gain) loss		(288	)		2,879			(3,167	)	NM				5,931			(4,765	)		10,696		NM
Total costs and expenses		96,312			94,581			1,731			1.8	%		292,931			281,213			11,718			4.2	%
Operating income		57,147			15,700			41,447			264.0	%		144,353			76,784			67,569			88.0	%
Interest expense		11,630			11,554			76			0.7	%		35,100			34,284			816			2.4	%
Gain on exchange of debt		—			—			—			—			—			7,811			(7,811	)	NM
Other (income) expense, net		(885	)		(41	)		(844	)	NM				(1,093	)		5,073			(6,166	)	NM
Income before income tax    expense (benefit)		46,402			4,187			42,215			1,008.2	%		110,346			45,238			65,108			143.9	%
Income tax expense (benefit)		142			5,484			(5,342	)	NM				363			(11,079	)		11,442		NM
Net income (loss)	$	46,260		$	(1,297	)	$	47,557		NM			$	109,983		$	56,317		$	53,666			95.3	%
Basic and diluted earnings    (loss) per common share	$	0.32		$	(0.01	)	$	0.33		NM			$	0.76		$	0.39		$	0.37			94.9	%

NM – not meaningful

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	Three Months Ended										Nine Months Ended
	September 30,										September 30,
	2018		2017		Change			% (2)			2018		2017		Change			% (2)
Operating: (1)
Net sales:
Oil (MBbls)		1,717		1,700		17			1.0	%		5,012		5,428		(416	)		(7.7	)%
NGLs (MBbls)		318		299		19			6.4	%		985		1,024		(39	)		(3.8	)%
Natural gas (MMcf)		7,939		8,130		(191	)		(2.3	)%		24,648		28,005		(3,357	)		(12.0	)%
Total oil equivalent (MBoe)		3,359		3,354		5			0.1	%		10,106		11,119		(1,013	)		(9.1	)%
Total nat. gas equiv.  (MMcfe)		20,152		20,125		27			0.1	%		60,633		66,714		(6,081	)		(9.1	)%
Avg. daily equivalent sales (Boe/day)		36,508		36,459		49			0.1	%		37,017		40,729		(3,712	)		(9.1	)%
Avg. daily equiv. sales (Mcfe/day)		219,048		218,752		296			0.1	%		222,099		244,372		(22,273	)		(9.1	)%
Average realized sales prices:
Oil ($/Bbl)	$	69.57	$	45.92	$	23.65			51.5	%	$	66.52	$	45.81	$	20.71			45.2	%
NGLs ($/Bbl)		31.70		22.07		9.63			43.6	%		28.91		21.88		7.03			32.1	%
Natural gas ($/Mcf)		2.85		2.97		(0.12	)		(4.0	)%		2.90		2.97		(0.07	)		(2.4	)%
Oil equivalent ($/Boe)		45.32		32.43		12.89			39.7	%		42.88		31.85		11.03			34.6	%
Natural gas equivalent ($/Mcfe)		7.55		5.40		2.15			39.8	%		7.15		5.31		1.84			34.7	%
Average per Boe ($/Boe):
Lease operating expenses	$	11.14	$	10.48	$	0.66			6.3	%	$	10.87	$	9.61	$	1.26			13.1	%
Gathering and transportation		1.72		1.22		0.50			41.0	%		1.56		1.41		0.15			10.6	%
Production costs		12.86		11.70		1.16			9.9	%		12.43		11.02		1.41			12.8	%
Production taxes		0.13		0.10		0.03			30.0	%		0.13		0.12		0.01			8.3	%
DD&A		11.01		10.88		0.13			1.2	%		11.36		10.51		0.85			8.1	%
G&A  expenses		4.76		4.66		0.10			2.1	%		4.48		4.08		0.40			9.8	%
	$	28.76	$	27.34	$	1.42			5.2	%	$	28.40	$	25.73	$	2.67			10.4	%
Average per Mcfe ($/Mcfe):
Lease operating expenses	$	1.86	$	1.75	$	0.11			6.3	%	$	1.81	$	1.60	$	0.21			13.1	%
Gathering and transportation		0.29		0.20		0.09			45.0	%		0.26		0.23		0.03			13.0	%
Production costs		2.15		1.95		0.20			10.3	%		2.07		1.83		0.24			13.1	%
Production taxes		0.02		0.02		—			—			0.02		0.02		—			—
DD&A		1.83		1.81		0.02			1.1	%		1.89		1.75		0.14			8.0	%
G&A  expenses		0.79		0.78		0.01			1.3	%		0.75		0.68		0.07			10.3	%
	$	4.79	$	4.56	$	0.23			5.0	%	$	4.73	$	4.28	$	0.45			10.5	%

(1) The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for crude 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:
Bbl — barrel	Mcf — thousand cubic feet
Boe — barrel of oil equivalent	Mcfe — thousand cubic feet equivalent
MBbls — thousand barrels for crude oil, condensate or NGLs	MMcf — million cubic feet
MBoe — thousand barrels of oil equivalent	MMcfe — million cubic feet equivalent

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Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues.  Total revenues increased $43.2 million, or 39.2%, to $153.5 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.  Oil revenues increased $41.4 million, or 53.1%, NGLs revenues increased $3.5 million, or 52.7%, natural gas revenues decreased $1.5 million, or 6.1%, and other revenues decreased $0.3 million.  The increase in oil revenues was attributable to a 51.5% increase in the average realized sales price to $69.57 per barrel for the three months ended September 30, 2018 from $45.92 per barrel for the three months ended September 30, 2017 and sales volumes increased 1.0%.  The increase in NGLs revenues was attributable to a 43.6% increase in the average realized sales price to $31.70 per barrel for the three months ended September 30, 2018 from $22.07 per barrel for the three months ended September 30, 2017 and sales volumes increased 6.4%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 0.2 billion cubic feet (“Bcf”), or 2.3% and a 4.0% decrease in the average realized price to $2.85 per Mcf for the three months ended September 30, 2018 from $2.97 per Mcf for the three months ended September 30, 2017.  Overall, production volumes increased 0.1% on a Boe basis.  The largest production increases for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 were from our newly acquired interest in the Heidelberg field and our Ship Shoal 300 field.  Offsetting were production decreases primarily due to natural production declines.  Production for the three months ended September 30, 2018 was also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,100 Boe per day.  During the three months ended September 30, 2017, deferred production was 6,100 Boe per day.

Revenues from oil and NGLs as a percent of our total revenues were 84.4% for the three months ended September 30, 2018 compared to 76.8% for the three months ended September 30, 2017.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 45.6% for the three months ended September 30, 2018 compared to 48.1% for the three months ended September 30, 2017.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers, and facilities maintenance, increased $2.3 million, or 6.5%, to $37.4 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017.  On a component basis, base lease operating expenses increased $0.5 million, insurance premiums increased $0.4 million, workover expenses increased $2.2 million, and facilities maintenance expense decreased $0.8 million.  Base lease operating expenses increased primarily due to the addition of the Heidelberg field, and lower product handling and operating charges to an outside party at our Mississippi Canyon 243 field (Matterhorn).  The insurance premium increase is primarily due to timing differences on our pro-rata share of insurance premiums related to the Thunder Hawk platform, which services the Mississippi Canyon 698 (Big Bend) and Mississippi Canyon 782 (Dantzler) fields.  The increase in workover expense was primarily due to a 2018 project at our Mahogany field.  The facility maintenance expense decrease was primarily attributable to work performed in 2017 at our Mississippi Canyon 243 field (Matterhorn), which was partially offset by projects with lower overall costs undertaken in 2018.  

Production taxes.  Production taxes increased $0.1 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017.  Most of our production is from federal waters where no production taxes are imposed.  Our Fairway field, which is in state waters, is subject to production taxes.  

Gathering and transportation.  Gathering and transportation expenses increased $1.7 million to $5.8 million for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 primarily related to the Heidelberg field, where we are required to pay additional amounts if throughputs are below minimums quantities.  

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, increased to $11.01 per Boe for the three months ended September 30, 2018 from $10.88 per Boe for the three months ended September 30, 2017.  On a nominal basis, DD&A increased to $37.0 million (or 1.3%) for the three months ended September 30, 2018 from $36.5 million for the three months ended September 30, 2017.  DD&A on a nominal basis increased primarily due to revisions in future development costs.  Other factors affecting the DD&A rate are production, capital expenditures, sales of assets and changes in proved reserves volumes.    

General and administrative expenses (“G&A”).  G&A was $16.0 million for the three months ended September 30, 2018, increasing 2.3% from $15.6 million for the three months ended September 30, 2017.  The increase was primarily due to an accrual for an executive’s anticipated separation settlement, increases in medical claims and buyout of an office lease.  G&A on a per Boe basis was $4.76 per Boe for the three months ended September 30, 2018 compared to $4.66 per Boe for the three months ended September 30, 2017.

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Derivative (gain) loss. We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production. The three months ended September 30, 2018 reflects a $0.3 million derivative gain.  We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production. The three months ended September 30, 2017 reflects a $2.9 million derivative loss primarily for our crude oil derivative contracts.  

Interest expense.  Interest expense was $11.6 million for both three months periods ended September 30, 2018 and 2017.  See Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on our debt.   

Other (income) expense, net.  During the three months ended September 30, 2018, other income, net, was $0.9 million primarily due to interest income.  

Income tax expense.Our income tax expense for the three months ended September 30, 2018 and 2017 was $0.1 million and $5.5 million, respectively.  Based on a full year forecast, we are not expecting any current income tax expense. Immaterial deferred income tax expense was recorded for the three months ended September 30, 2018 due to dollar-for-dollar offsets by our valuation allowance.  The income tax expense for the three months ended September 30, 2017 relates to revisions under GAAP using the annualized effective tax rate method in computing income tax expense or benefit for interim periods.  Our effective tax rate using book pre-tax income was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues.  Total revenues increased $79.3 million, or 22.1%, to $437.3 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.  Oil revenues increased $84.8 million, or 34.1%, NGLs revenues increased $6.1 million, or 27.1%, natural gas revenues decreased $11.6 million, or 14.0%, and other revenues increased $0.1 million.  The increase in oil revenues was attributable to a 45.2% increase in the average realized sales price to $66.52 per barrel for the nine months ended September 30, 2018 from $45.81 per barrel for the nine months ended September 30, 2017, partially offset by a decrease in sales volumes of 7.7%.  The increase in NGLs revenues was attributable to a 32.1% increase in the average realized sales price to $28.91 per barrel for the nine months ended September 30, 2018 from $21.88 per barrel for the nine months ended September 30, 2017, partially offset by a decrease in sales volumes of 3.8%.  The decrease in natural gas revenues was attributable to a decrease in sales volumes of 3.4 Bcf, or 12.0% and a 2.4% decrease in the average realized price to $2.90 per Mcf for the nine months ended September 30, 2018 from $2.97 per Mcf for the nine months ended September 30, 2017.  Overall, production volumes decreased 9.1% on a Boe basis. The largest production increases for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 were from our newly acquired interest in the Heidelberg field and our Ship Shoal 300 field.  Revenue and production was adjusted for royalty relief on two of our deepwater fields related to their 2017 and 2016 production and realized prices which is recognized in the subsequent year.  This royalty relief impact to revenues during the nine months ended September 30, 2018 and 2017 was $1.0 million and $5.0 million, respectively.  Offsetting were production decreases primarily due to natural production declines.  Production for the nine months ended September 30, 2018 was also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,300 Boe per day.  During the nine months ended September 30, 2017, deferred production was 3,800 Boe per day.

Revenues from oil and liquids as a percent of our total revenues were 82.8% for the nine months ended September 30, 2018 compared to 75.7% for the nine months ended September 30, 2017.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 43.5% for the nine months ended September 30, 2018 compared to 47.8% for the nine months ended September 30, 2017.   

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Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers, and facilities maintenance, increased $3.0 million, or 2.8%, to $109.9 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  On a component basis, base lease operating expenses increased $2.0 million, insurance premiums increased $1.7 million, workover expenses increased $0.3 million, and facilities maintenance expense decreased $1.0 million.  Base lease operating expenses increased primarily due the addition of the Heidelberg field; lower product handling and operating charges to an outside party at our Matterhorn field and higher incentive compensation expenses.  The insurance premium increase is primarily due to our insurance policies related to named windstorms, which had better coverage in 2018 compared to the 2017 period.  The facility maintenance expense decrease is primarily attributable to compressor overhauls and pipeline projects in 2017, which did not re-occur at the same expense level during 2018.  

Production taxes.  Production taxes were basically flat for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.  Most of our production is from federal waters where no production taxes are imposed.  Our Fairway field, which is in state waters, is subject to production taxes.  

Gathering and transportation.  Gathering and transportation expenses increased $0.1 million to $15.8 million for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 primarily related to the Heidelberg field, where we are required to pay additional amounts if throughputs are below minimums quantities defined in the contract and were partially offset by lower expenses from lower production volumes.  

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, increased to $11.36 per Boe for the nine months ended September 30, 2018 from $10.51 per Boe for the nine months ended September 30, 2017.  On a nominal basis, DD&A decreased to $114.8 million (1.7%) for the nine months ended September 30, 2018 from $116.8 million for the nine months ended September 30, 2017.  DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are capital expenditures, sales of assets, changes in future development costs on remaining reserves and an increase in proved reserves volumes.    

General and administrative expenses.  G&A was $45.2 million for the nine months ended September 30, 2018, essentially flat compared to the nine months ended September 30, 2017.  Decreases in lawsuit settlements were offset by an accrual for an executive’s anticipated separation settlement, increases in medical claims and buyout of an office lease.  G&A on a per Boe basis was $4.48 per Boe for the nine months ended September 30, 2018 compared to $4.08 per Boe for the nine months ended September 30, 2017.

Derivative (gain) loss. We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production. The nine months ended September 30, 2018 reflects a $5.9 million derivative loss.  We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production. The nine months ended September 30, 2017 reflects a $4.8 million derivative gain primarily for our crude oil derivative contracts.  

Interest expense.  Interest expense was $35.1 million and $34.3 million for the nine months ended September 30, 2018 and 2017, respectively.  The increase is primarily due to an interest accrual related to a royalty issue with the ONRR on production that dates back 10 to 15 years.  See Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on our debt.   

Gain on exchange of debt.  During the nine months ended September 30, 2017, an additional net gain of $7.8 million was recognized primarily as a result of paying interest in cash on the Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes versus paying the interest in kind.  The cash interest payments on Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes lowered the carrying value of the respective notes under ACS 470-60, resulting in the recognition of a non-cash gain.  The cash payments have a lower interest rate compared to the PIK option and this also reduced future interest and principal payments.  Partially offsetting were additional expenses related to the 2016 Restructuring Transactions for differences between estimated and actual expense.    

Other income (expense), net.  During the nine months ended September 30, 2018, other income, net, was $1.1 million primarily due to interest income.  During the nine months ended September 30, 2017, other expense, net, was $5.1 million and consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million.  SeeFinancial Statements - Note 11– Contingencies under Part I, Item 1 of this Form 10-Q for additional information on the Apache lawsuit.  

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Income tax expense (benefit).Our income tax expense for the nine months ended September 30, 2018 was $0.4 million and our income tax benefit for the nine months ended September 30, 2017 was $11.1 million.  Based on a full year forecast, we are not expecting any current income tax expense.  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.  The income tax benefit for the nine months ended September 30, 2017 relates to net operating loss carryback claims made pursuant to rules for “specified liability losses”.  Our effective tax rate using book pre-tax income was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our asset retirement obligations.  We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.  

If commodity prices were to return to the weaker levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could have a significant adverse effect on our liquidity.  In addition, other events outside of our control could significantly affect our liquidity such as changes in regulations or the interpretation of existing regulations.  

On October 18, 2018, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement which provides a revolving bank credit facility and letter of credit facility with an increased initial borrowing base of $250.0 million and matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs. See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information, including the pro forma impact of the 2018 Refinancing Transaction on our Condensed Consolidated Balance Sheet as of September 30, 2018.

New Revolving Credit Agreement.  Subsequent to the issuance of the Senior Second Lien Notes and repayment of the existing notes and loans outstanding, we had $61.0 outstanding borrowings under the New Revolving Credit Agreement, $9.7 million of letters of credit outstanding and $179.3 million availability.  We will be subject to the normal re-determination of our borrowing base in the spring of 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our New Revolving Credit Agreement.  The New Revolving Credit Agreement’s security is collateralized by substantially all of our oil and natural gas properties and certain personal property.  The New Revolving Credit Agreement contains financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the New Revolving Credit Agreement.  We were in compliance with all applicable covenants of the Prior Credit Agreement and other long-term debt instruments as of September 30, 2018 and after the 2018 Refinancing Transaction under the New Revolving Credit Agreement and the Senior Second Lien Notes.

BOEM Matters.  As of the filing date of this Form 10-Q, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to financial assurance obligations.  During April 2018, we posted an additional $10.6 million of bonds as requested by BOEM to account for decommissioning obligations that accrued on sole-liability properties during the Company’s period of leasing.  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 2018 as of the filing date of the Form 10-Q.

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

Cash Flow and Working Capital.  Net cash provided by operating activities for the nine months ended September 30, 2018 was $294.9 million compared to $130.3 million, or 126%, for the nine months ended September 30, 2017.  The change between periods is primarily due to higher realized prices for crude oil and NGLs, lower spending for ARO activities and working capital changes.  Our combined average realized sales price per Boe increased 34.7% in the nine months ended September 30, 2018, which caused total revenues to increase $109.0 million, partially offset by decreases of 9.1% in production volumes which caused revenues to decrease by $29.8 million.  

Other items affecting operating cash flows for the nine months ended September 30, 2018 were ARO settlements of $22.8 million, which decreased from $56.2 million in the prior period and cash advances from joint venture partners increased $27.0 million.  During the nine months ended September 30, 2017, we received insurance reimbursements of $31.7 million and made a deposit related to the Apache matter of $49.5 million.  Working capital items and advances from joint interest partners accounted for the balance of the change in net cash provided by operating activities.  

Net cash used in investing activities during the nine months ended September 30, 2018 and 2017 was $45.7 million and $74.3 million, respectively, which represents our investments in oil and gas properties and equipment.  Investments in oil and natural gas properties on an accrual basis in the nine months ended September 30, 2018were $59.2 million compared to $79.1 million for the nine months ended September 30, 2017.  The majority of our capital expenditures for the nine months ended September 30, 2018 related to investments on the conventional shelf in the Gulf of Mexico and, to a lesser extent, in the deep waters of the Gulf of Mexico.  Adjustments from working capital changes associated with investing activities was a net cash decrease of $20.3 million in the nine months ended September 30, 2018 compared to net cash increase of $5.7 million in the nine months ended September 30, 2017.  These amounts represent timing differences between when the work was performed and the payments are made.  The net purchase price for the acquisition of the Heidelberg field was $16.8 million, which was acquired during the nine months ended September 30, 2018 and there were no similar investments in the prior year period.  The sale of our overriding royalty interests in the Permian Basis fields resulted in net proceeds of $50.5 million and there were no asset sales in the prior year period.

Net cash used by financing activities for the nine months ended September 30, 2018 and 2017 was $9.1 million and $20.1 million, respectively. The net cash used for the nine months ended September 30, 2018 and 2017 was primarily attributable to the interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes, which are 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 and interest rate risk from floating interest rates on our New Revolving Credit Agreement.  During the second quarter of 2018, we entered into derivative contracts for crude oil which relate to volumes of 11,000 barrels per day through December 2018.  See Financial Statements – Note 7 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  Under the New Revolving Credit Agreement, by December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.    

  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.  Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

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Our general and excess liability policies are effective for one year beginning May 1, 2018 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, 2018, and our Energy Package effective on June 1, 2018, 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 nine months ended 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 on an accrual basis for exploration, development and other leasehold costs:  

	Nine Months Ended
	September 30,
	2018			2017
	(In thousands)
Exploration (1)	$	24,163		$	20,458
Development (1)		36,192			57,397
Heidelberg field		16,782			—
Reimbursement from Monza for 2017 expenditures		(14,075	)		—
Seismic, JV Drilling Program and other		12,881			1,233
Investments in oil and gas property/equipment	$	75,943		$	79,088

(1) Reported geographically in the subsequent table

The following table presents our exploration and development capital expenditures on an accrual basis geographically in the Gulf of Mexico:

	Nine Months Ended
	September 30,
	2018		2017
	(In thousands)
Conventional shelf	$	47,070	$	75,463
Deepwater		13,285		2,392
Exploration and development capital expenditures	$	60,355	$	77,855

Our capital expenditures for the nine months ended September 30, 2018 were financed by cash flow from operations and cash on hand.  

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During the nine months ended September 30, 2018, we completed the A-17 well at Mahogany, which began producing during March 2018, the Viosca Knoll 823 (“Virgo”) A-10 ST well, which began production during April 2018, the Mahogany A-5 ST 2 well, which began producing in July 2018, and the Virgo A-12 well, which began producing in September.  The Virgo A-10 ST well, the Mahogany A-5 ST2 well, and the Virgo A-12 well are in the JV Drilling Program.  During the nine months ended September 30, 2017, we completed three wells.  We did not drill any dry holes in either period.  

Exploration/Development Activities.  As of October 31, 2018, we were drilling on the Virgo A-13 well and were in the completion phase for the South Timbalier 311 A-2 well.  The Main Pass 286 #1 well has been cased and is waiting for development sanction.  These three wells are in the JV Drilling Program.  In addition, we are completing the A-19 well at Mahogany, which is not in the JV Drilling Program.

Offshore Lease Awards.  During the nine months ended September 30, 2018, we were successful in obtaining nine new leases in the Central and Eastern Gulf of Mexico.  The new leases are primarily located near or offsetting our existing properties and were acquired in total for less than $1.0 million, net to our interest.  Subsequently in October 2018, we received preliminary notice of being successful in obtaining eight additional leases, which were acquired in total for $1.0 million, net to our interest.  We expect to receive official notice related to these eight leases within the next 90 days.

Acquisitions.  In April 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 904.  After effective date and closing adjustments, the net purchase price was $16.8 million.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

Divestitures.Periodically, we sell properties as part of the management of our property portfolio.  In September 2018, we closed on the divestiture of our overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.  See Financial Statements – Note 5 –Acquisitions and Divestitures under Part I, Item 1 of this Form 10-Q for additional information.

Capital Expenditure Budget.  Our current 2018 capital expenditure forecast is approximately $95 million, which excludes the Heidelberg field transaction and excludes other potential acquisitions.  The forecast incorporates the shared investments in certain wells included in the JV Drilling Program.  Our 2018 capital expenditure program includes participation in 10 wells, seven of which are included in the JV Drilling Program.  We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.

Income Taxes.  As of September 30, 2018, we have current income tax receivables of $65.2 million.  The current income tax receivables include an estimated net operating loss claim for 2017 of $13.1 million; $11.1 million of the refund is expected to be received during 2018 with the remainder expected thereafter.  The other component of current income tax receivables relates to our net operating loss claims totaling $52.1 million for the years 2012, 2013 and 2014 that were carried back to prior years and are expected to be received during the first half of 2019.  These receivables relate to claims under rules for “specified liability losses” made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  For 2018, we do not expect to make any significant income tax payments.  See Financial Statements – Note 9 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO at September 30, 2018 and December 31, 2017 were $313.2 million and $300.4 million, respectively.  Our plans include spending $30.6 million in 2018 for ARO compared to $72.4 million spent on ARO in 2017.  As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates.  See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017 for additional information.    

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Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term DebtandNote 6 – Asset Retirement Obligations, andunderPart I, Item 1 of this Form 10-Q. As of September 30, 2018, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $5.7 million which was the same amount as of December 31, 2017.  In conjunction with the purchase of the Heidelberg field interest, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.  Except for scheduled utilization, other contractual obligations as of September 30, 2018 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2017.

Critical Accounting Policies

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2017.  Also refer to Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1of this Form 10-Q.  

Recent Accounting Pronouncements

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

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the nine months ended September 30, 2018 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2017.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2017.  

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely.  Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and could have impacts on our business in the future.  During the second quarter of 2018, we entered into derivative crude oil contracts related to a portion of our estimated production for the remainder of 2018.  We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments.  Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements.  See Financial Statements – Note 7 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  Under the New Revolving Credit Agreement, by December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  See Financial Statements – Note 12 – Subsequent Events under Part I, Item 1 of this Form 10-Q for additional information.    

Interest Rate Risk.  As of September 30, 2018, we had no borrowings outstanding under our Prior Credit Agreement.  The Prior Credit Agreement had a variable interest rate, which is primarily impacted by the London Interbank Offered Rate and the margin, which ranged from 3.00% to 4.00% depending on the amount of utilization.  As of September 30, 2018, we did not have any derivative instruments related to interest rates.  As of October 18, 2018, we had $61.0 million borrowings outstanding under the New Revolving Credit Agreement.  As of October 31, 2018, we had $61.0 million of borrowings outstanding on the New Revolving Credit Agreement subject to the variable London Interbank Offered Rate and the Applicable Margin and we did not have any derivative instruments related to interest rates.    

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Item 4.  Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of September 30, 2018, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended September 30, 2018, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.  

PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

See Financial Statements – Note 11 – Contingencies, under Part I Item 1 of this Form 10-Q for information on various legal matters.  

Item 1A.  Risk Factors  

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2017, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2017 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2017.

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Item 5.  Other Information  

Certain entities controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the 2018 Refinancing Transaction.  The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes.  On October 31, 2018, the Audit Committee of the Company waived any application of the insider trading policy in the Company’s Code of Business Conduct and Ethics to these transactions as being unnecessary in light of the full disclosures made in connection with the offering of the Senior Second Lien Notes as part of the 2018 Refinancing Transaction.  As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan liquidated as the loan was repaid in full.

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Item 6.  Exhibits

Exhibit Number	Description
3.1	Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))
3.2	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))
4.1	Indenture, dated as of October 18, 2018, by and among W&T Offshore, Inc., W&T Energy VI, LLC, and W&T Energy VII, LLC, as subsidiary guarantors the Guarantors (as defined) and Wilmington Trust, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))
10.1	Purchase Agreement dated October 5, 2018 by and among W&T Offshore, Inc., W&T Energy VI, LLC, W&T Energy VII, LLC and Morgan Stanley & Co. LLC, as representative of the Initial Purchasers named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on October 11, 2018 (File No. 001-32414))
10.2	First Amendment to Intercreditor Agreement, dated as of October 18, 2018, by and among Toronto Dominion (Texas) LLC, as Original Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Original Second Lien Collateral Trustee, Wilmington Trust, National Association, as Original Second Lien Trustee, Wilmington Trust, National Association, as Second Lien Trustee, Wilmington Trust, National Association, as Second Lien Collateral Trustee, Cortland Capital Market Services LLC, as Priority Lien Agent, Wilmington Trust, National Association as Third Lien Collateral Trustee and Wilmington Trust, National Association as Third Lien Trustee. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))
10.3	Priority Confirmation Joinder, dated as of September 18, 2018, by and between Toronto Dominion (Texas) LLC, as Original Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Original Second Lien Collateral Trustee, Wilmington Trust, National Association, as Original Second Lien Trustee, Second Lien Collateral Trustee, Third Lien Collateral Trustee and Third Lien Trustee and Cortland Capital Market Services LLC, Priority Lien Agent. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))
10.4	Sixth Amended and Restated Credit Agreement, dated as of October 18, 2018, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))

53

Exhibit Number	Description
10.5*†	Form of Executive Annual Incentive Agreement for Fiscal 2018.
10.6*†	Form of 2018 Executive Restricted Stock Unit 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.

*	Filed or Furnished herewith.
†	Management Contract or Compensatory Plan or Arrangement, filed herewith

54

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 1, 2018.

W&T OFFSHORE, INC.
By:	/s/  Janet Yang
	Vice President and Acting Chief Financial Officer (Principal Financial Officer), duly authorized to sign on behalf of the registrant

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EX-10.5

Exhibit 10.5

W&T OFFSHORE, INC.
AMENDED AND RESTATED INCENTIVE COMPENSATION PLAN

Executive Annual Incentive Award Agreement

For Fiscal Year 2018

This potential Annual Incentive Award (the “Award”) is granted on November 1, 2018 (the “Award Date”), by W&T Offshore, Inc., a Texas corporation (the “Company”) to the executive whose name appears in the footer below (“Awardee” or “you”).

WHEREAS, the Company in order to induce you to enter into and to continue to dedicate service to the Company and to materially contribute to the success of the Company agrees to grant you this Award; and

WHEREAS, this Award is granted to you pursuant to the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, as may be amended from time to time (the “Plan”), and the following terms and conditions of this agreement (the “Agreement”) for the Company’s 2018 fiscal year.

NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the Award is hereby granted on the following terms and conditions:

1.Terms and Conditions.  The Award is subject to all the terms and conditions of the Plan.  All capitalized terms not defined in this Agreement shall have the meaning stated in the Plan.  If there is any inconsistency between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control unless this Agreement expressly states that an exception to the Plan is being made.

2.Definitions.  For purposes of this Agreement, the following terms shall have the meanings stated below.

(a)“Base Salary” means the base salary you received as an employee during the Performance Period, (i) including any amounts deferred pursuant to an election under any 401(k) plan, pre-tax premium plan, deferred compensation plan, or flexible spending account sponsored by the Company or any Subsidiary, and  any overtime paid to you as an offshore employee required by your standard work schedule, but (ii) excluding any incentive compensation, employee benefit, or other  benefit paid or provided under any incentive, bonus or employee benefit plan sponsored by the Company or any Subsidiary, all overtime paid other than as specified in (i) above and/or any excellence award, gains upon stock option exercises, restricted stock grants or vesting, moving or travel expense reimbursement, sign on bonus, imputed income, or tax gross-ups, without regard to whether the payment or gain is taxable income to you.

(b)“Disability” means your permanent disability as defined in your Individual Agreement.  In the event that there is no existing written Individual Agreement between you and the Company or if any such agreement does not define Disability, the term “Disability” shall mean: (i) a physical or mental impairment of sufficient severity that, in the sole opinion of the

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Company, (A) you are unable to continue performing the duties assigned to you prior to such impairment or (B) your condition entitles you to disability benefits under any insurance or employee benefit plan of the Company or its Subsidiaries, and (ii) the impairment or condition is cited by the Company as the reason for your termination; provided, however, that in all cases, the term Disability shall be applied and interpreted in compliance with section 409A of the Code and the regulations thereunder.

(c)“Individual Agreement” means any employment or severance agreement, if any, between you and the Company or any Subsidiary.

(d)“Performance Goals” means the performance criteria established by the Committee pursuant to Section 8 of the Plan and set forth in Appendix A attached hereto.

(e)“Performance Period” means the Company’s complete fiscal year ending December 31, 2018.

(f)“Total Performance Score” means the aggregate number of points, expressed as a percentage, you are assigned as a result of the Committee’s review, analysis and certification of the achievement of the applicable Performance Goals set forth in Appendix A attached hereto for the Performance Period.  Your Total Performance Score, shall be expressed as a percentage set forth using the chart below:

Total Performance Score in Points	Total Performance Score Expressed as a Percentage
200	200%
100	100%
50	50%
0	0%

(g)“Individual Performance Multiplier” means a number based on your Individual Performance Score (defined below).  Your Individual Performance Score corresponds to the Company’s view of your individual performance and contribution to the success of the Company, on a scale of one to five, as determined by your supervisor and subject to the review of the Chief Executive Officer and the Compensation Committee (the “Individual Performance Score”).  It is intended, but not required, that the Individual Performance Scores be provided in tenths, e.g., 4.1.  

Individual Performance Score   1.02.02.13.04.05.0

Individual Performance Multiplier 000.100.531.001.90

An   Individual Performance Score of between one and two results in an Individual Performance Multiplier of zero and therefore no Award whatsoever is earned.  For the avoidance of doubt, you must have an Individual Performance Score of at least 2.1 in order to earn an Award.

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3.Effect of Award Agreement.   This Award is subject to all of the terms and conditions of the Agreement and the Plan; all decisions or interpretations of the Agreement and the Plan by the Committee are binding, conclusive and final.

4.Award Percentage.  Your award percentage is __% (“Award Percentage”).

5.Maximum Performance Levels. The maximum Total Performance Score you may be assigned shall not exceed 200.

6.Award Calculation.

(a)Subject to the terms and conditions set forth in the Plan and this Agreement, including, without limitation, Sections 5 and 8, your Award is equal to the dollar amount obtained by multiplying the following four numbers: your Base Salary, Award Percentage, Total Performance Score (expressed as a percentage), and Individual Performance Multiplier.    

(i)The Total Performance Score will be calculated using straight-line interpolation.

(ii)Any Award that is earned will be paid in cash as soon as practicable after the Committee has certified the applicable Performance Goals were achieved for the Performance Period, but in no event later than the seventy-fifth (75^th) day following the date the Performance Period ends. However, notwithstanding anything within this Agreement to the contrary, the Company will not pay any Awards unless and until the following financial condition is achieved on or before December 31, 2020: Adjusted EBITDA less Interest Expense Incurred, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus the three preceding fiscal quarters, exceeds $200 million.  In such case the cash payment will be made within 30 days following the achievement of this financial condition, but subject to all the terms of this Agreement, including but not limited to Sections 7(b) and 8; provided that the Committee in its sole discretion retains the right to pay any Award otherwise earned regardless of whether such financial condition is achieved.

(iii)You must be employed prior to September 30 within the Performance Period in order to be eligible to participate in the Plan for the Performance Period.

(b)Subject to (i) and (ii) above, as an example calculation, an individual with a Base Salary of $100,000, an Individual Performance Score of 4.0 (resulting in an Individual Performance Multiplier of 1.0), a Total Performance Score of 90 and an Award Percentage of 30%, shall receive the following award:

$27,000 = ($100,000) x (1.0) x (0.9) x (0.3)  

7.Effect of Termination of Employment.  Notwithstanding any provisions to the contrary below in the remainder of this Section 7, in the event of any inconsistency between this Section 7 and any written Individual Agreement you may have, the terms of such an Individual

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Agreement will control.   In the event you do not have an Individual Agreement or your Individual Agreement does not address the treatment of Annual Incentive Awards under the Plan, and your employment is terminated at any time on or after the Award Date and before the Award is paid, your Award will be treated as follows:

(a)Death or Disability.  If your termination of employment is a result of your death or Disability, as determined by the Company in its sole and complete discretion, you will receive a pro-rata Award, if an Award is payable for the Performance Period, based on the Base Salary and Individual Performance Multiplier you received during the Performance Period (the “Pro-Rata Award”).  Subject to Section 6(a)(ii), you, your beneficiaries, or your estate, as applicable, will be paid in cash as soon as practicable after the Committee has certified the applicable Performance Goals were achieved for the Performance Period, but in no event later than the seventy-fifth (75^th) day following the date the Performance Period ends; provided, however, that you must have been employed with the Company for a minimum of 90 days during the Performance Period in order to be eligible for a Pro-Rata Award described in this Section 7(a).

(b)Terminations other than Death or Disability.  Unless your termination of employment is a result of your death or Disability, you must be employed by the Company or a Subsidiary on the date Awards are paid in order to be eligible to receive payment of an Award.  You have no vested interest in the Award prior to the Award actually being paid to you by the Company.  If your employment with the Company or a Subsidiary terminates for any reason other than your death or Disability, whether your termination is voluntary or involuntary, with or without cause, you will not be eligible to receive payment of any Award for the Performance Period.

8.Right of the Committee.  The Committee has the right to increase, reduce or eliminate your Award for any reason regardless of the amount of your Total Performance Score or Individual Performance Multiplier achieved.

9.Right of the Company and Subsidiaries to Terminate Services.  Nothing in this Agreement confers upon you the right to continue in the employ of the Company or any Subsidiary, or interfere in any way with the rights of the Company or any Subsidiary to terminate your employment at any time, with or without cause.

10.Effect of Transfer to New Position during the Performance Period.  In the event that you are transferred to a new position with the Company or a Subsidiary during the Performance Period that confers upon you a new employment status in all or any significant aspect of your employment with the Company or a Subsidiary (including, but not limited to, a new title, rank, Base Salary, authority, duties, or other similar employment element) that is dissimilar from the position you hold upon the Award Date, the Committee has the sole discretion to determine whether or not such new position shall necessitate one or more of the following actions: (a) amending this Agreement, including, but not limited to, an amendment to the Performance Goals or the percentage of your Base Salary constituting your Target Award, (b) terminating this Agreement and any potential Award for the applicable Performance Period, (c) pro-rating your Award to reflect the number of days you actually spent in active service in your previous position, or (d) making such other adjustments as the Committee deems

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appropriate to reflect your transfer to a new position; provided, however, that the Committee may determine in its sole discretion that no adjustment is necessary to this Agreement or Award.  

11.Withholding Taxes.  The Company may require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company), an amount the Company deems necessary to satisfy its (or its Subsidiary’s) current or future obligation to withhold federal, state or local income or other taxes that you incur as a result of the Award.  With respect to any such required tax withholding, the Company shall withhold from the payment to be issued to you under this Agreement the amount necessary to satisfy the Company’s obligation to withhold taxes.  

12.Furnish Information.  You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

13.No Liability for Good Faith Determinations.  The Company, the Committee and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Award granted hereunder.

14.Execution of Receipts and Releases.  Any payment of cash to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment, to execute a release and receipt therefor in such form as the Company shall determine.

15.Notice.  All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or if earlier the date it is sent via certified United States mail.

16.Waiver of Notice.  Any person entitled to notice hereunder may waive such notice in writing.

17.Information Confidential.  As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors.  In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you.

18.Nontransferability.  Neither this Agreement nor this Award subject to this Agreement shall be subject in any manner to anticipation, alienation, sale, exchange, transfer, assignment, pledge, encumbrance or garnishment by your creditors or your beneficiary, except transfer by will or by the laws of descent and distribution. All rights with respect to this

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Agreement shall be exercisable during your lifetime only by yourself or, if necessary, your guardian or legal representative.

19.Successors. This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

20.Severability.  If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

21.Amendment.  Subject to Section 8, the Committee may amend this Agreement at any time; provided, however, that no such amendment may adversely affect your rights under this Agreement without your consent, except to the extent such amendment is reasonably determined by the Committee, in its sole discretion, to be necessary to comply with applicable law or to prevent a detrimental accounting impact. No amendment or addition to this Agreement shall be effective unless in writing.

22.Headings.  The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

23.GoverningLaw.  All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of Texas, without giving any effect to any conflict of law provisions thereof, except to the extent Texas state law is preempted by federal law.  

24.Consent to Texas Jurisdiction and Venue.  You hereby consent and agree that state courts located in Harris County, Texas and the United States District Court for the Southern District of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Company arising in connection with the Award or this Agreement.  In any dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.

25.The Plan.  This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

26.Clawback.To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Committee,  this Award and amounts or shares paid or payable pursuant to or with respect to this Award shall be subject to the provisions of any applicable clawback policies or procedures adopted by the Company or its affiliates, which clawback policies or procedures may provide for forfeiture, repurchase and/or recoupment of this Award and amounts paid or payable pursuant to or with respect to such Award.  Notwithstanding any provision of the Agreement to the contrary, the Company reserves the right, without your consent or the consent of any beneficiary of this Award, to adopt any such clawback policies and procedures, including such policies and procedures applicable to this Agreement with retroactive effect. By your acceptance of a cash payment pursuant to this

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Executive (2018):

Agreement, you are bound by such clawback policies or procedures and you may not seek indemnification or contribution from the Company for any amounts clawed back.

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Executive (2018):

Executed by the Company as of the Award Date.

W&T Offshore, Inc.

By: ___________

       Tracy W. Krohn, Chief Executive Officer

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Exhibit 10.5

Appendix A - For Annual Plan

Performance Goals

The Performance Goals for your 2018 Annual Incentive Award are set forth below and will be utilized to calculate your Total Performance Score utilizing straight-line interpolation.  The Committee shall review, analyze and certify the achievement of each of the criterion below, either for the Company or yourself, as applicable, and shall determine your Total Performance Score according to the aggregate number of points, expressed as a percentage, you receive from each of the Performance Goals below. For the sake of clarity, with respect to negative metrics such as LOE and G&A, HSE&R, and Cost Control, the Performance Goals should be read as being below the “Threshold”, “Target” and “Maximum” levels.    

A-1

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A-2

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HSE&R Score Calculation Details

TRIR (Total Recordable Incident Rate):  Total Number of Recordable Cases (occupational injury requiring medical treatment) x 200,000/divided by total hours worked by all employees during the year covered

Spill ratio:  Barrels spilled / millions of barrels produced

INC to Component Ratio:  Number of INCs (Incidents of Non-Compliance) / number of components inspected by BSEE  

A-3

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EX-10.6

Exhibit 10.6

W&T OFFSHORE, INC.

AMENDED AND RESTATED INCENTIVE COMPENSATION PLAN

2018 EXECUTIVE LONG TERM INCENTIVE PLAN AGREEMENT

This Executive Long Term Incentive Plan Agreement (this “Agreement”) is made and entered into as of August 15, 2018 (the “Date of Grant”), by and between W&T Offshore, Inc., a Texas corporation (the “Company”) and the executive whose name appears in the footer below (“you”);

WHEREAS, the Company in order to induce you to enter into and to continue and dedicate service to the Company and to materially contribute to the success of the Company agrees to grant you this restricted stock unit and/or cash award;

WHEREAS, the Company adopted the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, as it may be amended from time to time (the “Plan”) under which the Company is authorized to grant stock-based awards to certain employees of the Company; and

WHEREAS, the Company adopted the W&T Offshore, Inc. Stock Ownership and Retention Policy, as it may be amended from time to time (the “Policy”) under which the Company has established various stock ownership and retention requirements; and

NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the grant of the Award is made subject to the following terms and conditions:

1.The Grant.  Subject to the conditions set forth below and the adjustment provisions of Section 2(b), the Company hereby grants to you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary or other compensation for your services for the Company, an award consisting of (i)_______________ shares of restricted stock units in accordance with the terms and conditions set forth herein and in the Plan (the “Restricted Stock Units”) and (ii) $____ in cash (the “Cash Grant”) (the Restricted Stock Units and the Cash Grant shall be referred to together as  the “Award” ). The Award is equal to __% of your Base Salary (defined below).  The Restricted Stock Units included in the Award are based on the strike price set by the Company for 2018. For the avoidance of doubt, the Cash Grant will be paid if, as and when the Restricted Stock Units vest under this Agreement and the Plan. To the extent you commenced employment after the beginning of the initial performance period, the Award has been adjusted to reflect that fact.  

2.Vesting Date, Adjustment, and Other Restrictions.  Subject to the terms and conditions of this Agreement and the Plan, including, without limitation, Section 5, the Award will vest, subject to the Performance Vesting Requirement, on December 14, 2020 (the “Vesting Date”).

(a)Performance Vesting Requirement. The “Performance Vesting Requirement” means the achievement of the “Performance Goals,” which are performance

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criteria established by the Committee pursuant to Section 7 of the Plan and set forth in Appendix A attached hereto.  

(b)Adjustments Following the Satisfaction of the Performance Vesting Requirement.  Immediately following the Committee’s certification of the satisfaction of the applicable Performance Vesting Requirement and the applicable level of achievement attained in connection therewith, the Award subject to a Performance Vesting Requirement granted to you pursuant to Section 1 of this Agreement shall be adjusted to reflect the achievement of the Performance Goals during the applicable performance period. To the extent after the Date of the Grant you were on an approved, unpaid leave of absence  during any part of the applicable performance period, the Award  subject to that Performance Vesting Requirement shall be further adjusted to equal  (x)  the Award subject to that Performance Vesting Requirement adjusted above to reflect the achievement of the Performance Goals times (y) a number equal to the quotient resulting from your Actual Base Salary (as hereinafter defined) divided by your Base Salary (as hereinafter defined).  In addition, the Committee has the right to further increase, reduce or eliminate the Award granted to you for any reason regardless of the satisfaction of the Performance Vesting Requirement and the applicable level of achievement attained in connection therewith.  In the event of a negative adjustment, the remaining Award subject to that Performance Vesting granted to you pursuant to Section 1 of this Agreement not eligible for vesting shall be forfeited as of the end of the applicable performance period. The Committee shall promptly notify you of any and all adjustments made to your Award pursuant to this Section 2(b).

For purposes of this Agreement, “Base Salary” means your annual pay rate in effect at the beginning of the applicable performance period calculated over the applicable performance period, (i) including any amounts deferred pursuant to an election under any 401(k) plan, pre-tax premium plan, deferred compensation plan, or flexible spending account sponsored by the Company or any Subsidiary, but (ii) excluding any incentive compensation, employee benefit, or other cash benefit paid or provided under any incentive, bonus or employee benefit plan sponsored by the Company or any Subsidiary, and/or any excellence award, gains upon stock option exercises, restricted stock grants or vesting, moving or travel expense reimbursement, imputed income, or tax gross-ups, without regard to whether the payment or gain is taxable income to you. To the extent you commence employment after the beginning of the initial performance period, your Base Salary for that initial performance period shall mean the base salary you would receive working (based on your annual pay rate in effect on your first day of employment) for the period from your first day of employment until the end of the initial performance period.

For purposes of this Agreement, “Actual Base Salary” means the  base salary you actually received during the applicable performance period calculated as of the last day of the applicable performance period, (i) including any amounts deferred pursuant to an election under any 401(k) plan, pre-tax premium plan, deferred compensation plan, or flexible spending account sponsored by the Company or any Subsidiary, and any overtime paid to you as an offshore employee required by your standard work schedule, but (ii)  excluding any incentive compensation, employee benefit, or other benefit paid or provided under any incentive, bonus or employee benefit plan sponsored by the Company or any Subsidiary, all overtime paid other than as specified in (i) above and/or any excellence award, gains upon stock option exercises,

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restricted stock grants or vesting, moving or travel expense reimbursement, sign on bonus, imputed income, or tax gross-ups, without regard to whether the payment or gain is taxable income to you.

By way of example only, the Performance Vesting Requirement adjustment described above will operate as follows: if, as part of your Award,  you are granted 1,000 Restricted Stock Units subject to a Performance Vesting Requirement on the Date of Grant, and the level of achievement of the Performance Goals during the applicable performance period is reached at a level the Company has designated as a 75% achievement level, it will only be possible for you to vest in 750 Restricted Stock Units on the Vesting Date and the remaining 250 Restricted Stock Units shall be forfeited as of the end of the performance period.  In addition, to the extent you were on approved, unpaid leave during any part of the applicable performance period, the number of such Restricted Stock Units shall be further adjusted as described in the first paragraph of Section 2(b) to the extent your Actual Base Salary for the applicable performance period is less than your Base Salary for such performance period. As noted in the first paragraph of Section 2(b), the Committee has the right to further increase, reduce or eliminate your Award (including the number of Restricted Stock Units granted to you) for any reason regardless of the satisfaction of the Performance Vesting Requirement and the applicable level of achievement attained in connection therewith.

(c)Other Restrictions.  Subject to Section 5 of this Agreement, the restrictions on your Award will expire on the Vesting Date only if you have been an employee of the Company or of a Subsidiary continuously from the Date of Grant through the Vesting Date.  In the event that the Performance Vesting Requirement is not satisfied, no portion of the Award subject to that Performance Vesting Requirement shall become vested.  Restricted Stock Units that have become vested pursuant to this Section 2 shall be referred to herein as the “Vested Units.” That portion of the Cash Grant that has become vested pursuant to this Section 2 shall be referred to herein as the “Vested Cash Grant.”

3.Settlement.  

(a)Form of Settlement.  The Committee, in its sole discretion, shall determine at the time of such settlement whether the Vested Units will be settled: (i) in a single lump sum cash payment in an amount equal to the Fair Market Value of Stock as of the date of settlement multiplied by the number of Vested Units to be settled, (ii) in shares of such Stock, or (iii) in a combination of cash and shares of Stock.  Settlement of Vested Units shall be subject to and pursuant to rules and procedures established by the Committee in its sole discretion. The Committee, in its sole discretion, shall determine at the time of such settlement whether the Vested Cash Grant will be settled: (i) in a single lump sum cash payment, (ii) in shares of Stock equal to the Vested Cash Grant divided by the Fair Market Value of Stock as of the date of settlement to, or (iii) in a combination of cash and shares of Stock. Settlement of Vested Cash Grant shall be subject to and pursuant to rules and procedures established by the Committee in its sole discretion.

(b)Time of Settlement.  The Vested Units and Vested Cash Grant shall be settled by the Company as soon as administratively feasible following the Vesting Date, but in no event shall such settlement occur later than 75 days following the Vesting Date.  

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4.Restrictions, Forfeiture and Limitations on Ownership.  The shares of Restricted Stock Units are restricted in the sense that they may be forfeited to the Company prior to the time the Restricted Stock Units are deemed Vested Units. You, or your executor, administrator, heirs, or legatees shall have the right to vote any shares of Stock you may receive as settlement of the Vested Units and hold all other privileges of a shareholder of the Company only from the date of issuance of a Stock certificate in your name representing payment of a Vested Unit in the form of a share of Stock, or the delivery of the Stock to the Company’s transfer agent, as applicable.

5.Termination of Services or Change in Control.

(a)Termination due to your Death or Disability. Following the satisfaction of the Performance Vesting Requirement, if your employment with the Company and any of its Subsidiaries is terminated as a result of your death or Disability (as defined below), then the forfeiture restrictions on your Award subject to that Performance Vesting Requirement, subject to any adjustment pursuant to Section 2(b) above, shall automatically lapse, and in the case of your Disability, subject to Section 11 of this Agreement.  If your employment with the Company and any of its Subsidiaries is terminated as a result of your death or Disability prior to the satisfaction of the Performance Vesting Requirement, no portion of your Award subject to that Performance Vesting Requirement will become vested.

For purposes of this Section 5(a), the term “Disability” shall have the meaning given such term in any written employment, severance or other similar individual agreement (an “Individual Agreement”) between you and the Company. In the event that there is no existing written Individual Agreement between you and the Company or if any such agreement does not define Disability, the term “Disability” shall mean: (i) a physical or mental impairment of sufficient severity that, in the sole opinion of the Company, (A) you are unable to continue performing the duties assigned to you prior to such impairment or (B) your condition entitles you to disability benefits under any insurance or employee benefit plan of the Company or its Subsidiaries, and (ii) the impairment or condition is cited by the Company as the reason for your termination; provided, however, that in all cases, the term Disability shall be applied and interpreted in compliance with section 409A of the Code and the regulations thereunder.

(b)Termination due to your Normal Retirement.  Following the satisfaction of the Performance Vesting Requirement, if your employment with the Company and any of its Subsidiaries is terminated as a result of your Normal Retirement prior to the Vesting Date, then the restrictions on your Award subject to that Performance Vesting Requirement, subject to any adjustment pursuant to Section 2(b) above, shall automatically lapse pro-rata in relation to the amount of time you have been employed by the Company or any of its Subsidiaries, as described below; provided, however, that such restrictions shall lapse subject to the additional provisions of Section 11 of this Agreement, if applicable.  Solely for purposes of determining that portion of your Award that may lapse or vest pursuant to this Section 5(b), the Award subject to that Performance Vesting Requirement, as adjusted pursuant to Section 2(b) above, shall be referred to in two portions, two-thirds (2/3) of the Award shall be the “Two-Year Portion”; the remaining and final one-third (1/3) of the Award shall be the “Three-Year Portion.”  Following a termination of your employment due to your Normal Retirement:

Executive (2018):4

(i)restrictions will lapse on the Two-Year Portion equal to the product of (A) two-thirds (2/3) of your total Award granted to you, subject to any adjustment pursuant to Section 2(b) above, times (B) a fraction, the numerator of which is the number of full months (counting the month in which your termination of employment occurs as a full month), beginning with the first day of the first month of the year in which the Date of Grant occurs, during which you were employed by the Company and/or any Subsidiary (not to exceed 24) and the denominator of which is 24; plus

(ii)restrictions will lapse on \ the Three-Year Portion equal to the product of (A) one-third (1/3) of your total Award, subject to any adjustment pursuant to Section 2(b) above, times (B) a fraction, the numerator of which is the number of full months (counting the month in which your termination of employment occurs as a full month), beginning with the first day of the first  month of the year in which the Date of Grant occurs, during which you were employed by the Company and/or any Subsidiary and the denominator of which is 36.

Notwithstanding anything to the contrary in Section 2 or the remainder of this Section 5, as an example calculation, an individual who was employed at January 1, 2018 and terminating employment due to Normal Retirement in April 2019 with an Award consisting of 3,000 shares of Restricted Stock Units and $10,000.00 in Cash Grant shall receive the following adjusted award under this Agreement:

If your employment with the Company and any of its Subsidiaries is terminated as a result of your Normal Retirement prior to the satisfaction of the Performance Vesting Requirement, no portion of your Award subject to that Performance Vesting Requirement will become Vested Units.  For purposes of this Section 5(b), the term “Normal Retirement” shall have the meaning given such term in any Individual Agreement between you and the Company. In the event that there is no existing written Individual Agreement between you and the Company or if any such agreement does not define Normal Retirement, the term “Normal Retirement” shall mean the termination of your employment with the Company and each of its Subsidiaries by which you are employed  due to your voluntary retirement on or after the date that you attain age 67.

(c)Termination for Any Other Reason.  Subject to Sections 5(d) and 5(e) below, if your employment with the Company or any of its Subsidiaries is terminated for any other reason other than your death, Disability or your Normal Retirement prior to the Vesting Date, then that portion, if any, of the Award granted pursuant to this Agreement for which have not become either Vested Units or Vested Cash Grants as of the date of termination shall become null and void as of the date of such termination.

Executive (2018):5

(d)Change in Control.  

(i)Prior to Satisfaction of the Performance Vesting Requirement. Notwithstanding anything to the contrary in Section 2 or the remainder of this Section 5, in the event that a Change in Control is consummated prior to both the Vesting Date and the end of the applicable performance period for which the Performance Vesting Requirement relates, forfeiture restrictions on your Award  subject to that Performance Vesting Requirement granted to you pursuant to Section 1 of this Agreement shall automatically lapse and the Award  subject to that Performance Vesting Requirement will vest, subject further to Section 11 of this Agreement.  

(ii)Following the Satisfaction of the Performance Vesting Requirement.  Notwithstanding anything to the contrary in the remainder of this Section 5, in the event that a Change in Control is consummated prior to the Vesting Date but following the satisfaction of the Performance Vesting Requirement, forfeiture restrictions on your Award subject to that Performance Vesting Requirement, subject to any adjustment pursuant to Section 2(b) above, shall automatically lapse and such Award subject to that Performance Vesting Requirement will vest subject further to Section 11 of this Agreement.   For further clarity, in the event that the Change in Control is consummated following the applicable performance period to which the Performance Vesting Requirement relates, but the Performance Vesting Requirement was not achieved during such time, no portion of the Award subject to that Performance Vesting Requirement shall become vested upon a Change in Control.

(iii)Other restrictions.  Nothing within this Section 5(d) is intended to modify Sections 5(a) or 5(b) above regarding the full acceleration or pro-rata acceleration, as applicable, of your Award upon a termination of employment due to death, Disability or Normal Retirement.  The provisions of Sections 5(a) and 5(b) shall apply to a termination of your employment for death, Disability or Normal Retirement, as applicable, whether or not such a termination of employment were to occur in connection with a Change in Control.

(e)Effect of Individual Agreement.  Notwithstanding any provision herein to the contrary, in the event of any inconsistency between this Section 5 and any Individual Agreement entered into by and between you and the Company, the terms of such an Individual Agreement shall control.

6.Leave of Absence.  With respect to the Award, the Company may, in its sole discretion, determine that if you are on leave of absence for any reason you will be considered to still be in the employ of the Company, provided that, except as set forth in Section 2(b), rights to the Restricted Stock Units and Cash Grant during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began.

7.Delivery of Stock.  In the event the Committee determines to settle the Restricted Stock Units in the form of Stock, promptly following the expiration of the restrictions on the Restricted Stock Units as contemplated in Sections 2 or 5 of this Agreement, the Company shall either cause to be issued and delivered to you or your designee a certificate or other evidence of the number of Restricted Stock Units as to which restrictions have lapsed, free of any restrictive legend relating to the lapsed restrictions, or cause those number of Restricted Stock Units to be

Executive (2018):6

properly registered with the Company’s transfer agent as appropriate, upon receipt by the Company of any tax withholding as may be requested pursuant to Section 8 of this Agreement.  The value of such Restricted Stock Units shall not bear any interest owing to the passage of time.

8.Payment of Taxes.  The Company may require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company), an amount the Company deems necessary to satisfy its (or its Subsidiary’s) current or future obligation to withhold federal, state or local income or other taxes that you incur as a result of the Award.  With respect to any such required tax withholding, the Company will withhold from the Award to be issued to you under this Agreement, as applicable, the cash amount or the number of shares necessary to satisfy the Company’s obligation to withhold taxes; where the Restricted Stock Units or Cash Grant will be settled in shares of Stock, such a determination will be based on the shares’ Fair Market Value at the time such determination is made.  In the event the Restricted Stock Units or Cash Grant are settled in shares of Stock, and Company determines that the aggregate Fair Market Value of the shares of Stock withheld as payment of any tax withholding obligation is insufficient to discharge that tax withholding obligation, then you must pay to the Company, in cash, the amount of that deficiency immediately upon the Company’s request.

9.Compliance with Securities Law.  Notwithstanding any provision of this Agreement to the contrary, in the event the Restricted Stock Units or Cash Grant are settled in shares of Stock, the issuance of Stock will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Stock may then be listed.  No Stock will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Stock may then be listed.  In addition, Stock will not be issued hereunder unless (a) a registration statement under the Securities Act of 1933, as amended (the “Act”), is at the time of issuance in effect with respect to the shares issued or (b) in the opinion of legal counsel to the Company, the shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Act.  The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any shares subject to the Award will relieve the Company of any liability in respect of the failure to issue such shares as to which such requisite authority has not been obtained.  As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company.  From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate Persons to make shares of Stock available for issuance.

10.Right of the Company and Subsidiaries to Terminate Employment.  Nothing in this Agreement confers upon you the right to continue in the employ of the Company or any Subsidiary, or interfere in any way with the rights of the Company or any Subsidiary to terminate your employment at any time, with or without cause.

Executive (2018):7

11.Non-Compete Agreements.  The Company, in its sole discretion, may require you to execute a separate non-compete, non-solicitation, or similar agreement in connection with the grant of the Award pursuant to this Agreement or in connection with the acceleration of any portion of the Award in accordance with the provisions of Section 5 of this Agreement.  

12.Furnish Information.  You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

13.Remedies.  The parties to this Agreement shall be entitled to recover from each other reasonable attorneys’ fees incurred in connection with the successful enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.

14.No Liability for Good Faith Determinations.  The Company, the Committee and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Award granted hereunder.

15.Execution of Receipts and Releases.  Any payment of cash or any issuance or transfer of shares of Stock or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as the Company shall determine.

16.No Guarantee of Interests.  The Company, the members of the Committee and the Board do not guarantee the Stock of the Company from loss or depreciation.

17.Notice.  All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or if earlier the date it is sent via certified United States mail.

18.Waiver of Notice.  Any person entitled to notice hereunder may waive such notice in writing.

19.Information Confidential.  As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors.  In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you.

Executive (2018):8

20.Successors.  This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns, including, but not limited to, any successor entity resulting from a Change in Control.

21.Severability.  If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

22.Company Action.  Any action required of the Company shall be by authority of the Board or by a person or entity authorized to act by the Board.

23.Headings.  The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

24.Governing Law.  All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of Texas, without giving any effect to any conflict of law provisions thereof, except to the extent Texas state law is preempted by federal law.  The obligation of the Company to sell and deliver Stock hereunder is subject to applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Stock.

25.Consent to Texas Jurisdiction and Venue.  You hereby consent and agree that state courts located in HarrisCounty, Texas and the United States District Court for the SouthernDistrict of Texas each shall have personal jurisdiction and proper venue with respect to any dispute between you and the Company arising in connection with the Award or this Agreement.  In any dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.  

26.Amendment.  This Agreement may be amended by the Board or by the Committee at any time (a) if the Board or the Committee determines, in its sole discretion, that amendment is necessary or advisable in light of any addition to or change in any federal or state tax or securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies to the Award; or (b) other than in the circumstances described in clause (a) or provided in the Plan, with your consent.  

27.Transfer.  This Agreement and the Award granted hereunder will not be transferable by you other than by will or the laws of descent and distribution, or as otherwise provided by the Plan.

28.The Plan.  This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

29.The Policy.  This Agreement and this Award is subject to all the terms, conditions, limitations and restrictions contained within the Policy.

30.Clawback.To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Committee,  this Award

Executive (2018):9

and amounts or shares paid or payable pursuant to or with respect to this Award shall be subject to the provisions of any applicable clawback policies or procedures adopted by the Company or its affiliates, which clawback policies or procedures may provide for forfeiture, repurchase and/or recoupment of this Award and amounts or shares paid or payable pursuant to or with respect to such Award.  Notwithstanding any provision of the Agreement to the contrary, the Company reserves the right, without your consent or the consent of any beneficiary of this Award, to adopt any such clawback policies and procedures, including such policies and procedures applicable to this Agreement with retroactive effect. Your acceptance of this Award shall constitute your agreement (1) to be bound by such clawback policies or procedures and (2) to not seek indemnification or contribution from the Company for any amounts clawed back.

W&T OFFSHORE, INC.

By: ___________

       Tracy W. Krohn, Chief Executive Officer

Executive (2018):10

Appendix A

Performance Goals for 2018 Award

The Performance Goals for your Award shall be comprised of the business criterion noted below.  Subject to the achievement of the applicable Performance Level (defined below) for the applicable performance period and resulting adjustments under Section 2(b) of the Agreement, your Award, as adjusted, will become Vested Units and Vested Cash Grants on the Vesting Date, only if you have been an employee of the Company or of a Subsidiary continuously from the Date of Grant through the Vesting Date.  The applicable Scale between the Performance Levels on the charts below will be calculated using straight-line interpolation. The Committee shall review, analyze and certify the achievement of the Performance Level for each business criteria for the applicable performance period and shall determine whether the Performance Vesting Requirement has been met, in accordance with the Agreement and the terms of the Plan.  For determination of meeting the Performance Vesting Requirement, the Performance Level achieved for the applicable performance period shall be deemed achieved effective as of the last day of the applicable performance period, despite any delay that may occur in determining which Performance Level is met during the Committee’s certification process.

Business Criteria

Criteria	Percentage of 100% of the Award  Which is Subject to Performance Criteria	Performance Period
Adjusted EBITDA(1) for the Performance Period as approved by the Compensation Committee (Measurement rounded to nearest million)	40%	The full calendar year, from January 1 to December 31, 2018

Performance Level (000)	Scale
(“Target”):$260,000 or greater	100%
$200,000 or greater	75%
$90,000 or greater	50%
less than $90,000	0%

(1) We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. Adjusted EBITDA excludes the unrealized gain or loss related to our derivative contracts, contract option fee, gain or loss on extinguishment of debt, gains or losses in connection with litigation settlements, and other items that are, in the sole discretion of the Compensation Committee appropriate adjustment to reflect normalized results.   

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Criteria	Percentage of 100% of the Award Which Is  Subject to Performance Criteria	Performance Period
Adjusted EBITDA Margin Percentage for the Performance Period (Measurement rounded to nearest 1/10th decimal)	60%	The full calendar year, from January 1 to December 31, 2018

Performance Level	Scale
Greater than or equal to 52% (“Target”)	100%
Greater than or equal to 50%	75%
Greater than or equal to 45%	50%
Greater than or equal to 40%	25%
Less than 40%	0%

Executive (2018):12

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Tracy W. Krohn, certify that:

1. I have reviewed this quarterly report on Form 10-Q of W&T Offshore, Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2018	/s/  Tracy W. Krohn
	Tracy W. Krohn
	Chairman, Chief Executive Officer and Director
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Janet Yang, certify that:

1. I have reviewed this quarterly report on Form 10-Q of W&T Offshore, Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2018	/s/  JANET YANG
	Janet Yang
	Vice President, Acting Chief Financial Officer
	And Chief Accounting Officer (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of W&T Offshore, Inc. (the “Company”), hereby certifies, to the best of his knowledge, that the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2018 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that information contained in such Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 1, 2018	/s/  Tracy W. Krohn
	Tracy W. Krohn
	Chairman, Chief Executive Officer and Director
	(Principal Executive Officer)

Date:  November 1, 2018	/s/  JANET YANG
	Janet Yang
	Vice President, Acting Chief Financial Officer And Chief Accounting Officer
	(Principal Financial Officer)

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Trading Symbol	WTI
Entity Registrant Name	W&T OFFSHORE INC
Entity Central Index Key	0001288403
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		139,153,798

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 339,063	$ 99,058
Receivables:
Oil and natural gas sales	49,482	45,443
Joint interest	16,493	19,754
Income taxes	65,240	13,006
Total receivables	131,215	78,203
Prepaid expenses and other assets (Note 1)	19,699	13,419
Total current assets	489,977	190,680
Oil and natural gas properties and other, net - at cost: (Note 1)	522,781	579,016
Restricted deposits for asset retirement obligations	20,577	25,394
Income taxes receivable		52,097
Other assets (Note 1)	69,014	60,393
Total assets	1,102,349	907,580
Current liabilities:
Accounts payable	95,502	79,667
Undistributed oil and natural gas proceeds	34,225	20,129
Advances from joint interest partners	31,012	3,998
Asset retirement obligations	30,207	23,613
Current maturities of long-term debt: (Note 2)
Principal	189,829
Carrying value adjustments	34,985	22,925
Current maturities of long-term debt - carrying value	224,814	22,925
Accrued liabilities (Note 1)	31,058	17,930
Total current liabilities	446,818	168,262
Long-term debt: (Note 2)
Principal	713,365	889,790
Carrying value adjustments	45,758	79,337
Long term debt, less current portion - carrying value	759,123	969,127
Asset retirement obligations, less current portion	283,009	276,833
Other liabilities (Note 1)	73,175	66,866
Commitments and contingencies (Note 11)
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at September 30, 2018 and December 31, 2017
Common stock, $0.00001 par value; 200,000,000 shares authorized; 142,022,971 issued and 139,153,798 outstanding at September 30, 2018 and 141,960,462 issued and 139,091,289 outstanding December 31, 2017	1	1
Additional paid-in capital	549,569	545,820
Retained earnings (deficit)	(985,179)	(1,095,162)
Treasury stock, at cost; 2,869,173 shares for both dates presented	(24,167)	(24,167)
Total shareholders' equity (deficit)	(459,776)	(573,508)
Total liabilities and shareholders' equity (deficit)	$ 1,102,349	$ 907,580

XML

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.00001	$ 0.00001
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, issued	0	0
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, issued	142,022,971	141,960,462
Common stock, outstanding	139,153,798	139,091,289
Treasury stock, shares	2,869,173	2,869,173

XML

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Total revenues	$ 153,459	$ 110,281	$ 437,284	$ 357,997
Operating costs and expenses:
Lease operating expenses	37,430	35,134	109,855	106,817
Production taxes	432	340	1,326	1,304
Depreciation, depletion, amortization and accretion	36,969	36,489	114,807	116,843
General and administrative expenses	15,990	15,631	45,248	45,379
Derivative (gain) loss	(288)	2,879	5,931	(4,765)
Total costs and expenses	96,312	94,581	292,931	281,213
Operating income	57,147	15,700	144,353	76,784
Interest expense	11,630	11,554	35,100	34,284
Gain on exchange of debt				7,811
Other (income) expense, net	(885)	(41)	(1,093)	5,073
Income before income tax expense (benefit)	46,402	4,187	110,346	45,238
Income tax expense (benefit)	142	5,484	363	(11,079)
Net income (loss)	$ 46,260	$ (1,297)	$ 109,983	$ 56,317
Basic and diluted earnings (loss) per common share	$ 0.32	$ (0.01)	$ 0.76	$ 0.39
Oil
Revenues:
Total revenues	$ 119,482	$ 78,055	$ 333,406	$ 248,648
NGLs
Revenues:
Total revenues	10,087	6,605	28,481	22,401
Natural gas
Revenues:
Total revenues	22,641	24,113	71,485	83,129
Other
Revenues:
Total revenues	1,249	1,508	3,912	3,819
Gathering and transportation
Operating costs and expenses:
Operating costs and expenses	$ 5,779	$ 4,108	$ 15,764	$ 15,635

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Condensed Consolidated Statement of Changes in Shareholders' Deficit - 9 months ended Sep. 30, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock Outstanding	Additional Paid-In Capital	Retained Earnings (Deficit)	Treasury Stock
Beginning Balances at Dec. 31, 2017	$ (573,508)	$ 1	$ 545,820	$ (1,095,162)	$ (24,167)
Beginning Balances (in shares) at Dec. 31, 2017		139,091			2,869
Share-based compensation	3,808		3,808
Stock Issued, shares		63
RSUs surrendered for payroll taxes	(59)		(59)
Net income	109,983			109,983
Ending Balances at Sep. 30, 2018	$ (459,776)	$ 1	$ 549,569	$ (985,179)	$ (24,167)
Ending Balances (in shares) at Sep. 30, 2018		139,154			2,869

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Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating activities:
Net income	$ 109,983	$ 56,317
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	114,807	116,843
Gain on exchange of debt		(7,811)
Amortization of debt items and other items	1,796	1,271
Share-based compensation	3,808	5,449
Derivative (gain) loss	5,931	(4,765)
Cash receipts (payments) on derivative settlements, net	(3,091)	3,924
Deferred income taxes	363	321
Changes in operating assets and liabilities:
Oil and natural gas receivables	(4,039)	3,906
Joint interest receivables	3,261	8
Insurance reimbursements		31,740
Income taxes	(139)	320
Prepaid expenses and other assets	(8,467)	2,194
Escrow deposit - Apache lawsuit		(49,500)
Asset retirement obligation settlements	(22,764)	(56,226)
Cash advances from JV partners	27,014	(786)
Accounts payable, accrued liabilities and other	66,389	27,115
Net cash provided by operating activities	294,852	130,320
Investing activities:
Investment in oil and natural gas properties and equipment	(59,161)	(79,088)
Changes in operating assets and liabilities associated with investing activities	(20,261)	5,679
Acquisition of property interest	(16,782)
Proceeds from sale of assets	50,474
Purchases of furniture, fixtures and other		(905)
Net cash used in investing activities	(45,730)	(74,314)
Financing activities:
Other	(26)	(372)
Net cash used in financing activities	(9,117)	(20,078)
Increase in cash and cash equivalents	240,005	35,928
Cash and cash equivalents, beginning of period	99,058	70,236
Cash and cash equivalents, end of period	339,063	106,164
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Payment of interest	(6,171)	(6,170)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest	$ (2,920)	(7,335)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Financing activities:
Payment of interest		$ (6,201)

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Basis of Presentation

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

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. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”) 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, 2017.

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.

Recent Events.  The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth.  The average realized prices of crude oil and NGLs improved during the nine months ended September 30, 2018 compared to the average realized prices in the nine months ended September 30, 2017.  

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”) which substantially changed our capital structure.  The Senior Second Lien Notes were issued at par and have a maturity date of November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “New Revolving Credit Agreement”) which provides us with a revolving bank credit facility with an initial borrowing base of $250.0 million (increasing from $150.0 million under our prior facility).  Letters of credit may be issued in amounts up to $30.0 million provided availability exists.  The New Revolving Credit Agreement matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  We refer to these transactions and the related repurchases and retirements, repayments and redemptions of all of our outstanding notes and term loans collectively as the “2018 Refinancing Transaction.”  See Note 12, Subsequent Events, for additional information.  

We believe we will have adequate available liquidity to fund our operations through November 2019, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or future Bureau of Ocean Energy Management (“BOEM”) bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

See our Annual Report on Form 10-K for the year ended December 31, 2017 concerning risks related to our business and events occurring during 2017 and other information and the Notes herein for additional information.  

Accounting Standard Updates Effective January 1, 2018:

   Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018.  The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business.  In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business.          

Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us in the period ending March 31, 2018.  We reviewed our contracts using the five-step revenue recognition model, which did not identify any changes required as to the amount or timing of revenue recognition.  We adopted the new standard using the modified retrospective approach which did not result in any cumulative-effect adjustment on the date of adoption.  The implementation of ASU 2014-09 resulted in a change in our reporting in the Condensed Consolidated Statement of Operations so that we now report revenue streams separately for crude oil, NGLs, natural gas and other revenues in compliance with the new standard.    

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

Reclassification.  Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows:  Within the Net Cash Provided by Operating Activities of the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items, of which did not change the total amount previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets or the Condensed Consolidated Statements of Operations.

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

	September 30,		December 31,
	2018		2017
Prepaid/accrued insurance	$	4,214	$	2,401
Surety bond unamortized premiums		2,847		2,676
Prepaid deposits related to royalties		9,698		6,456
Advances for capital expenditures		860		—
Derivative contract premiums		791		—
Other		1,289		1,886
Prepaid expenses and other assets	$	19,699	$	13,419

Oil and Natural Gas Properties and Other, Net – at cost.  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Oil and natural gas properties and equipment	$	8,146,742	$	8,102,044
Furniture, fixtures and other		20,227		21,831
Total property and equipment		8,166,969		8,123,875
Less accumulated depreciation, depletion    and amortization		7,644,188		7,544,859
Oil and natural gas properties and other, net	$	522,781	$	579,016

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

	September 30,		December 31,
	2018		2017
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Appeal bond deposits		6,925		6,925
Investment in White Cap, LLC		2,648		2,511
Deposit related to letters of credit		4,702		—
Unamortized brokerage fee for Monza		1,981		—
Proportional consolidation of Monza's    other assets  (Note 4)		2,212		—
Other		1,046		1,457
Total other assets	$	69,014	$	60,393

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

	September 30,		December 31,
	2018		2017
Accrued interest	$	15,041	$	4,200
Accrued salaries/payroll taxes/benefits		2,291		2,454
Incentive compensation plans		6,452		7,366
Litigation accruals		3,604		3,480
Derivative contracts		3,252		84
Other		418		346
Total accrued liabilities	$	31,058	$	17,930

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

	September 30,		December 31,
	2018		2017
Apache lawsuit	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		11,379		11,015
Dispute related to royalty deductions		4,687		—
Dispute related to royalty-in-kind		2,100		914
Other		5,509		5,437
Total other liabilities (long-term)	$	73,175	$	66,866

Recent Accounting Developments.  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months.  Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a financing or operating lease.  However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space, which is primarily in Houston, Texas, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases nor do we have any leases recorded on the Condensed Consolidated Balance Sheets.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

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

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

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Long-Term Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

2.  Long-Term Debt

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

	September 30, 2018								December 31, 2017
			Adjustments to								Adjustments to
			Carrying			Carrying					Carrying			Carrying
	Principal		Value (1)			Value			Principal		Value (1)			Value
11.00% 1.5 Lien Term Loan,      due November 2019:
Principal	$	75,000	$	—		$	75,000		$	75,000	$	—		$	75,000
Future interest payments		—		9,425			9,425			—		15,596			15,596
Subtotal		75,000		9,425			84,425			75,000		15,596			90,596
9.00 % Second Lien Term Loan,     due May 2020:		300,000		—			300,000			300,000		—			300,000
9.00%/10.75% Second Lien     PIK Toggle Notes, due May 2020:
Principal		177,513		—			177,513			171,769		—			171,769
Future payments-in-kind		—		—			—			—		5,745			5,745
Future interest payments		—		31,952			31,952			—		34,872			34,872
Subtotal		177,513		31,952			209,465			171,769		40,617			212,386
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		160,852		—			160,852			153,192		—			153,192
Future payments-in-kind		—		3,664			3,664			—		11,323			11,323
Future interest payments		—		38,682			38,682			—		38,682			38,682
Subtotal		160,852		42,346			203,198			153,192		50,005			203,197
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(2,980	)		(2,980	)		—		(3,956	)		(3,956	)
Total long-term debt		903,194		80,743			983,937			889,790		102,262			992,052
Current maturities of long-term debt (2)		189,829		34,985			224,814			—		22,925			22,925
Long term debt, less current    maturities	$	713,365	$	45,758		$	759,123		$	889,790	$	79,337		$	969,127

(1) Future interest payments and future payments-in-kind are recorded on an undiscounted basis.

(2) Represents principal of the 8.50% Unsecured Senior Notes due June 15, 2019 and future interest payments on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes due within twelve months.

Debt Issuance, Repayment of Long-Term Debt and the New Revolving Credit Agreement

As described in Note 12, Subsequent Events, on October 18, 2018, we issued the Senior Second Lien Notes and entered into the New Revolving Credit Agreement.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  

The following discussion and descriptions relate to our long-term debt as of September 30, 2018:  

Accounting for Certain Debt Instruments

We accounted for a transaction executed on September 7, 2016 as a Troubled Debt Restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the 9.00/ 10.75% Second Lien Payment-In-Kind (“PIK”) Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); the 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”) and the 11.00% 1.5 Lien Term Loan, due November 15, 2019 (the “1.5 Lien Term Loan”) (collectively, the “2016 Restructuring Transactions”) are measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the 2016 Restructuring Transactions in the Condensed Consolidated Statements of Operations for the periods presented.  Additionally, no interest expense related to the 2016 Restructuring Transactions will be recorded in the fourth quarter of 2018 as payments of interest on the 2016 Restructuring Transactions will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments.  Under ASC 470-60, payments related to the 2016 Restructuring Transactions are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.

The primary terms of our long-term debt are described below:    

Prior Credit Agreement.  The Fifth Amended and Restated Credit Agreement, (the “Prior Credit Agreement”) provided a revolving bank credit facility and would have expired by its term on November 8, 2018.  The primary items of the Prior Credit Agreement are as follows, with certain terms defined under the Prior Credit Agreement:

• The Borrowing Base of $150.0 million.

• Letters of credit limit of up to $150.0 million, provided availability under the revolving bank credit facility exists.      

• The First Lien Leverage Ratio limit of 2.00 to 1.00.

• The Current Ratio, as defined in the Prior Credit Agreement, was required to be greater than 1.00 to 1.00.

• Deposit accounts could only be established with banks under the Prior Credit Agreement with certain exceptions.

• We could not have unrestricted cash balances above $35.0 million if outstanding balances under the Prior Credit Agreement (including letters of credit) are greater than $5.0 million.

• To the extent there are borrowings, they were primarily executed as Eurodollar Loans, and the applicable margins range from 3.00% to 4.00%.

• The commitment fee was 50 basis points for all levels of utilization.

  As of September 30, 2018 and December 31, 2017, we did not have any borrowings outstanding under the Prior Credit Agreement and had $9.7 million and $0.3 million of letters of credit outstanding, respectively.  Available credit as of September 30, 2018 was $140.3 million.  As of September 30, 2018, we had on deposit $4.7 million with the lead bank in compliance with the terms of the Prior Credit Agreement, as letters of credit are considered borrowings and our unrestricted cash balance exceeded $35.0 million.  On October 18, 2018, the Prior Credit Agreement was replaced by the New Revolving Credit Agreement, as described in Note 12,Subsequent Events.  

1.5 Lien Term Loan.  In September 2016, we entered into the 1.5 Lien Term Loan with a maturity date of November 15, 2019.    Interest accrued at 11.00% per annum and is payable quarterly in cash.  The 1.5 Lien Term Loan was secured by a 1.5 priority lien on all of our assets pledged under the Prior Credit Agreement.  The lien securing the 1.5 Lien Term Loan was subordinated to the liens securing the Prior Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows as of September 30, 2018 have been included in the carrying value under ASC 470-60.  On October 18, 2018, the 1.5 Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.

Second Lien Term Loan.  In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which had an annual interest rate of 9.00%.  The Second Lien Term Loan was issued at a 1.0% discount to par with a maturity date of May 15, 2020 and has been recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs as of September 30, 2018.  Interest on the Second Lien Term Loan was payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan was 9.6%, which included amortization of debt issuance costs and discounts.  The Second Lien Term Loan was secured by a second-priority lien on all of our assets that are secured under the Prior Credit Agreement.  The Second Lien Term Loan was effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan (discussed above) and was effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).   On October 18, 2018, the Second Lien Term Loan was repaid in full, as described in Note 12, Subsequent Events.    

Second Lien PIK Toggle Notes.  In September 2016, we issued Second Lien PIK Toggle Notes with a maturity date of May 15, 2020.  Interest was payable on May 15 and November 15 of each year.  For the interest period from November 15, 2017 up to and including March 6, 2018, we had the option to pay all or a portion of interest in-kind at the rate of 10.75% per annum, which if so exercised, is added to the principal amount.  After March 6, 2018, interest was payable in cash at the rate of 9.00% per annum.  The Second Lien PIK Toggle Notes were secured by a second-priority lien on all of our assets that are pledged under the Prior Credit Agreement.  The Second Lien PIK Toggle Notes were effectively subordinate to the Prior Credit Agreement and the 1.5 Lien Term Loan and were effectively pari passu with the Second Lien Term Loan.  On October 18, 2018, all of the outstanding Second Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.

Third Lien PIK Toggle Notes.  In September 2016, we issued Third Lien PIK Toggle Notes with a maturity date of June 15, 2021.  For the interest periods up to and including September 6, 2018, if we so elected, we had the option to pay all or a portion of interest in-kind at a rate of 10.00% per annum.  If so elected, such in-kind were added to the principal amount.  After September 6, 2018, interest was payable in cash at the rate of 8.50% per annum.  The Third Lien PIK Toggle Notes were secured by a third-priority lien on all of our assets that were secured under the Prior Credit Agreement.  The Third Lien PIK Toggle Notes were effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  On October 18, 2018, all of the outstanding Third Lien PIK Toggle Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Unsecured Senior Notes.  Our 8.500% Unsecured Senior Notes outstanding, which had an annual interest rate of 8.50% and maturity date of June 15, 2019, (the “Unsecured Senior Notes”), were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes was payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes was 8.4%, which included amortization of premiums and debt issuance costs.  On October 18, 2018, all of the outstanding Unsecured Senior Notes were repurchased by the Company and retired or irrevocably called for redemption, as described in Note 12, Subsequent Events.  

Covenants.  We were in compliance with all applicable covenants for all of our debt instruments as of September 30, 2018.

For information about fair value measurements for our long-term debt, refer to Note 3, Fair Value Measurements.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

3.  Fair Value Measurements  

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 fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as only one entity has been the holder of the 1.5 Lien Term Loan.  The fair values of our Second Lien Term Loan, Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and Unsecured Senior Notes were based on quoted prices, although the market is not a very active market; therefore, the fair value is classified within Level 2.  

The following table presents the fair value of our long-term debt, all of which are classified as Level 2 within the valuation hierarchy (in thousands):

	Hierarchy	September 30, 2018		December 31, 2017
11.00% 1.5 Lien Term Loan, due November 2019	Level 2	$	75,000	$	75,000
9.00 % Second Lien Term Loan, due May 2020	Level 2		303,000		288,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020	Level 2		179,289		162,322
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021	Level 2		165,677		119,490
8.50% Unsecured Senior Notes, due June 2019	Level 2		188,880		178,439

The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2, Long-Term Debt.  See Note 7, Derivative Financial Instruments, for the fair value of our open derivative contracts, which is classified as Level 2 in the reporting hierarchy and is reported in the Condensed Consolidated Balance Sheets using fair value.

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Drilling Program Joint Venture

9 Months Ended

Sep. 30, 2018

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Drilling Program Joint Venture

4.  Drilling Program Joint Venture

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza Energy LLC, a Delaware limited liability company, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico over the next three years.  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.  The Monza board has approved the substitution of one of these identified undeveloped drilling projects, the Viosca Knoll 823 (“VK 823”) A-14 well, with the VK 823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well.  The interest in the VK823 A-14 well is in process of being reconveyed to W&T.  Since the initial closing, additional investors have joined as members of Monza and as of September 30, 2018, total commitments by all members, including W&T, are $361.4 million.  Monza has closed off funding from additional investors.  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.  For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well.  W&T will be the operator of each well in the JV Drilling Program unless there is already a designated third-party operator.

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.  

At the inception of Monza, W&T received a net reimbursement of approximately $20 million for the capital expenditures incurred prior to the close date for projects in the JV Drilling Program.  W&T may be obligated to fund certain cost overruns, subject to certain exceptions, on JV Drilling Program wells above budgeted and contingency amounts.  As of September 30, 2018, members of Monza made partner capital contribution payments to Monza totaling $114.7 million.

Information on the structure and relationship follows:

Board Structure and Authority.  Under the Monza limited liability agreement, the business and affairs of Monza are managed by a board of five directors, which will consist of three directors selected by the third-party investors, Mr. Krohn, and an additional independent director will be selected by a majority of the third-party investors in Monza subject to consent by W&T.  The independent director and one of the directors to be selected by the investors have not yet been selected.  The day-to-day operations of Monza are being managed by W&T, under the direction of the Monza board, pursuant to a services agreement.  W&T has no control over the decisions of the Monza board.  W&T has veto rights for certain decisions, but does not have the ability to unilaterally make decisions for Monza, except for day-to-day decisions as permitted under the services agreement.  The Monza board is responsible for the management of Monza and for making decisions with respect to its interest in the 14 drilling projects, including approval of the budgets.    

Accounting Methodology and Carrying Amounts.  Our interest in Monza is considered to be a variable interest entity that we account for using proportional consolidation.  We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interest in the Monza properties.  As of September 30, 2018, in the Condensed Consolidated Balance Sheet, we recorded $7.5 million, net, in oil and natural gas properties, $2.2 million in other assets and $2.6 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities.  For the nine months ended September 30, 2018, we recorded $2.2 million in revenue, $1.1 million in operating expense and $0.3 million, net, in other expense in connection with our proportional interest in Monza’s operations.

Maximum Exposure. Our contribution to Monza as of September 30, 2018 was $53.5 million, which consisted of cash and the conveyance of the Company’s working interest in the 14 projects.  We may also take responsibility for certain drilling and completion cost overruns, subject to certain limitations and certain exceptions, of which the total exposure cannot be estimated at this time.

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Acquisitions and Divestitures

5. Acquisitions and Divestitures  

  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 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.  In connection with this transaction, we were required to furnish a letter of credit of $9.4 million to a pipeline company as consignee.  We recognized asset retirement obligations (“ARO”) of $3.6 million as a component of the transaction.  In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.  

Permian Basin.  On September 28, 2018, we closed on the divestiture of all of our ownership in an overriding royalty interests in the Permian Basin.  The net proceeds received were $50.5 million, which was recorded as a reduction to our full-cost pool.  We may receive additional proceeds of up to $6.4 million from the transaction if certain title defects are cured during the 90 days following the closing date.    

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

6.  Asset Retirement Obligations

Our ARO primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives.  

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

Balance, December 31, 2017	$	300,446
Liabilities settled		(22,764	)
Accretion of discount		13,872
Liabilities assumed through purchase		3,597
Revisions of estimated liabilities (1)		18,065
Balance, September 30, 2018		313,216
Less current portion		30,207
Long-term	$	283,009

(1) Upward revisions were primarily related to a non-operated field covering multiple wells, which experienced difficulties during the remediation process coupled with scope change due to the size of its platform.  In addition, another non-operated field experienced difficulties with a sub-contractor that had gone bankrupt and a replacement sub-contractor is attempting to re-negotiate the contract.  We do not have control over the remediation projects for non-operated properties.  Along with these two non-operated fields, we had upward revisions at two fields that were operated by us which experienced sustained casing pressure issues during the remediation process.

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Derivative Financial Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

7.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our crude oil and natural gas.  Some of the derivative counterparties are also lenders or affiliates of lenders participating in our Prior 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.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, 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 the second quarter of 2018, we entered into crude oil derivative contracts which relate to a portion of our expected crude oil production from May 2018 to December 2018.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  During the first quarter of 2017, we entered into commodity contracts for crude oil and natural gas, all of which had expired as of December 31, 2017.

As of September 30, 2018, our open crude oil derivative contracts were as follows:  

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Strike
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		2,000		184,000	$	63.80
Crude Oil:  Puts,  Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Put
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		5,000		460,000	$	60.00
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional		Notional		Contract Prices
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day) (1)		(Bbls) (1)		(Bought)		(Sold)
2018	December		2,000		184,000	$	60.00	$	69.50
2018	December		2,000		184,000	$	55.00	$	72.75

(1) bbls = barrels

The swap and two-way collars were “cost-less” contracts, in that no premiums were paid or received.  For the put option contract, the $2.1 million premium is being amortized over the life of the contract and recorded in Prepaid and other assets on the Condensed Consolidated Balance Sheet.  See Note 1, Basis of Presentation.

Our open and closed (not settled) commodity derivative contracts were recorded within the line Accrued liabilities on the Condensed Consolidated Balance Sheet summarized in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Open contracts	$	2,840	$	—
Closed contracts - not settled		412		84
Total contracts	$	3,252	$	84

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018		2017
Derivative (gain) loss	$	(288	)	$	2,879	$	5,931	$	(4,765	)

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

	Nine Months Ended
	September 30,
	2018			2017
Cash receipts (payments) on derivative settlements, net	$	(3,091	)	$	3,924

Offsetting Commodity Derivatives

All our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our Prior Credit Agreement, that event may also trigger an acceleration of settlement of some of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.  As of September 30, 2018, there would have been no difference in the presentation of our commodity derivatives on a gross or net basis.

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Share-Based Compensation and Cash-Based Incentive Compensation

9 Months Ended

Sep. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Share-Based Compensation and Cash-Based Incentive Compensation

8.  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 2018, 2017 and 2016, the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees.  RSUs are a long-term compensation component and are granted to certain employees, 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 are both a short-term and long-term compensation component and are subject to satisfaction of certain predetermined performance criteria.

As of September 30, 2018, there were 13,342,827 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 may be issued net of withholding tax if an awardee elects to satisfy his or her tax liability 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 2018, 2017 and 2016 grants, which are subject to predetermined performance criteria applied against the applicable performance period.  These RSUs continue to be 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 2018, 2017 and 2016 were determined using the Company’s closing price on the grant date.  We are also required to 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 nine months ended September 30, 2018 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2017		5,765,251		$	2.48
Granted		986,333			6.90
Vested		(28,503	)		2.38
Forfeited/adjustments		(113,014	)		2.45
Nonvested, September 30, 2018		6,610,067			3.14

For the RSUs that vested during 2018, the aggregate fair value at the grant dates was $0.1 million and the aggregate fair value at the vesting date was $0.2 million.

For the outstanding RSUs issued to the eligible employees as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):  

	Restricted Stock Units
2018		3,657,375
2019		1,966,359
2020		986,333
Total		6,610,067

Awards to Non-Employee Directors.  Under the W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, the “Director Compensation Plan”), shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during 2018, 2017 and 2016.  As of September 30, 2018, there were 128,980 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced on a one-to-one basis when Restricted Shares are granted.  

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

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

A summary of activity related to Restricted Shares is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2017		246,528		$	2.27
Granted		41,544			6.74
Vested		(106,240	)		2.64
Nonvested, September 30, 2018		181,832			3.08

For the Restricted Shares that vested during 2018, the aggregate fair value at the grant dates was $0.3 million and the aggregate fair value at the vesting date was $0.7 million.

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):

	Restricted Shares
2019		105,012
2020		62,972
2021		13,848
Total		181,832

Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  Share-based compensation was lower in the three and nine months ended September 30, 2018 compared to the prior year period due to timing of the grant date and changes in the 2018 program.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation expense from:
Restricted stock units	$	1,304	$	1,914	$	3,598	$	6,114
Restricted Shares		70		70		210		210
Total	$	1,374	$	1,984	$	3,808	$	6,324
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	289	$	694	$	800	$	2,213

Unrecognized Share-Based Compensation.As of September 30, 2018, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $8.3 million and $0.4 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2020 for RSUs and April 2021 for Restricted Shares.  

Cash-Based Incentive Compensation. In addition to share-based awards, cash-based awards were granted under the Plan to eligible employees in 2018, 2017 and 2016.  For 2018, there are two cash-based awards consisting of a long-term award and a short-term award.  All cash-based awards are performance-based awards consisting of predetermined performance criteria applied against the applicable performance period.  The 2018 long-term, cash-based awards will be eligible for payment on December 14, 2020 subject to participants meeting certain performance criteria.  The 2018 short-term, cash-based awards will be eligible for payment on or about March 15, 2019 subject to participants meeting certain eligibility criteria.  The cash-based awards for the 2018 short-term program, the 2017 program and the 2016 program include an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (as defined in the awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award as described below.  Expense for each program is recognized over the service period once the applicable financial condition is expected to be met, and the business criteria and individual performance criteria can be reasonably estimated for the applicable period.

• For the 2018 long-term, cash-based program, incentive compensation expense was based on estimates for full-year 2018 company performance metrics which were assessed as probable to be achieved and is being recognized over the September 2018 to November 2020 period.

• For the 2018 short-term, cash-based program, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was assessed as probable to be achieved; therefore, expense was recorded based on estimates for full-year 2018 Company metrics and historic individual performance measures, and is being recognized over the January 2018 to February 2019 period.

• For the 2017 cash-based awards, a portion of the business criteria and individual performance criteria were achieved.  The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2017 and in the first two months of 2018 for the 2017 cash-based awards.  Payments were made in March 2018.

• For the 2016 cash-based awards, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $300 million over four consecutive quarters was assessed as not being probable to be achieved; therefore no expense was recognized as of September 30, 2018.  The terms of the 2016 cash-based awards allow for the achievement of the financial condition up through December 31, 2018.  If the financial condition is achieved, payment is to be made within 30 days of achievement of the financial condition.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation included in:
General and administrative expenses	$	1,374	$	1,984	$	3,808	$	6,324
Cash-based incentive compensation included in:
Lease operating expense		837		930		2,240		1,324
General and administrative expenses		1,534		2,287		5,597		3,291
Total charged to operating income	$	3,745	$	5,201	$	11,645	$	10,939

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

9.  Income Taxes  

Our income tax expense for the three and nine months ended September 30, 2018 was $0.1 million and $0.4 million, respectively.  Our income tax expense for the three months ended September 30, 2017 was $5.5 million and our income tax benefit for the nine months ended September 30, 2017 was $11.1 million.  Our effective tax rate was not meaningful for the periods presented.  Based on a full year forecast, we are not expecting any current income tax expense.  In addition, immaterial deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance.  The income tax expense for the three months ended September 30, 2017 relates to revisions under GAAP using the annualized effective tax rate method in computing income tax expense or benefit for interim periods and the income tax benefit for the nine months ended September 30, 2017 relates to net operating loss carryback claims made pursuant to Internal Revenue Code (“IRC”) Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.

During the nine months ended September 30, 2018, we did not receive any income tax refunds and made no income tax payments of significance.  During the nine months ended September 30, 2017 we received $11.9 million of income tax refunds and made $0.2 million of income tax payments.          

As of September 30, 2018, we recorded current income taxes receivable of $65.2 million.  As of December 31, 2017, the balance sheet reflected current income taxes receivable of $13.0 million and non-current income taxes receivable of $52.1 million.  The receivable primarily relates to a net operating loss claim carried back for 2017 and net operating loss claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims require a review by the Congressional Joint Committee on Taxation.

As of September 30, 2018 and December 31, 2017, our valuation allowance was $148.3 million and $171.5 million, respectively, related to federal and state deferred tax assets.  Net deferred tax assets were recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  Although our net deferred tax assets and the related valuation allowance reflect the provisions of the Tax Cuts and Jobs Act (“TCJA”), due to the timing and the complexity of the provisions of the TCJA, further adjustments may be required during 2018 in determination of the final effect in our financial statements.  

The tax years 2013 through 2017 remain open to examination by the tax jurisdictions to which we are subject.   

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Earnings/ (Loss) Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings/ (Loss) Per Share

10.  Earnings Per Share

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
Net income (loss)	$	46,260	$	(1,297	)	$	109,983	$	56,317
Less portion allocated to nonvested shares		1,860		—			4,489		2,349
Net income (loss) allocated to common shares	$	44,400	$	(1,297	)	$	105,494	$	53,968
Weighted average common shares outstanding		138,972		137,575			138,917		137,547
Basic and diluted earnings (loss) per common share	$	0.32	$	(0.01	)	$	0.76	$	0.39
Shares excluded due to being anti-dilutive (weighted-average)		—		7,709			—		—

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Contingencies

9 Months Ended

Sep. 30, 2018

Commitments And Contingencies Disclosure [Abstract]

Contingencies

11.  Contingencies  

Apache Lawsuit.  On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon (“MC”) 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, where oral argument is scheduled for December 4, 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.  

The deposit of $49.5 million with the registry of the court is recorded in Other assets (long-term) on the Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) as of September 30, 2018 and December 31, 2017.

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties.  We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision.  Because the IBLA still has not ruled on W&T’s request for reconsideration, the district court action has been suspended.  The court requires periodic reports concerning the status of the request for reconsideration pending before the IBLA.  Once the IBLA rules, the district court action will return to the court’s active docket.

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 $2.1 million as of September 30, 2018.  We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals.        

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 nine months ended September 30, 2018 and 2017, we paid additional royalty payments of $0.6 million and $1.2 million, respectively.  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 nine months ended September 30, 2018 and 2017, 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 eight 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 the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to January 2018.  The proposed civil penalties for these INCs total $7.9 million.  We have accrued approximately $3.4 million as of September 30, 2018, 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.     

Surety Bond Collateral.  The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities.  We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion.  We did not receive any collateral demands from surety bond providers during the nine months ended September 30, 2018.

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.

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Subsequent Events

9 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Subsequent Events

12.  Subsequent Events

On October 18, 2018, we entered into a series of transactions to effect a refinancing of substantially all of our outstanding indebtedness.  On such date, we issued $625.0 million of the Senior Second Lien Notes at par with an interest rate of 9.75% per annum that matures on November 1, 2023, which are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”).  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.  The Senior Second Lien Notes will be recorded at their carrying value consisting of principal and unamortized debt issuance costs.

   Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture).  In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date.

On and after November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.000% on November 1, 2022 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are guaranteed by Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). If we experience certain change of control events, we will be required to offer to repurchase the notes at 101.000% of the principal amount, plus accrued and unpaid interest, if any, to the repurchase date.

Certain entities controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the 2018 Refinancing Transaction.  The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes.  As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan liquidated as the loan was repaid in full.

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the New Revolving 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”).  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.

Concurrently with the issuance of the Senior Second Lien Notes, we entered into the New Revolving Credit Agreement with a maturity date of October 18, 2022.  The primary items of the New Revolving Credit Agreement are as follows, with certain terms defined under the New Revolving Credit Agreement:

• The initial borrowing base and lending commitment is $250.0 million.

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

• The Leverage Ratio, as defined in the New Revolving Credit Agreement, is limited to 3.50 to 1.00 for quarters ending December 31, 2018 and March 31, 2019; 3.25 to 1.00 for quarters ending June 30, 2019 and September 30, 2019; and 3.00 to 1.00 for quarters ending December 31, 2019 and thereafter.  In the event of a Material Acquisition, as defined in the New Revolving Credit Agreement, the Leverage Ratio limit is 3.50 to 1.00 for the two quarters following a Material Acquisition.  

• The Current Ratio, as defined in the New Revolving Credit Agreement, must be greater than 1.00 to 1.00.

• We are required to have deposit accounts only with banks under the New Revolving Credit Agreement with certain exceptions.

• To the extent there are borrowings, the Applicable Margins, as defined in the New Revolving Credit Agreement, for Eurodollar Loans range from 2.50% to 3.50% per annum and the Applicable Margins for ABR loans range from 1.50% to 2.50% per annum.  The specific Applicable Margin rate is based on the Borrowing Base Utilization Percentage.  

• The commitment fee is 37.5 basis points if the Borrowing Base Utilization Percentage is below 50% and 50 basis points if the Borrowing Base Utilization Percentage is 50% or greater.

• By December 2, 2018, we are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria.  We may enter into these derivative contracts with counter parties within the New Revolving Credit Agreement or with other counter parties meeting certain criteria described in the New Revolving Credit Agreement.

Availability under the New Revolving Credit Agreement is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  The first redetermination will be in the spring of 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the New Revolving Credit Agreement.  The New Revolving Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal property.  

The New Revolving Credit Agreement contains various customary covenants for certain financial tests, as defined in the New Revolving Credit Agreement, and these tests are measured as of the end of each quarter, and for customary events of default.  The customary events of default include: (i) default in the payment of interest on the Senior Second Lien Notes when due, continued for 30 days; (ii) default in payment of the principal of or premium, if any, on the Senior Second Lien Notes when due; (iii) failure by the Company or any of its restricted subsidiaries, if any, to comply with certain covenants relating to merger and consolidation and offers to purchase Senior Second Lien Notes in connection with certain change of control transactions or asset sales; (iv) failure by the Company to comply for 60 days after notice with any of the other agreements in the Indenture; (v) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Company or any of its restricted subsidiaries (or the payment of which is guaranteed by the Company or any of its restricted subsidiaries) if that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period provided in such indebtedness (a “Payment Default”); or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other such indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $50.0 million or more; (vii) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company; (viii) failure by the Company, or any of the Company’s restricted subsidiaries that is a significant subsidiary or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, to pay final judgments aggregating in excess of $50.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (ix) any Security Document (as defined in the Indenture) ceases for any reason to be enforceable with respect to any collateral having a fair market value of not more than $25.0 million, which failure is not cured within 45 days; (x) any second lien purported to be granted under any Security Document on collateral, individually or in the aggregate, having a fair market value in excess of $25.0 million, ceases to be an enforceable and perfected second-priority lien, which failure is not cured within 45 days; and (xi) except as permitted by the Indenture, any future subsidiary guarantee entered into by one of the Company’s subsidiaries shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its subsidiary guarantee of the Senior Second Lien Notes.

After closing the 2018 Refinancing Transaction on October 18, 2018, we had $61.0 million borrowings outstanding, $9.7 million of letters of credit outstanding and our borrowing availability was $179.3 million under the New Revolving Credit Agreement.  We were in compliance with all applicable covenants of the New Revolving Credit Agreement and Senior Second Lien Notes after the 2018 Refinancing Transaction.

The funds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of the long-term debt instruments outstanding including accrued interest, tender offer premiums, redemption premiums and debt issuance costs.  The 2018 Refinancing Transaction is expected to result in a net gain of approximately $47.0 million that will be recorded in the consolidated statement of operations and approximately $17.9 million of additional capitalized debt issuance costs fees that will be recorded on the balance sheet during the fourth quarter of 2018.  As the 2018 Refinancing Transaction substantially changed our capital structure, the following table is provided to present the Condensed Consolidated Balance sheet on a pro forma basis as if the 2018 Refinancing Transaction occurred on September 30, 2018:

	September 30, 2018
	As Reported			Extinguishment of Debt Adjustments				Debt Issuance Adjustments				Pro Forma
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	(954,100	)	(1)	$	671,887		(7)	$	56,850
Total receivables		131,215			—				—				131,215
Prepaid expenses and other assets		19,699			2,138		(2)		—				21,837
Total current assets		489,977			(951,962	)			671,887				209,902
Oil and natural gas properties and other, net		522,781			—				—				522,781
Restricted deposits for ARO		20,577			—				—				20,577
Other assets		69,014			—				—				69,014
Total assets	$	1,102,349		$	(951,962	)		$	671,887			$	822,274
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	95,502		$	—			$	—			$	95,502
Undistributed oil and natural gas proceeds		34,225			—				—				34,225
Advances from joint interest partners		31,012			—				—				31,012
Asset retirement obligations		30,207			—				—				30,207
Current maturities of long-term debt:
Principal		189,829			(189,829	)	(3)		—				—
Carrying value adjustments		34,985			(34,985	)	(4)		—				—
Current maturities of long-term debt   - carrying value		224,814			(224,814	)			—				—
Accrued liabilities		31,058			(14,989	)	(5)		3,787		(8)		19,856
Total current liabilities		446,818			(239,803	)			3,787				210,802
Long-term debt:
Principal		713,365			(713,365	)	(3)		625,000		(9)		625,000
Borrowings on revolving bank credit facility		—			—				61,000		(10)		61,000
Carrying value adjustments		45,758			(45,758	)	(4)		(17,900	)	(11)		(17,900	)
Long term debt, less current portion   - carrying value		759,123			(759,123	)			668,100				668,100
Asset retirement obligations, less current portion		283,009			—				—				283,009
Other liabilities		73,175			—				—				73,175
Shareholders’ deficit:
Common stock		1			—				—				1
Additional paid-in capital		549,569			—				—				549,569
Retained earnings (deficit)		(985,179	)		46,964		(6)		—				(938,215	)
Treasury stock, at cost		(24,167	)		—				—				(24,167	)
Total shareholders’ deficit		(459,776	)		46,964				—				(412,812	)
Total liabilities and shareholders’ deficit	$	1,102,349		$	(951,962	)		$	671,887			$	822,274

Pro Forma Adjustments:

(1) Cash used to extinguish debt including principal, interest, tender offer premiums and redemption premiums.

(2) Prepaid interest related to the Second Lien Term Loan and the Unsecured Senior Notes.

(3) Payment of outstanding debt principal.

(4) Elimination of carrying value adjustments either through payments or write off of remaining balances.

(5) Payment of interest related to the Second Lien Loan and the Unsecured Senior Notes accrued as of September 30, 2018.

(6) Net gain from the write off of the remaining balances of carrying value adjustments, reduced for interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  In addition, the net gain was reduced for premiums related to repurchases pursuant to the early tender offer, redemptions premiums and certain prepayments paid on the existing notes and loans.

(7) Net proceeds from the issuance of the Senior Second Lien Notes and borrowings under the New Revolving Credit Agreement, less debt issuance costs paid of $14.1 million.

(8) Accrued debt issuance costs related to the Senior Second Lien Notes.

(9) Issuance of the Senior Second Lien Notes.

(10) Borrowings under the New Revolving Credit Agreement.

(11) Paid and accrued debt issuance costs related to the Senior Second Lien Notes and New Revolving Credit Agreement.

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Supplemental Guarantor Information

9 Months Ended

Sep. 30, 2018

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

13.  Supplemental Guarantor Information

On September 30, 2018, our payment obligations under the Prior Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (collectively, the “Existing Notes”) were fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including the Guarantor Subsidiaries.  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Subsequent to the 2018 Refinancing Transaction, the New Revolving Credit Agreement and the Senior Second Lien Notes are fully and unconditionally guaranteed by Guarantor Subsidiaries.  Under the indentures governing the Existing Notes and the Senior Second Lien Notes, the guarantees of the Guarantor Subsidiaries can be released under certain circumstances, including:  

(1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale or other disposition does not violate the Asset Sale provisions (as such capitalized terms are defined in the New Revolving Credit Agreement and Senior Second Lien Notes);

(2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the Asset Sale provisions of the New Revolving Credit Agreement and Senior Second Lien Notes and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the New Revolving Credit Agreement and Senior Second Lien Notes;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the applicable indenture) or upon satisfaction and discharge of the New Revolving Credit Agreement and Senior Second Lien Notes;

(5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary as described in the New Revolving Credit Agreement and Senior Second Lien Notes, provided no event of default has occurred and is continuing.

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  As a result of the JV Drilling Program, we recorded proportional consolidation adjustments, which are not considered a guarantor asset under our debt agreements and, accordingly, are reported as non-guarantor adjustments in the following tables.  Due to the methodology of recording the ceiling-test write down in prior periods, consolidating adjustments are required to present the consolidated results appropriately.  The 2018 Refinancing Transaction substantially changed our capital structure.  See Note 12, Subsequent Events, for additional information.  

Condensed Consolidating Balance Sheet as of September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	—		$	—		$	—		$	339,063
Receivables:
Oil and natural gas sales		7,946			40,972			564			—			49,482
Joint interest		16,493			—			—			—			16,493
Income taxes		199,203			—			—			(133,963	)		65,240
Total receivables		223,642			40,972			564			(133,963	)		131,215
Prepaid expenses and other assets		16,707			2,956			36			—			19,699
Total current assets		579,412			43,928			600			(133,963	)		489,977
Oil and natural gas properties and other, net		372,660			111,907			49,476			(11,262	)		522,781
Restricted deposits for asset retirement obligations		20,577			—			—			—			20,577
Other assets		637,886			589,084			(51,316	)		(1,106,640	)		69,014
Total assets	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	90,260		$	7,318		$	(2,076	)	$	—		$	95,502
Undistributed oil and natural gas proceeds		32,806			1,419			—			—			34,225
Advances from joint interest partners		31,012			-			—			—			31,012
Asset retirement obligations		19,479			10,728			—			—			30,207
Current maturities of long-term debt:
Principal		189,829			—			—			—			189,829
Carrying value adjustments		34,985			—			—			—			34,985
Current maturities of long-term debt  -    carrying value		224,814			—			—			—			224,814
Accrued liabilities		31,076			133,945			—			(133,963	)		31,058
Total current liabilities		429,447			153,410			(2,076	)		(133,963	)		446,818
Long-term debt:
Principal		713,365			—			—			—			713,365
Carrying value adjustments		45,758			—			—			—			45,758
Long term debt, less current portion -   carrying value		759,123			—			—			—			759,123
Asset retirement obligations, less current portion		162,835			120,154			20			—			283,009
Other liabilities		708,461			—			—			(635,286	)		73,175
Shareholders’ equity (deficit):
Common stock		1			—			—			—			1
Additional paid-in capital		549,569			704,885			—			(704,885	)		549,569
Retained earnings (deficit)		(974,734	)		(233,530	)		816			222,269			(985,179	)
Treasury stock, at cost		(24,167	)		—			—			—			(24,167	)
Total shareholders’ equity (deficit)		(449,331	)		471,355			816			(482,616	)		(459,776	)
Total liabilities and shareholders’ equity (deficit)	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349

Condensed Consolidating Balance Sheet as of December 31, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	99,058		$	—		$	—		$	99,058
Receivables:
Oil and natural gas sales		5,665			39,778			—			45,443
Joint interest		19,754			—			—			19,754
Income taxes		128,835			—			(115,829	)		13,006
Total receivables		154,254			39,778			(115,829	)		78,203
Prepaid expenses and other assets		11,154			2,265			—			13,419
Total current assets		264,466			42,043			(115,829	)		190,680
Oil and natural gas properties and other, net		430,354			152,464			(3,802	)		579,016
Restricted deposits for asset retirement obligations		25,394			—			—			25,394
Income taxes receivable		52,097			—			—			52,097
Other assets		505,304			453,306			(898,217	)		60,393
Total assets	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	72,705		$	6,962		$	—		$	79,667
Undistributed oil and natural gas proceeds		18,762			1,367			—			20,129
Advances from joint interest partners		3,998			—			—			3,998
Asset retirement obligations		22,488			1,125			—			23,613
Current maturities of long-term debt  - carrying value		22,925			—			—			22,925
Accrued liabilities		18,058			115,701			(115,829	)		17,930
Total current liabilities		158,936			125,155			(115,829	)		168,262
Long-term debt:
Principal		889,790			—			—			889,790
Carrying value adjustments		79,337			—			—			79,337
Long term debt, less current portion - carrying value		969,127			—			—			969,127
Asset retirement obligations, less current portion		152,883			123,950			—			276,833
Other liabilities		566,375			—			(499,509	)		66,866
Shareholders’ equity (deficit):
Common stock		1			—			—			1
Additional paid-in capital		545,820			704,885			(704,885	)		545,820
Retained earnings (deficit)		(1,091,360	)		(306,177	)		302,375			(1,095,162	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(569,706	)		398,708			(402,510	)		(573,508	)
Total liabilities and shareholders’ equity (deficit)	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Guarantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	79,740		$	71,964	$	1,755	$	—		$	153,459
Operating costs and expenses:
Lease operating expenses		22,188			15,182		60		—			37,430
Production taxes		432			—		—		—			432
Gathering and transportation		3,193			2,545		41		—			5,779
Depreciation, depletion, amortization    and accretion		19,170			15,568		514		1,717			36,969
General and administrative expenses		8,812			7,083		95		—			15,990
Derivative gain		(288	)		—		—		—			(288	)
Total costs and expenses		53,507			40,378		710		1,717			96,312
Operating income		26,233			31,586		1,045		(1,717	)		57,147
Earnings of affiliates		25,977			—		—		(25,977	)		—
Interest expense		11,630			—		—		—			11,630
Other (income) expense, net		(912	)		—		27		—			(885	)
Income before income tax    expense (benefit)		41,492			31,586		1,018		(27,694	)		46,402
Income tax expense (benefit)		(5,467	)		5,609		—		—			142
Net income	$	46,959		$	25,977	$	1,018	$	(27,694	)	$	46,260

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Gurantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	220,796		$	214,264	$	2,224	$	—		$	437,284
Operating costs and expenses:
Lease operating expenses		63,565			46,194		96		—			109,855
Production taxes		1,326			—		—		—			1,326
Gathering and transportation		8,730			6,983		51		—			15,764
Depreciation, depletion, amortization and accretion		58,544			48,125		678		7,460			114,807
General and administrative expenses		22,869			22,073		306		—			45,248
Derivative loss		5,931			—		—		—			5,931
Total costs and expenses		160,965			123,375		1,131		7,460			292,931
Operating income		59,831			90,889		1,093		(7,460	)		144,353
Earnings of affiliates		72,646			—		—		(72,646	)		—
Interest expense		35,100			—		—		—			35,100
Other (income) expense, net		(1,369	)		—		276		—			(1,093	)
Income before income tax   expense (benefit)		98,746			90,889		817		(80,106	)		110,346
Income tax expense (benefit)		(17,880	)		18,243		—		—			363
Net income	$	116,626		$	72,646	$	817	$	(80,106	)	$	109,983

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	51,981		$	58,300	$	—		$	110,281
Operating costs and expenses:
Lease operating expenses		18,796			16,338		—			35,134
Production taxes		340			—		—			340
Gathering and transportation		1,804			2,304		—			4,108
Depreciation, depletion, amortization and accretion		18,804			16,855		830			36,489
General and administrative expenses		7,131			8,500		—			15,631
Derivative loss		2,879			—		—			2,879
Total costs and expenses		49,754			43,997		830			94,581
Operating income		2,227			14,303		(830	)		15,700
Earnings of affiliates		13,251			—		(13,251	)		—
Interest expense		11,554			—		—			11,554
Other income, net		(41	)		—		—			(41	)
Income before income tax expense		3,965			14,303		(14,081	)		4,187
Income tax expense		4,432			1,052		—			5,484
Net income (loss)	$	(467	)	$	13,251	$	(14,081	)	$	(1,297	)

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	163,105		$	194,892	$	—		$	357,997
Operating costs and expenses:
Lease operating expenses		59,823			46,994		—			106,817
Production taxes		1,304			—		—			1,304
Gathering and transportation		6,948			8,687		—			15,635
Depreciation, depletion, amortization and accretion		59,391			55,103		2,349			116,843
General and administrative expenses		20,569			24,810		—			45,379
Derivative gain		(4,765	)		—		—			(4,765	)
Total costs and expenses		143,270			135,594		2,349			281,213
Operating income		19,835			59,298		(2,349	)		76,784
Earnings of affiliates		49,719			—		(49,719	)		—
Interest expense		34,284			—		—			34,284
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,073			—		—			5,073
Income before income tax expense (benefit)		38,008			59,298		(52,068	)		45,238
Income tax expense (benefit)		(20,658	)		9,579		—			(11,079	)
Net income	$	58,666		$	49,719	$	(52,068	)	$	56,317

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	116,626		$	72,646		$	817		$	(80,106	)	$	109,983
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		58,544			48,125			678			7,460			114,807
Amortization of debt items and other items		1,796			—			—			—			1,796
Share-based compensation		3,808			—			—			—			3,808
Derivative loss		5,931			—			—			—			5,931
Cash receipts on derivative settlements, net		(3,091	)		—			—			—			(3,091	)
Deferred income taxes		363			—			—			—			363
Earnings of affiliates		(72,646	)		—			—			72,646			—
Changes in operating assets and liabilities:											—
Oil and natural gas receivables		(2,281	)		(1,194	)		(564	)		—			(4,039	)
Joint interest receivables		3,261			—			—			—			3,261
Income taxes		(18,382	)		18,243			—			—			(139	)
Prepaid expenses and other assets		(36,764	)		(116,777	)		9,297			135,777			(8,467	)
Asset retirement obligation settlements		(15,860	)		(6,904	)		—			—			(22,764	)
Cash advances from JV partners		27,014			—			—			—			27,014
Accounts payable, accrued liabilities and other		196,880			8,157			(2,871	)		(135,777	)		66,389
Net cash provided by operating activities		265,199			22,296			7,357			—			294,852
Investing activities:
Investment in oil and natural gas properties and equipment		(36,462	)		(14,547	)		(8,152	)		—			(59,161	)
Changes in operating assets and liabilities associated with    investing activities		(13,307	)		(7,749	)		795			—			(20,261	)
Acquisition of property interest		(16,782	)		—			—			—			(16,782	)
Proceeds from sale of assets		50,474			—			—			—			50,474
Net cash used in investing activities		(16,077	)		(22,296	)		(7,357	)		—			(45,730	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,171	)		—			—			—			(6,171	)
Payment of interest on 2nd Lien PIK Toggle Notes		(2,920	)		—			—			—			(2,920	)
Other		(26	)		—			—			—			(26	)
Net cash used in financing activities		(9,117	)		—			—			—			(9,117	)
Increase in cash and cash equivalents		240,005			—			—			—			240,005
Cash and cash equivalents, beginning of period		99,058			—			—			—			99,058
Cash and cash equivalents, end of period	$	339,063		$	—		$	—		$	—		$	339,063

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	58,666		$	49,719		$	(52,068	)	$	56,317
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		59,391			55,103			2,349			116,843
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		1,271			—			—			1,271
Share-based compensation		5,449			—			—			5,449
Derivative gain		(4,765	)		—			—			(4,765	)
Cash receipts on derivative settlements		3,924			—			—			3,924
Deferred income taxes		321			—			—			321
Earnings of affiliates		(49,719	)		—			49,719			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(2,694	)		6,600			—			3,906
Joint interest receivables		8			—			—			8
Insurance reimbursements		31,740			—			—			31,740
Income taxes		(9,259	)		9,579			—			320
Prepaid expenses and other assets		1,326			(95,523	)		96,391			2,194
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligations		(41,381	)		(14,845	)		—			(56,226	)
Cash advances from JV partners		(786	)		—			—			(786	)
Accounts payable, accrued liabilities and other		127,387			(3,881	)		(96,391	)		27,115
Net cash provided by operating activities		123,568			6,752			—			130,320
Investing activities:
Investment in oil and natural gas properties and equipment		(68,831	)		(10,257	)		—			(79,088	)
Changes in operating assets and liabilities associated with    investing activities		2,174			3,505			—			5,679
Purchases of furniture, fixtures and other		(905	)		—			—			(905	)
Net cash used in investing activities		(67,562	)		(6,752	)		—			(74,314	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,170	)		—			—			(6,170	)
Payment of interest on 2nd Lien PIK Toggle Notes		(7,335	)		—			—			(7,335	)
Payment of interest on 3rd Lien PIK Toggle Notes		(6,201	)		—			—			(6,201	)
Other		(372	)		—			—			(372	)
Net cash used in financing activities		(20,078	)		—			—			(20,078	)
Increase in cash, cash equivalents and restricted cash		35,928			—			—			35,928
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	106,164		$	—		$	—		$	106,164

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Operations

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. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately consolidated interest in Monza Energy LLC (“Monza”), as described in more detail in Note 4.

Interim Financial Statements

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, 2017.

Use of Estimates

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.

Recent Events

Recent Events.  The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth.  The average realized prices of crude oil and NGLs improved during the nine months ended September 30, 2018 compared to the average realized prices in the nine months ended September 30, 2017.  

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”) which substantially changed our capital structure.  The Senior Second Lien Notes were issued at par and have a maturity date of November 1, 2023.  Concurrently with the issuance of the Senior Second Lien Notes, we entered into the Sixth Amended and Restated Credit Agreement (as amended, the “New Revolving Credit Agreement”) which provides us with a revolving bank credit facility with an initial borrowing base of $250.0 million (increasing from $150.0 million under our prior facility).  Letters of credit may be issued in amounts up to $30.0 million provided availability exists.  The New Revolving Credit Agreement matures on October 18, 2022.  The proceeds from the issuance of the Senior Second Lien Notes, cash on hand and borrowings under the New Revolving Credit Agreement were used to repurchase and retire, repay or irrevocably redeem all of our existing notes and term loans outstanding and fund debt issuance costs.  We refer to these transactions and the related repurchases and retirements, repayments and redemptions of all of our outstanding notes and term loans collectively as the “2018 Refinancing Transaction.”  See Note 12, Subsequent Events, for additional information.  

We believe we will have adequate available liquidity to fund our operations through November 2019, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or future Bureau of Ocean Energy Management (“BOEM”) bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

See our Annual Report on Form 10-K for the year ended December 31, 2017 concerning risks related to our business and events occurring during 2017 and other information and the Notes herein for additional information.  

Accounting Standard Updates Effective January 1, 2018

Accounting Standard Updates Effective January 1, 2018:

   Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018.  The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business.  In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business.          

Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us in the period ending March 31, 2018.  We reviewed our contracts using the five-step revenue recognition model, which did not identify any changes required as to the amount or timing of revenue recognition.  We adopted the new standard using the modified retrospective approach which did not result in any cumulative-effect adjustment on the date of adoption.  The implementation of ASU 2014-09 resulted in a change in our reporting in the Condensed Consolidated Statement of Operations so that we now report revenue streams separately for crude oil, NGLs, natural gas and other revenues in compliance with the new standard.    

Revenue Recognition

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

Reclassification

Reclassification.  Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows:  Within the Net Cash Provided by Operating Activities of the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items, of which did not change the total amount previous reported.  The adjustments did not affect the Condensed Consolidated Balance Sheets or the Condensed Consolidated Statements of Operations

Prepaid Expenses And Other Assets

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

	September 30,		December 31,
	2018		2017
Prepaid/accrued insurance	$	4,214	$	2,401
Surety bond unamortized premiums		2,847		2,676
Prepaid deposits related to royalties		9,698		6,456
Advances for capital expenditures		860		—
Derivative contract premiums		791		—
Other		1,289		1,886
Prepaid expenses and other assets	$	19,699	$	13,419

Oil and Natural Gas Properties and Other, Net - at Cost

Oil and Natural Gas Properties and Other, Net – at cost.  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Oil and natural gas properties and equipment	$	8,146,742	$	8,102,044
Furniture, fixtures and other		20,227		21,831
Total property and equipment		8,166,969		8,123,875
Less accumulated depreciation, depletion    and amortization		7,644,188		7,544,859
Oil and natural gas properties and other, net	$	522,781	$	579,016

Other Assets (Long-term)

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

	September 30,		December 31,
	2018		2017
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Appeal bond deposits		6,925		6,925
Investment in White Cap, LLC		2,648		2,511
Deposit related to letters of credit		4,702		—
Unamortized brokerage fee for Monza		1,981		—
Proportional consolidation of Monza's    other assets  (Note 4)		2,212		—
Other		1,046		1,457
Total other assets	$	69,014	$	60,393

Accrued Liabilities

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

	September 30,		December 31,
	2018		2017
Accrued interest	$	15,041	$	4,200
Accrued salaries/payroll taxes/benefits		2,291		2,454
Incentive compensation plans		6,452		7,366
Litigation accruals		3,604		3,480
Derivative contracts		3,252		84
Other		418		346
Total accrued liabilities	$	31,058	$	17,930

Other Liabilities (Long-term)

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

	September 30,		December 31,
	2018		2017
Apache lawsuit	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		11,379		11,015
Dispute related to royalty deductions		4,687		—
Dispute related to royalty-in-kind		2,100		914
Other		5,509		5,437
Total other liabilities (long-term)	$	73,175	$	66,866

Recent Accounting Developments

Recent Accounting Developments.  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months.  Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a financing or operating lease.  However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space, which is primarily in Houston, Texas, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases nor do we have any leases recorded on the Condensed Consolidated Balance Sheets.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

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

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

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Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Schedule of Amounts Recorded in Prepaid Expenses and Other Assets

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

	September 30,		December 31,
	2018		2017
Prepaid/accrued insurance	$	4,214	$	2,401
Surety bond unamortized premiums		2,847		2,676
Prepaid deposits related to royalties		9,698		6,456
Advances for capital expenditures		860		—
Derivative contract premiums		791		—
Other		1,289		1,886
Prepaid expenses and other assets	$	19,699	$	13,419

Schedule of Oil and Natural Gas Properties and other, Net at Cost

Oil and Natural Gas Properties and Other, Net – at cost.  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Oil and natural gas properties and equipment	$	8,146,742	$	8,102,044
Furniture, fixtures and other		20,227		21,831
Total property and equipment		8,166,969		8,123,875
Less accumulated depreciation, depletion    and amortization		7,644,188		7,544,859
Oil and natural gas properties and other, net	$	522,781	$	579,016

Schedule of Other Assets (Long-term)

The major categories are presented in the following table (in thousands)

	September 30,		December 31,
	2018		2017
Escrow deposit - Apache lawsuit	$	49,500	$	49,500
Appeal bond deposits		6,925		6,925
Investment in White Cap, LLC		2,648		2,511
Deposit related to letters of credit		4,702		—
Unamortized brokerage fee for Monza		1,981		—
Proportional consolidation of Monza's    other assets  (Note 4)		2,212		—
Other		1,046		1,457
Total other assets	$	69,014	$	60,393

Schedule of Accrued Liabilities

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

	September 30,		December 31,
	2018		2017
Accrued interest	$	15,041	$	4,200
Accrued salaries/payroll taxes/benefits		2,291		2,454
Incentive compensation plans		6,452		7,366
Litigation accruals		3,604		3,480
Derivative contracts		3,252		84
Other		418		346
Total accrued liabilities	$	31,058	$	17,930

Schedule of Other Liabilities (Long-term)

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

	September 30,		December 31,
	2018		2017
Apache lawsuit	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		11,379		11,015
Dispute related to royalty deductions		4,687		—
Dispute related to royalty-in-kind		2,100		914
Other		5,509		5,437
Total other liabilities (long-term)	$	73,175	$	66,866

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

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

	September 30, 2018								December 31, 2017
			Adjustments to								Adjustments to
			Carrying			Carrying					Carrying			Carrying
	Principal		Value (1)			Value			Principal		Value (1)			Value
11.00% 1.5 Lien Term Loan,      due November 2019:
Principal	$	75,000	$	—		$	75,000		$	75,000	$	—		$	75,000
Future interest payments		—		9,425			9,425			—		15,596			15,596
Subtotal		75,000		9,425			84,425			75,000		15,596			90,596
9.00 % Second Lien Term Loan,     due May 2020:		300,000		—			300,000			300,000		—			300,000
9.00%/10.75% Second Lien     PIK Toggle Notes, due May 2020:
Principal		177,513		—			177,513			171,769		—			171,769
Future payments-in-kind		—		—			—			—		5,745			5,745
Future interest payments		—		31,952			31,952			—		34,872			34,872
Subtotal		177,513		31,952			209,465			171,769		40,617			212,386
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		160,852		—			160,852			153,192		—			153,192
Future payments-in-kind		—		3,664			3,664			—		11,323			11,323
Future interest payments		—		38,682			38,682			—		38,682			38,682
Subtotal		160,852		42,346			203,198			153,192		50,005			203,197
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(2,980	)		(2,980	)		—		(3,956	)		(3,956	)
Total long-term debt		903,194		80,743			983,937			889,790		102,262			992,052
Current maturities of long-term debt (2)		189,829		34,985			224,814			—		22,925			22,925
Long term debt, less current    maturities	$	713,365	$	45,758		$	759,123		$	889,790	$	79,337		$	969,127

(1) Future interest payments and future payments-in-kind are recorded on an undiscounted basis.

(2) Represents principal of the 8.50% Unsecured Senior Notes due June 15, 2019 and future interest payments on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes due within twelve months.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Long-Term Debt

The following table presents the fair value of our long-term debt, all of which are classified as Level 2 within the valuation hierarchy (in thousands):

	Hierarchy	September 30, 2018		December 31, 2017
11.00% 1.5 Lien Term Loan, due November 2019	Level 2	$	75,000	$	75,000
9.00 % Second Lien Term Loan, due May 2020	Level 2		303,000		288,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020	Level 2		179,289		162,322
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021	Level 2		165,677		119,490
8.50% Unsecured Senior Notes, due June 2019	Level 2		188,880		178,439

The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2, Long-Term Debt.  See Note 7, Derivative Financial Instruments, for the fair value of our open derivative contracts, which is classified as Level 2 in the reporting hierarchy and is reported in the Condensed Consolidated Balance Sheets using fair value.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Summary of Changes to Asset Retirement Obligation

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

Balance, December 31, 2017	$	300,446
Liabilities settled		(22,764	)
Accretion of discount		13,872
Liabilities assumed through purchase		3,597
Revisions of estimated liabilities (1)		18,065
Balance, September 30, 2018		313,216
Less current portion		30,207
Long-term	$	283,009

(1) Upward revisions were primarily related to a non-operated field covering multiple wells, which experienced difficulties during the remediation process coupled with scope change due to the size of its platform.  In addition, another non-operated field experienced difficulties with a sub-contractor that had gone bankrupt and a replacement sub-contractor is attempting to re-negotiate the contract.  We do not have control over the remediation projects for non-operated properties.  Along with these two non-operated fields, we had upward revisions at two fields that were operated by us which experienced sustained casing pressure issues during the remediation process.

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary of Open Commodity Derivative Contracts

As of September 30, 2018, our open crude oil derivative contracts were as follows:  

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Strike
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		2,000		184,000	$	63.80
Crude Oil:  Puts,  Priced off WTI (NYMEX)
		Notional		Notional
		Quantity		Quantity		Put
Termination Period		(Bbls/day) (1)		(Bbls) (1)		Price
2018	December		5,000		460,000	$	60.00
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional		Notional		Contract Prices
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day) (1)		(Bbls) (1)		(Bought)		(Sold)
2018	December		2,000		184,000	$	60.00	$	69.50
2018	December		2,000		184,000	$	55.00	$	72.75

(1) bbls = barrels

Summary of Open and Closed (Not Settled) Commodity Derivative Contracts

Our open and closed (not settled) commodity derivative contracts were recorded within the line Accrued liabilities on the Condensed Consolidated Balance Sheet summarized in the following table (in thousands):

	September 30,		December 31,
	2018		2017
Open contracts	$	2,840	$	—
Closed contracts - not settled		412		84
Total contracts	$	3,252	$	84

Changes in Fair Value and Settlements of Commodity Derivative Contracts

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018		2017
Derivative (gain) loss	$	(288	)	$	2,879	$	5,931	$	(4,765	)

Cash Receipts (Payments) on Derivative Settlements Included Within Net Cash Provided By Operating Activities

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

	Nine Months Ended
	September 30,
	2018			2017
Cash receipts (payments) on derivative settlements, net	$	(3,091	)	$	3,924

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Share-Based Compensation and Cash-Based Incentive Compensation (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Share Activity Related to Restricted Stock Units

A summary of activity related to RSUs during the nine months ended September 30, 2018 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2017		5,765,251		$	2.48
Granted		986,333			6.90
Vested		(28,503	)		2.38
Forfeited/adjustments		(113,014	)		2.45
Nonvested, September 30, 2018		6,610,067			3.14

Schedule of Outstanding Restricted Stock Units Issued to Eligible Employees

For the outstanding RSUs issued to the eligible employees as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):  

	Restricted Stock Units
2018		3,657,375
2019		1,966,359
2020		986,333
Total		6,610,067

Schedule of Restricted Stock Activity

A summary of activity related to Restricted Shares is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2017		246,528		$	2.27
Granted		41,544			6.74
Vested		(106,240	)		2.64
Nonvested, September 30, 2018		181,832			3.08

Schedule of Outstanding Restricted Stock Shares Issued to Non-employee Directors

For the outstanding Restricted Shares issued to the non-employee directors as of September 30, 2018, vesting is expected to occur as follows (subject to any forfeitures):

	Restricted Shares
2019		105,012
2020		62,972
2021		13,848
Total		181,832

Summary of Incentive Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit

A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation expense from:
Restricted stock units	$	1,304	$	1,914	$	3,598	$	6,114
Restricted Shares		70		70		210		210
Total	$	1,374	$	1,984	$	3,808	$	6,324
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	289	$	694	$	800	$	2,213

Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Share-based compensation included in:
General and administrative expenses	$	1,374	$	1,984	$	3,808	$	6,324
Cash-based incentive compensation included in:
Lease operating expense		837		930		2,240		1,324
General and administrative expenses		1,534		2,287		5,597		3,291
Total charged to operating income	$	3,745	$	5,201	$	11,645	$	10,939

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Earnings/ (Loss) Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
Net income (loss)	$	46,260	$	(1,297	)	$	109,983	$	56,317
Less portion allocated to nonvested shares		1,860		—			4,489		2,349
Net income (loss) allocated to common shares	$	44,400	$	(1,297	)	$	105,494	$	53,968
Weighted average common shares outstanding		138,972		137,575			138,917		137,547
Basic and diluted earnings (loss) per common share	$	0.32	$	(0.01	)	$	0.76	$	0.39
Shares excluded due to being anti-dilutive (weighted-average)		—		7,709			—		—

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Subsequent Events (Tables)

9 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Schedule of Condensed Consolidated Balance sheet on a Pro forma Basis

As the 2018 Refinancing Transaction substantially changed our capital structure, the following table is provided to present the Condensed Consolidated Balance sheet on a pro forma basis as if the 2018 Refinancing Transaction occurred on September 30, 2018:

	September 30, 2018
	As Reported			Extinguishment of Debt Adjustments				Debt Issuance Adjustments				Pro Forma
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	(954,100	)	(1)	$	671,887		(7)	$	56,850
Total receivables		131,215			—				—				131,215
Prepaid expenses and other assets		19,699			2,138		(2)		—				21,837
Total current assets		489,977			(951,962	)			671,887				209,902
Oil and natural gas properties and other, net		522,781			—				—				522,781
Restricted deposits for ARO		20,577			—				—				20,577
Other assets		69,014			—				—				69,014
Total assets	$	1,102,349		$	(951,962	)		$	671,887			$	822,274
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	95,502		$	—			$	—			$	95,502
Undistributed oil and natural gas proceeds		34,225			—				—				34,225
Advances from joint interest partners		31,012			—				—				31,012
Asset retirement obligations		30,207			—				—				30,207
Current maturities of long-term debt:
Principal		189,829			(189,829	)	(3)		—				—
Carrying value adjustments		34,985			(34,985	)	(4)		—				—
Current maturities of long-term debt   - carrying value		224,814			(224,814	)			—				—
Accrued liabilities		31,058			(14,989	)	(5)		3,787		(8)		19,856
Total current liabilities		446,818			(239,803	)			3,787				210,802
Long-term debt:
Principal		713,365			(713,365	)	(3)		625,000		(9)		625,000
Borrowings on revolving bank credit facility		—			—				61,000		(10)		61,000
Carrying value adjustments		45,758			(45,758	)	(4)		(17,900	)	(11)		(17,900	)
Long term debt, less current portion   - carrying value		759,123			(759,123	)			668,100				668,100
Asset retirement obligations, less current portion		283,009			—				—				283,009
Other liabilities		73,175			—				—				73,175
Shareholders’ deficit:
Common stock		1			—				—				1
Additional paid-in capital		549,569			—				—				549,569
Retained earnings (deficit)		(985,179	)		46,964		(6)		—				(938,215	)
Treasury stock, at cost		(24,167	)		—				—				(24,167	)
Total shareholders’ deficit		(459,776	)		46,964				—				(412,812	)
Total liabilities and shareholders’ deficit	$	1,102,349		$	(951,962	)		$	671,887			$	822,274

Pro Forma Adjustments:

(1) Cash used to extinguish debt including principal, interest, tender offer premiums and redemption premiums.

(2) Prepaid interest related to the Second Lien Term Loan and the Unsecured Senior Notes.

(3) Payment of outstanding debt principal.

(4) Elimination of carrying value adjustments either through payments or write off of remaining balances.

(5) Payment of interest related to the Second Lien Loan and the Unsecured Senior Notes accrued as of September 30, 2018.

(6) Net gain from the write off of the remaining balances of carrying value adjustments, reduced for interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  In addition, the net gain was reduced for premiums related to repurchases pursuant to the early tender offer, redemptions premiums and certain prepayments paid on the existing notes and loans.

(7) Net proceeds from the issuance of the Senior Second Lien Notes and borrowings under the New Revolving Credit Agreement, less debt issuance costs paid of $14.1 million.

(8) Accrued debt issuance costs related to the Senior Second Lien Notes.

(9) Issuance of the Senior Second Lien Notes.

(10) Borrowings under the New Revolving Credit Agreement.

(11) Paid and accrued debt issuance costs related to the Senior Second Lien Notes and New Revolving Credit Agreement.

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Supplemental Guarantor Information (Tables)

9 Months Ended

Sep. 30, 2018

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Balance Sheet

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  As a result of the JV Drilling Program, we recorded proportional consolidation adjustments, which are not considered a guarantor asset under our debt agreements and, accordingly, are reported as non-guarantor adjustments in the following tables.  Due to the methodology of recording the ceiling-test write down in prior periods, consolidating adjustments are required to present the consolidated results appropriately.  The 2018 Refinancing Transaction substantially changed our capital structure.  See Note 12, Subsequent Events, for additional information.  

Condensed Consolidating Balance Sheet as of September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	339,063		$	—		$	—		$	—		$	339,063
Receivables:
Oil and natural gas sales		7,946			40,972			564			—			49,482
Joint interest		16,493			—			—			—			16,493
Income taxes		199,203			—			—			(133,963	)		65,240
Total receivables		223,642			40,972			564			(133,963	)		131,215
Prepaid expenses and other assets		16,707			2,956			36			—			19,699
Total current assets		579,412			43,928			600			(133,963	)		489,977
Oil and natural gas properties and other, net		372,660			111,907			49,476			(11,262	)		522,781
Restricted deposits for asset retirement obligations		20,577			—			—			—			20,577
Other assets		637,886			589,084			(51,316	)		(1,106,640	)		69,014
Total assets	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	90,260		$	7,318		$	(2,076	)	$	—		$	95,502
Undistributed oil and natural gas proceeds		32,806			1,419			—			—			34,225
Advances from joint interest partners		31,012			-			—			—			31,012
Asset retirement obligations		19,479			10,728			—			—			30,207
Current maturities of long-term debt:
Principal		189,829			—			—			—			189,829
Carrying value adjustments		34,985			—			—			—			34,985
Current maturities of long-term debt  -    carrying value		224,814			—			—			—			224,814
Accrued liabilities		31,076			133,945			—			(133,963	)		31,058
Total current liabilities		429,447			153,410			(2,076	)		(133,963	)		446,818
Long-term debt:
Principal		713,365			—			—			—			713,365
Carrying value adjustments		45,758			—			—			—			45,758
Long term debt, less current portion -   carrying value		759,123			—			—			—			759,123
Asset retirement obligations, less current portion		162,835			120,154			20			—			283,009
Other liabilities		708,461			—			—			(635,286	)		73,175
Shareholders’ equity (deficit):
Common stock		1			—			—			—			1
Additional paid-in capital		549,569			704,885			—			(704,885	)		549,569
Retained earnings (deficit)		(974,734	)		(233,530	)		816			222,269			(985,179	)
Treasury stock, at cost		(24,167	)		—			—			—			(24,167	)
Total shareholders’ equity (deficit)		(449,331	)		471,355			816			(482,616	)		(459,776	)
Total liabilities and shareholders’ equity (deficit)	$	1,610,535		$	744,919		$	(1,240	)	$	(1,251,865	)	$	1,102,349

Condensed Consolidating Balance Sheet as of December 31, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	99,058		$	—		$	—		$	99,058
Receivables:
Oil and natural gas sales		5,665			39,778			—			45,443
Joint interest		19,754			—			—			19,754
Income taxes		128,835			—			(115,829	)		13,006
Total receivables		154,254			39,778			(115,829	)		78,203
Prepaid expenses and other assets		11,154			2,265			—			13,419
Total current assets		264,466			42,043			(115,829	)		190,680
Oil and natural gas properties and other, net		430,354			152,464			(3,802	)		579,016
Restricted deposits for asset retirement obligations		25,394			—			—			25,394
Income taxes receivable		52,097			—			—			52,097
Other assets		505,304			453,306			(898,217	)		60,393
Total assets	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	72,705		$	6,962		$	—		$	79,667
Undistributed oil and natural gas proceeds		18,762			1,367			—			20,129
Advances from joint interest partners		3,998			—			—			3,998
Asset retirement obligations		22,488			1,125			—			23,613
Current maturities of long-term debt  - carrying value		22,925			—			—			22,925
Accrued liabilities		18,058			115,701			(115,829	)		17,930
Total current liabilities		158,936			125,155			(115,829	)		168,262
Long-term debt:
Principal		889,790			—			—			889,790
Carrying value adjustments		79,337			—			—			79,337
Long term debt, less current portion - carrying value		969,127			—			—			969,127
Asset retirement obligations, less current portion		152,883			123,950			—			276,833
Other liabilities		566,375			—			(499,509	)		66,866
Shareholders’ equity (deficit):
Common stock		1			—			—			1
Additional paid-in capital		545,820			704,885			(704,885	)		545,820
Retained earnings (deficit)		(1,091,360	)		(306,177	)		302,375			(1,095,162	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(569,706	)		398,708			(402,510	)		(573,508	)
Total liabilities and shareholders’ equity (deficit)	$	1,277,615		$	647,813		$	(1,017,848	)	$	907,580

Condensed Consolidating Statement of Operations

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Guarantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	79,740		$	71,964	$	1,755	$	—		$	153,459
Operating costs and expenses:
Lease operating expenses		22,188			15,182		60		—			37,430
Production taxes		432			—		—		—			432
Gathering and transportation		3,193			2,545		41		—			5,779
Depreciation, depletion, amortization    and accretion		19,170			15,568		514		1,717			36,969
General and administrative expenses		8,812			7,083		95		—			15,990
Derivative gain		(288	)		—		—		—			(288	)
Total costs and expenses		53,507			40,378		710		1,717			96,312
Operating income		26,233			31,586		1,045		(1,717	)		57,147
Earnings of affiliates		25,977			—		—		(25,977	)		—
Interest expense		11,630			—		—		—			11,630
Other (income) expense, net		(912	)		—		27		—			(885	)
Income before income tax    expense (benefit)		41,492			31,586		1,018		(27,694	)		46,402
Income tax expense (benefit)		(5,467	)		5,609		—		—			142
Net income	$	46,959		$	25,977	$	1,018	$	(27,694	)	$	46,260

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries		Non-Gurantor Adjustments		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	220,796		$	214,264	$	2,224	$	—		$	437,284
Operating costs and expenses:
Lease operating expenses		63,565			46,194		96		—			109,855
Production taxes		1,326			—		—		—			1,326
Gathering and transportation		8,730			6,983		51		—			15,764
Depreciation, depletion, amortization and accretion		58,544			48,125		678		7,460			114,807
General and administrative expenses		22,869			22,073		306		—			45,248
Derivative loss		5,931			—		—		—			5,931
Total costs and expenses		160,965			123,375		1,131		7,460			292,931
Operating income		59,831			90,889		1,093		(7,460	)		144,353
Earnings of affiliates		72,646			—		—		(72,646	)		—
Interest expense		35,100			—		—		—			35,100
Other (income) expense, net		(1,369	)		—		276		—			(1,093	)
Income before income tax   expense (benefit)		98,746			90,889		817		(80,106	)		110,346
Income tax expense (benefit)		(17,880	)		18,243		—		—			363
Net income	$	116,626		$	72,646	$	817	$	(80,106	)	$	109,983

Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	51,981		$	58,300	$	—		$	110,281
Operating costs and expenses:
Lease operating expenses		18,796			16,338		—			35,134
Production taxes		340			—		—			340
Gathering and transportation		1,804			2,304		—			4,108
Depreciation, depletion, amortization and accretion		18,804			16,855		830			36,489
General and administrative expenses		7,131			8,500		—			15,631
Derivative loss		2,879			—		—			2,879
Total costs and expenses		49,754			43,997		830			94,581
Operating income		2,227			14,303		(830	)		15,700
Earnings of affiliates		13,251			—		(13,251	)		—
Interest expense		11,554			—		—			11,554
Other income, net		(41	)		—		—			(41	)
Income before income tax expense		3,965			14,303		(14,081	)		4,187
Income tax expense		4,432			1,052		—			5,484
Net income (loss)	$	(467	)	$	13,251	$	(14,081	)	$	(1,297	)

Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	163,105		$	194,892	$	—		$	357,997
Operating costs and expenses:
Lease operating expenses		59,823			46,994		—			106,817
Production taxes		1,304			—		—			1,304
Gathering and transportation		6,948			8,687		—			15,635
Depreciation, depletion, amortization and accretion		59,391			55,103		2,349			116,843
General and administrative expenses		20,569			24,810		—			45,379
Derivative gain		(4,765	)		—		—			(4,765	)
Total costs and expenses		143,270			135,594		2,349			281,213
Operating income		19,835			59,298		(2,349	)		76,784
Earnings of affiliates		49,719			—		(49,719	)		—
Interest expense		34,284			—		—			34,284
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,073			—		—			5,073
Income before income tax expense (benefit)		38,008			59,298		(52,068	)		45,238
Income tax expense (benefit)		(20,658	)		9,579		—			(11,079	)
Net income	$	58,666		$	49,719	$	(52,068	)	$	56,317

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2018

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Adjustments			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	116,626		$	72,646		$	817		$	(80,106	)	$	109,983
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		58,544			48,125			678			7,460			114,807
Amortization of debt items and other items		1,796			—			—			—			1,796
Share-based compensation		3,808			—			—			—			3,808
Derivative loss		5,931			—			—			—			5,931
Cash receipts on derivative settlements, net		(3,091	)		—			—			—			(3,091	)
Deferred income taxes		363			—			—			—			363
Earnings of affiliates		(72,646	)		—			—			72,646			—
Changes in operating assets and liabilities:											—
Oil and natural gas receivables		(2,281	)		(1,194	)		(564	)		—			(4,039	)
Joint interest receivables		3,261			—			—			—			3,261
Income taxes		(18,382	)		18,243			—			—			(139	)
Prepaid expenses and other assets		(36,764	)		(116,777	)		9,297			135,777			(8,467	)
Asset retirement obligation settlements		(15,860	)		(6,904	)		—			—			(22,764	)
Cash advances from JV partners		27,014			—			—			—			27,014
Accounts payable, accrued liabilities and other		196,880			8,157			(2,871	)		(135,777	)		66,389
Net cash provided by operating activities		265,199			22,296			7,357			—			294,852
Investing activities:
Investment in oil and natural gas properties and equipment		(36,462	)		(14,547	)		(8,152	)		—			(59,161	)
Changes in operating assets and liabilities associated with    investing activities		(13,307	)		(7,749	)		795			—			(20,261	)
Acquisition of property interest		(16,782	)		—			—			—			(16,782	)
Proceeds from sale of assets		50,474			—			—			—			50,474
Net cash used in investing activities		(16,077	)		(22,296	)		(7,357	)		—			(45,730	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,171	)		—			—			—			(6,171	)
Payment of interest on 2nd Lien PIK Toggle Notes		(2,920	)		—			—			—			(2,920	)
Other		(26	)		—			—			—			(26	)
Net cash used in financing activities		(9,117	)		—			—			—			(9,117	)
Increase in cash and cash equivalents		240,005			—			—			—			240,005
Cash and cash equivalents, beginning of period		99,058			—			—			—			99,058
Cash and cash equivalents, end of period	$	339,063		$	—		$	—		$	—		$	339,063

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2017

	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	58,666		$	49,719		$	(52,068	)	$	56,317
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		59,391			55,103			2,349			116,843
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		1,271			—			—			1,271
Share-based compensation		5,449			—			—			5,449
Derivative gain		(4,765	)		—			—			(4,765	)
Cash receipts on derivative settlements		3,924			—			—			3,924
Deferred income taxes		321			—			—			321
Earnings of affiliates		(49,719	)		—			49,719			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(2,694	)		6,600			—			3,906
Joint interest receivables		8			—			—			8
Insurance reimbursements		31,740			—			—			31,740
Income taxes		(9,259	)		9,579			—			320
Prepaid expenses and other assets		1,326			(95,523	)		96,391			2,194
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligations		(41,381	)		(14,845	)		—			(56,226	)
Cash advances from JV partners		(786	)		—			—			(786	)
Accounts payable, accrued liabilities and other		127,387			(3,881	)		(96,391	)		27,115
Net cash provided by operating activities		123,568			6,752			—			130,320
Investing activities:
Investment in oil and natural gas properties and equipment		(68,831	)		(10,257	)		—			(79,088	)
Changes in operating assets and liabilities associated with    investing activities		2,174			3,505			—			5,679
Purchases of furniture, fixtures and other		(905	)		—			—			(905	)
Net cash used in investing activities		(67,562	)		(6,752	)		—			(74,314	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(6,170	)		—			—			(6,170	)
Payment of interest on 2nd Lien PIK Toggle Notes		(7,335	)		—			—			(7,335	)
Payment of interest on 3rd Lien PIK Toggle Notes		(6,201	)		—			—			(6,201	)
Other		(372	)		—			—			(372	)
Net cash used in financing activities		(20,078	)		—			—			(20,078	)
Increase in cash, cash equivalents and restricted cash		35,928			—			—			35,928
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	106,164		$	—		$	—		$	106,164

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Basis of Presentation - Additional Information (Details) - USD ($)	Oct. 18, 2018	Sep. 30, 2018	Dec. 31, 2017
Basis Of Presentation [Line Items]
Debt instrument principal amount		$ 903,194,000	$ 889,790,000
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization		0	$ 0
9.75% Senior Second Lien Notes, Due November 2023 | Subsequent Event
Basis Of Presentation [Line Items]
Debt instrument principal amount	$ 625,000,000
Debt instrument interest rate	9.75%
Debt instrument maturity date	Nov. 01, 2023
Revolving Bank Credit Facility Due October 2022
Basis Of Presentation [Line Items]
Revolving bank credit facility borrowing base		$ 150,000,000
Revolving Bank Credit Facility Due October 2022 | Subsequent Event
Basis Of Presentation [Line Items]
Credit agreement expiration date	Oct. 18, 2022
Revolving bank credit facility borrowing base	$ 250,000,000
Revolving Bank Credit Facility Due October 2022 | Letters of Credit | Subsequent Event
Basis Of Presentation [Line Items]
Revolving bank credit facility maximum lender commitment	$ 30,000,000

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Basis of Presentation - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Prepaid Expense And Other Assets Current [Abstract]
Prepaid/accrued insurance	$ 4,214	$ 2,401
Surety bond unamortized premiums	2,847	2,676
Prepaid deposits related to royalties	9,698	6,456
Advances for capital expenditures	860
Derivative contract premiums	791
Other	1,289	1,886
Prepaid expenses and other assets	$ 19,699	$ 13,419

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Basis of Presentation - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Property Plant And Equipment Net [Abstract]
Oil and natural gas properties and equipment	$ 8,146,742	$ 8,102,044
Furniture, fixtures and other	20,227	21,831
Total property and equipment	8,166,969	8,123,875
Less accumulated depreciation, depletion and amortization	7,644,188	7,544,859
Oil and natural gas properties and other, net	$ 522,781	$ 579,016

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Basis of Presentation - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Other Assets [Abstract]
Escrow deposit - Apache lawsuit	$ 49,500	$ 49,500
Appeal bond deposits	6,925	6,925
Investment in White Cap, LLC	2,648	2,511
Deposit related to letters of credit	4,702
Unamortized brokerage fee for Monza	1,981
Proportional consolidation of Monza's other assets (Note 4)	2,212
Other	1,046	1,457
Total other assets	$ 69,014	$ 60,393

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Basis of Presentation - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Accrued interest	$ 15,041	$ 4,200
Accrued salaries/payroll taxes/benefits	2,291	2,454
Incentive compensation plans	6,452	7,366
Litigation accruals	3,604	3,480
Derivative contracts	3,252	84
Other	418	346
Total accrued liabilities	$ 31,058	$ 17,930

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Basis of Presentation - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Other Liabilities Disclosure [Abstract]
Apache lawsuit	$ 49,500	$ 49,500
Uncertain tax positions including interest/penalties	11,379	11,015
Dispute related to royalty deductions	4,687
Dispute related to royalty-in-kind	2,100	914
Other	5,509	5,437
Total other liabilities (long-term)	$ 73,175	$ 66,866

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Long-Term Debt - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Principal	$ 903,194	$ 889,790
Principal, current	189,829
Principal, less current maturities	713,365	889,790
Adjustments to carrying value, Debt premium, discount, issuance costs, net of amortization	(2,980)	(3,956)
Adjustments to carrying value, Total	80,743	102,262
Adjustments to carrying value, Current maturities	34,985	22,925
Adjustments to carrying value, less current maturities	45,758	79,337
Debt premium, discount, issuance costs, net of amortization	(2,980)	(3,956)
Total long-term debt	983,937	992,052
Long-term debt	224,814	22,925
Long term debt, less current maturities	759,123	969,127
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Principal	75,000	75,000
Adjustments to carrying value, Future interest payments	9,425	15,596
Adjustments to carrying value, Subtotal	9,425	15,596
Carrying Value	84,425	90,596
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Principal	300,000	300,000
Carrying Value	300,000	300,000
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Principal	189,829	189,829
Carrying Value	189,829	189,829
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Principal	177,513	171,769
Adjustments to carrying value, Future payments-in-kind		5,745
Adjustments to carrying value, Future interest payments	31,952	34,872
Adjustments to carrying value, Subtotal	31,952	40,617
Carrying Value	209,465	212,386
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Principal	160,852	153,192
Adjustments to carrying value, Future payments-in-kind	3,664	11,323
Adjustments to carrying value, Future interest payments	38,682	38,682
Adjustments to carrying value, Subtotal	42,346	50,005
Carrying Value	$ 203,198	$ 203,197

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Long-Term Debt - Components of Long-Term Debt (Parenthetical) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017	Sep. 07, 2016	May 31, 2015
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Debt instrument maturity date	Nov. 15, 2019	Nov. 15, 2019
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%		9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%	9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
Debt instrument paid in kind interest rate	10.75%	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2021	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%	10.00%
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2019	Jun. 15, 2019

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Long-Term Debt - Additional Information (Details) - USD ($)		1 Months Ended	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 07, 2016	May 31, 2015	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%			9.00%		9.00%		9.00%
Debt instrument maturity date						May 15, 2020		May 15, 2020
Debt instrument paid in kind interest rate				10.75%		10.75%		10.75%
Debt instrument payment terms						Interest was payable on May 15 and November 15 of each year. For the interest period from November 15, 2017 up to and including March 6, 2018, we had the option to pay all or a portion of interest in-kind at the rate of 10.75% per annum, which if so exercised, is added to the principal amount.
Debt instrument stated interest rate percentage for payment-in-kind	10.75%
Cash interest payable stub period						Mar. 06, 2018
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%			8.50%		8.50%		8.50%
Debt instrument maturity date						Jun. 15, 2021		Jun. 15, 2021
Debt instrument paid in kind interest rate				10.00%		10.00%		10.00%
Debt instrument payment terms						For the interest periods up to and including September 6, 2018, if we so elected, we had the option to pay all or a portion of interest in-kind at a rate of 10.00% per annum. If so elected, such in-kind were added to the principal amount.
Debt instrument stated interest rate percentage for payment-in-kind	10.00%
Cash interest payable stub period						Sep. 06, 2018
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument interest rate				11.00%		11.00%		11.00%
Debt instrument maturity date						Nov. 15, 2019		Nov. 15, 2019
Revolving Bank Credit Facility Due November 2018
Debt Instrument [Line Items]
Revolving bank credit facility borrowing base				$ 150,000,000		$ 150,000,000
First lien leverage ratio						200.00%
Outstanding balances on the revolving bank credit facility (including letters of credit)				5,000,000		$ 5,000,000
Unused portion of the borrowing base commitment fee						0.50%
Credit agreement expiration date						Nov. 08, 2018
Revolving bank credit facility borrowings outstanding				0		$ 0		$ 0
Letters of credit outstanding				9,700,000		9,700,000		$ 300,000
Remaining availability				140,300,000		140,300,000
Amount of cash deposit required for issuance of letters of credit				4,700,000		4,700,000
Unrestricted cash balance exceeding threshold				35,000,000		35,000,000
Revolving Bank Credit Facility Due November 2018 | Letters of Credit
Debt Instrument [Line Items]
Revolving bank credit facility maximum lender commitment				150,000,000		150,000,000
Revolving Bank Credit Facility Due November 2018 | Scenario Covenants
Debt Instrument [Line Items]
Maximum unrestricted cash balance if revolver balance is above $5 million				$ 35,000,000		$ 35,000,000
Revolving Bank Credit Facility Due November 2018 | Minimum
Debt Instrument [Line Items]
Credit agreement, current ratio						100.00%
Revolving Bank Credit Facility Due November 2018 | Minimum | Eurodollar
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						3.00%
Revolving Bank Credit Facility Due November 2018 | Maximum | Eurodollar
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate						4.00%
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Debt instrument maturity date	Nov. 15, 2019
Debt instrument payment terms						Interest accrued at 11.00% per annum and is payable quarterly in cash.
Debt instrument frequency of interest payment in cash						quarterly
Debt instrument, maturity date, description						1.5 Lien Term Loan with a maturity date of November 15, 2019.
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate		9.00%		9.00%		9.00%		9.00%
Debt instrument maturity date						May 15, 2020		May 15, 2020
Debt instrument payment terms						Interest on the Second Lien Term Loan was payable in arrears semi-annually on May 15 and November 15.
Debt instrument discount rate		1.00%
Annual effective interest rate				9.60%		9.60%
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate				8.50%		8.50%		8.50%
Debt instrument maturity date						Jun. 15, 2019		Jun. 15, 2019
Debt instrument payment terms						semi-annually in arrears on June 15 and December 15
Annual effective interest rate				8.40%		8.40%
2016 Restructuring Transactions
Debt Instrument [Line Items]
Interest expense				$ 0	$ 0	$ 0	$ 0
2016 Restructuring Transactions | Scenario, Forecast
Debt Instrument [Line Items]
Interest expense			$ 0
2016 Restructuring Transactions | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument maturity date						May 15, 2020
2016 Restructuring Transactions | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%
2016 Restructuring Transactions | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Maximum
Debt Instrument [Line Items]
Debt instrument paid in kind interest rate	10.75%
2016 Restructuring Transactions | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument maturity date						Jun. 15, 2021
2016 Restructuring Transactions | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%
2016 Restructuring Transactions | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Maximum
Debt Instrument [Line Items]
Debt instrument paid in kind interest rate	10.00%
2016 Restructuring Transactions | 11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Debt instrument maturity date						Nov. 15, 2019

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Fair Value Measurements - Schedule of Fair Value of Long-Term Debt (Details) - Fair Value, Inputs, Level 2 - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
11.00% 1.5 Lien Term Loan, Due November 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, term loan fair value	$ 75,000	$ 75,000
9.00 % Second Lien Term Loan, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, term loan fair value	303,000	288,000
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	179,289	162,322
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	165,677	119,490
8.50% Unsecured Senior Notes, Due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	$ 188,880	$ 178,439

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Fair Value Measurements - Schedule of Fair Value of Long-Term Debt (Parenthetical) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017	Sep. 07, 2016	May 31, 2015
11.00% 1.5 Lien Term Loan, Due November 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	11.00%	11.00%
Debt instrument maturity date	Nov. 15, 2019	Nov. 15, 2019
9.00 % Second Lien Term Loan, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%	9.00%		9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%	9.00%	9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
Debt instrument paid in kind interest rate	10.75%	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2021	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%	10.00%
8.50% Unsecured Senior Notes, Due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2019	Jun. 15, 2019

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Drilling Program Joint Venture - Additional Information (Details) $ in Thousands		3 Months Ended		9 Months Ended
	Mar. 12, 2018 DrillingProject UndevelopedDrillingProject	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Oil And Gas In Process Activities [Line Items]
Oil and natural gas properties		$ 522,781		$ 522,781		$ 579,016
Other assets		69,014		69,014		$ 60,393
Total revenues		153,459	$ 110,281	437,284	$ 357,997
Other expense		885	$ 41	1,093	$ (5,073)
Monza Energy LLC
Oil And Gas In Process Activities [Line Items]
Oil and natural gas properties		7,500		7,500
Other assets		2,200		2,200
Increase in working capital				2,600
Total revenues				2,200
Operating expense				1,100
Other expense				300
Maximum exposure amount by related party		53,500		53,500
JV Drilling Program
Oil And Gas In Process Activities [Line Items]
Percentage of revenue less expenses from joint venture	20.00%
Capital expenditures reimbursement, net		$ 20,000		$ 20,000
JV Drilling Program | Mr. Tracy W. Krohn
Oil And Gas In Process Activities [Line Items]
Minority interest ownership percentage by joint venture		4.50%		4.50%
JV Drilling Program | Monza Energy LLC
Oil And Gas In Process Activities [Line Items]
Joint venture maturity period	3 years
Joint venture ownership percentage contributed to related party	88.94%
Joint venture ownership percentage	11.06%
Number of undeveloped drilling project substituted | UndevelopedDrillingProject	1
Undeveloped drilling project, joint venture ownership percentage contributed to related party	58.71%
Undeveloped drilling project, joint venture ownership percentage	41.29%
Commitment amount by investors				$ 361,400
Percentage of revenue less expenses from joint venture	30.00%
Percentage of estimated well cost	20.00%
Capital contribution payments from members of Monza		$ 114,700		114,700
JV Drilling Program | Monza Energy LLC | Mr. Tracy W. Krohn
Oil And Gas In Process Activities [Line Items]
Capital commitment		$ 14,500		$ 14,500
JV Drilling Program | Monza Energy LLC | Maximum
Oil And Gas In Process Activities [Line Items]
Number of drilling projects | DrillingProject	14

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Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Thousands			9 Months Ended
	Sep. 28, 2018	Apr. 05, 2018	Sep. 30, 2018
Business Acquisition [Line Items]
Asset retirement obligations recognized			$ 3,597
Heidelberg Field Acquisition
Business Acquisition [Line Items]
Gross purchase price		$ 31,100
Net purchase price		16,800
Letters of credit outstanding		9,400
Asset retirement obligations recognized		$ 3,600
Purchase obligations due, year		2028
Purchase commitment		$ 19,600
Permian Basin
Business Acquisition [Line Items]
Net proceeds received from divestiture	$ 50,500
Period following date allowed as condition for curing title defects to receive additional proceeds			90 days
Permian Basin | Maximum
Business Acquisition [Line Items]
Additional proceeds expected to receive from divestiture			$ 6,400
Cobalt International Energy, Inc | Heidelberg Field Acquisition
Business Acquisition [Line Items]
Percentage of non-operated working interest acquired		9.375%

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Asset Retirement Obligations - Summary of Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period		$ 300,446
Asset retirement obligation settlements		(22,764)	$ (56,226)
Accretion of discount		13,872
Liabilities assumed through purchase		3,597
Revisions of estimated liabilities	[1]	18,065
Asset retirement obligations, end of period		313,216
Less current portion		30,207		$ 23,613
Long-term		$ 283,009		$ 276,833

[1] Upward revisions were primarily related to a non-operated field covering multiple wells, which experienced difficulties during the remediation process coupled with scope change due to the size of its platform. In addition, another non-operated field experienced difficulties with a sub-contractor that had gone bankrupt and a replacement sub-contractor is attempting to re-negotiate the contract. We do not have control over the remediation projects for non-operated properties. Along with these two non-operated fields, we had upward revisions at two fields that were operated by us which experienced sustained casing pressure issues during the remediation process.

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Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details)	9 Months Ended
	Sep. 30, 2018 $ / Derivative bbl
N Y M E X Crude Oil Swap
Derivatives Fair Value [Line Items]
Termination Period	December
Notional Quantity (Bbls/day)	2,000	[1]
Notional Quantity (Bbls)	184,000	[1]
Strike Price | $ / Derivative	63.80
NYMEX Crude Oil Puts
Derivatives Fair Value [Line Items]
Termination Period	December
Notional Quantity (Bbls/day)	5,000	[1]
Notional Quantity (Bbls)	460,000	[1]
Put Price | $ / Derivative	60.00
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts One
Derivatives Fair Value [Line Items]
Termination Period	December
Notional Quantity (Bbls/day)	2,000	[1]
Notional Quantity (Bbls)	184,000	[1]
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts One | Put Option | Bought
Derivatives Fair Value [Line Items]
Contract Prices | $ / Derivative	60.00
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts One | Call Option | Sold
Derivatives Fair Value [Line Items]
Contract Prices | $ / Derivative	69.50
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts Two
Derivatives Fair Value [Line Items]
Termination Period	December
Notional Quantity (Bbls/day)	2,000	[1]
Notional Quantity (Bbls)	184,000	[1]
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts Two | Put Option | Bought
Derivatives Fair Value [Line Items]
Contract Prices | $ / Derivative	55.00
NYMEX Crude Oil Two Way Collars | Open Crude Oil Derivative Contracts Two | Call Option | Sold
Derivatives Fair Value [Line Items]
Contract Prices | $ / Derivative	72.75

[1] bbls = barrels

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Derivative Financial Instruments - Additional Information (Details)	Sep. 30, 2018 USD ($)
Derivatives Fair Value [Line Items]
Derivative contract premiums	$ 791,000
N Y M E X Crude Oil Swap
Derivatives Fair Value [Line Items]
Derivative contract premiums	0
NYMEX Crude Oil Two Way Collars
Derivatives Fair Value [Line Items]
Derivative contract premiums	0
Prepaid and Other Assets | NYMEX Crude Oil Puts
Derivatives Fair Value [Line Items]
Derivative contract premiums	$ 2,100,000

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Derivative Financial Instruments - Summary of Open and Closed (Not Settled) Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Total contracts	$ 3,252	$ 84
Open Contracts
Derivatives Fair Value [Line Items]
Total contracts	2,840
Closed Contracts - Not Settled
Derivatives Fair Value [Line Items]
Total contracts	$ 412	$ 84

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Derivative Financial Instruments - Changes in Fair Value and Settlements of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ (288)	$ 2,879	$ 5,931	$ (4,765)

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Derivative Financial Instruments - Cash Receipts (Payments) on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts (payments) on derivative settlements, net	$ (3,091)	$ 3,924

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Share-Based Compensation and Cash-Based Incentive Compensation - Additional Information (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($) shares	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) Award shares	Sep. 30, 2017 USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans | shares	13,342,827		13,342,827
Number of cash based awards | Award			2
Recognized incentive compensation expense	$ 1,374,000	$ 1,984,000	$ 3,808,000	$ 6,324,000
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans | shares	128,980		128,980
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common shares available for issuance reduced conversion basis			One-for-one basis
Aggregate fair value of shares at the grant dates			$ 100,000
Aggregate fair value of shares at the vesting date			200,000
Unrecognized share-based compensation expense	$ 8,300,000		$ 8,300,000
Recognition period for unrecognized compensation expense			2020-11
Recognized incentive compensation expense	1,304,000	1,914,000	$ 3,598,000	6,114,000
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate fair value of shares at the grant dates			300,000
Aggregate fair value of shares at the vesting date			700,000
Unrecognized share-based compensation expense	400,000		$ 400,000
Recognition period for unrecognized compensation expense			2021-04
Recognized incentive compensation expense	$ 70,000	$ 70,000	$ 210,000	$ 210,000
Restricted Shares | Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common shares available for issuance reduced conversion basis			One-to-one basis
2018 Long-term Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash-based awards payment date			Dec. 14, 2020
2018 Short-term Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash-based awards payment date			Mar. 15, 2019
2018 Short-term Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense			$ 200,000,000
2017 Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash based award expected payment period			2018-03
2017 Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense			$ 200,000,000
2016 Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized incentive compensation expense			$ 0
Cash based compensation payment period after achievement of financial condition			30 days
2016 Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense			$ 300,000,000

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Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2018 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	5,765,251
Granted | shares	986,333
Vested | shares	(28,503)
Forfeited/adjustments | shares	(113,014)
Nonvested, end of period | shares	6,610,067
Nonvested, beginning of period | $ / shares	$ 2.48
Granted | $ / shares	6.90
Vested | $ / shares	2.38
Forfeited/adjustments | $ / shares	2.45
Nonvested, end of period | $ / shares	$ 3.14

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Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Outstanding Restricted Stock Units Issued to Eligible Employees (Details) - Restricted Stock Units (RSUs) - shares	Sep. 30, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	6,610,067	5,765,251
2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	3,657,375
2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	1,966,359
2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	986,333

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Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) - Restricted Shares	9 Months Ended
	Sep. 30, 2018 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	246,528
Granted | shares	41,544
Vested | shares	(106,240)
Nonvested, end of period | shares	181,832
Nonvested, beginning of period | $ / shares	$ 2.27
Weighted Average Grant Date Fair Value, Granted | $ / shares	6.74
Weighted Average Grant Date Fair Value, Vested | $ / shares	2.64
Nonvested, end of period | $ / shares	$ 3.08

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Share-Based Compensation and Cash-Based Incentive Compensation - Outstanding Restricted Shares Issued to Non-employee Directors (Details) - Restricted Shares - shares	Sep. 30, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	181,832	246,528
2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	105,012
2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	62,972
2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	13,848

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Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 1,374	$ 1,984	$ 3,808	$ 6,324
Tax benefit computed at the statutory rate	289	694	800	2,213
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	1,304	1,914	3,598	6,114
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 70	$ 70	$ 210	$ 210

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Share-Based Awards and Cash-Based Awards - Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income	$ 1,374	$ 1,984	$ 3,808	$ 6,324
Total charged to operating income	3,745	5,201	11,645	10,939
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income	1,374	1,984	3,808	6,324
Cash-based incentive compensation charged to operating income	1,534	2,287	5,597	3,291
Lease Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income	$ 837	$ 930	$ 2,240	$ 1,324

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Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense (benefit)	$ 142,000	$ 5,484,000	$ 363,000	$ (11,079,000)
Income tax refund received			0	11,900,000
Cash paid for income taxes			0	$ 200,000
Current income taxes receivable	65,240,000		65,240,000		$ 13,006,000
Non-current income taxes receivable					52,097,000
Valuation allowance	$ 148,300,000		$ 148,300,000		$ 171,500,000
Earliest Tax Year
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2013
Latest Tax Year
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2017

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Earnings/ (Loss) Per Share - Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ 46,260	$ (1,297)	$ 109,983	$ 56,317
Less portion allocated to nonvested shares	1,860		4,489	2,349
Net income (loss) allocated to common shares	$ 44,400	$ (1,297)	$ 105,494	$ 53,968
Weighted average common shares outstanding	138,972	137,575	138,917	137,547
Basic and diluted earnings (loss) per common share	$ 0.32	$ (0.01)	$ 0.76	$ 0.39
Shares excluded due to being anti-dilutive (weighted-average)		7,709

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Contingencies - Additional Information (Details) $ in Thousands		9 Months Ended
	Jan. 27, 2017 USD ($)	Sep. 30, 2018 USD ($) claim	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	May 31, 2017 USD ($)	Dec. 15, 2014 DeepwaterWell	Dec. 31, 2010 USD ($)
Loss Contingencies [Line Items]
Number of deepwater wells abandoned | DeepwaterWell						3
Deposit Into registry of court		$ 49,500	$ 49,500
Loss contingency accrued amount		49,500	49,500
Additional royalty payment		600		$ 1,200			$ 4,700
Payments for royalty	$ 4,700
Bond requied to post in order to appeal	7,200
Cash collacteral required to appeal	$ 6,900
Liability reserve		$ 2,100
Royalty payment processing revised period		84 months
BSEE
Loss Contingencies [Line Items]
Number of notices | claim		8
Proposed civil penalties related to various incidents of noncompliance, total		$ 7,900
Payments for civil penalty		3,400
Apache Corporation | Judicial Ruling
Loss Contingencies [Line Items]
Amount owed to Apache under judicial decision					$ 43,200
Prejudgment interest, attorney fees and judgment costs					$ 6,300
Apache Corporation | Judicial Ruling | Other Noncurrent Assets
Loss Contingencies [Line Items]
Deposit Into registry of court		49,500	49,500
Apache Corporation | Judicial Ruling | Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Loss contingency accrued amount		$ 49,500	$ 49,500

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Subsequent Events - Additional Information (Details) - USD ($)		3 Months Ended					9 Months Ended
	Oct. 18, 2018	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Debt instrument principal amount							$ 903,194,000	$ 889,790,000
9.75% Senior Second Lien Notes, Due November 2023 | Prior to November 1, 2020
Subsequent Event [Line Items]
Redemption description							Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date. On and after November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.000% on November 1, 2022 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are guaranteed by Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). If we experience certain change of control events, we will be required to offer to repurchase the notes at 101.000% of the principal amount, plus accrued and unpaid interest, if any, to the repurchase date.
Revolving Bank Credit Facility Due October 2022 | Scenario, Forecast
Subsequent Event [Line Items]
Leverage ratio		300.00%	325.00%	325.00%	350.00%	350.00%
Revolving Bank Credit Facility Due October 2022 | Two Quarters After Material Acquisition
Subsequent Event [Line Items]
Leverage ratio							350.00%
Subsequent Event
Subsequent Event [Line Items]
Investment in Second Lien Term Loan	$ 5,000,000
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023
Subsequent Event [Line Items]
Debt instrument principal amount	$ 625,000,000
Debt instrument interest rate	9.75%
Debt instrument maturity date	Nov. 01, 2023
Debt instrument payment terms	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.
Senior second lien notes repurchase price limit percentage	101.00%
Krohn entities purchase of Senior Second Lien Notes	$ 8,000,000
Customary covenants payment default aggregate amount	50,000,000
Customary covenants final judgment aggregate amount	50,000,000
Customary covenants collateral fair value amount	$ 25,000,000
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023 | Prior to November 1, 2020
Subsequent Event [Line Items]
Redemption price percentage of principal amount plus accrued and unpaid interest	100.00%
Redemption price percentage of principal amount plus accrued and unpaid interest redeemable upon proceeds from equity offering	109.75%
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023 | Prior to November 1, 2020 | Maximum
Subsequent Event [Line Items]
Redemption price percentage	35.00%
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023 | 12-month Period Beginning November 1, 2020
Subsequent Event [Line Items]
Redemption price percentage of principal amount plus accrued and unpaid interest	104.875%
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023 | 12-month Period Beginning November 1, 2021
Subsequent Event [Line Items]
Redemption price percentage of principal amount plus accrued and unpaid interest	102.438%
Subsequent Event | 9.75% Senior Second Lien Notes, Due November 2023 | On November 1, 2022 and Thereafter
Subsequent Event [Line Items]
Redemption price percentage of principal amount plus accrued and unpaid interest	100.00%
Subsequent Event | Revolving Bank Credit Facility Due October 2022
Subsequent Event [Line Items]
Credit agreement expiration date	Oct. 18, 2022
Initial borrowing base and lending commitment	$ 250,000,000
Estimated derivative contracts projected date	Dec. 02, 2018
Estimated derivative contracts projected production period	18 months
Revolving bank credit facility borrowings outstanding	$ 61,000,000
Letters of credit outstanding	9,700,000
Remaining availability	179,300,000
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Letters of Credit
Subsequent Event [Line Items]
Revolving bank credit facility maximum lender commitment	$ 30,000,000
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Maximum
Subsequent Event [Line Items]
Unused portion of the borrowing base commitment fee	0.50%
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Maximum | Eurodollar
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate	3.50%
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Maximum | Alternate Base Rate
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate	2.50%
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Minimum
Subsequent Event [Line Items]
Credit agreement, current ratio	100.00%
Unused portion of the borrowing base commitment fee	0.375%
Estimated percenatge of derivative contracts	50.00%
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Minimum | Eurodollar
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate	2.50%
Subsequent Event | Revolving Bank Credit Facility Due October 2022 | Minimum | Alternate Base Rate
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate	1.50%
Subsequent Event | 2018 Refinancing Transaction
Subsequent Event [Line Items]
Expected gain on refinancing transation	$ 47,000,000
Expected additional capitalized financing fees	$ 17,900,000

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Subsequent Events - Schedule of Condensed Consolidated Balance sheet on a Pro forma Basis (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 339,063	$ 99,058
Total receivables		131,215	78,203
Prepaid expenses and other assets		19,699	13,419
Total current assets		489,977	190,680
Oil and natural gas properties and other, net		522,781	579,016
Restricted deposits for ARO		20,577	25,394
Other assets		69,014	60,393
Total assets		1,102,349	907,580
Current liabilities:
Accounts payable		95,502	79,667
Undistributed oil and natural gas proceeds		34,225	20,129
Advances from joint interest partners		31,012	3,998
Asset retirement obligations		30,207	23,613
Current maturities of long-term debt: (Note 2)
Principal		189,829
Carrying value adjustments		34,985	22,925
Current maturities of long-term debt - carrying value		224,814	22,925
Accrued liabilities		31,058	17,930
Total current liabilities		446,818	168,262
Long-term debt: (Note 2)
Principal		713,365	889,790
Carrying value adjustments		45,758	79,337
Long term debt, less current portion - carrying value		759,123	969,127
Asset retirement obligations, less current portion		283,009	276,833
Other liabilities		73,175	66,866
Shareholders’ deficit:
Common stock		1	1
Additional paid-in capital		549,569	545,820
Retained earnings (deficit)		(985,179)	(1,095,162)
Treasury stock, at cost		(24,167)	(24,167)
Total shareholders' equity (deficit)		(459,776)	(573,508)
Total liabilities and shareholders' equity (deficit)		1,102,349	$ 907,580
Extinguishment of Debt Adjustments
Current assets:
Cash and cash equivalents	[1]	(954,100)
Prepaid expenses and other assets	[2]	2,138
Total current assets		(951,962)
Total assets		(951,962)
Current maturities of long-term debt: (Note 2)
Principal	[3]	(189,829)
Carrying value adjustments	[4]	(34,985)
Current maturities of long-term debt - carrying value		(224,814)
Accrued liabilities	[5]	(14,989)
Total current liabilities		(239,803)
Long-term debt: (Note 2)
Principal	[3]	(713,365)
Carrying value adjustments	[4]	(45,758)
Long term debt, less current portion - carrying value		(759,123)
Shareholders’ deficit:
Retained earnings (deficit)	[6]	46,964
Total shareholders' equity (deficit)		46,964
Total liabilities and shareholders' equity (deficit)		(951,962)
Debt Issuance Adjustments
Current assets:
Cash and cash equivalents	[7]	671,887
Total current assets		671,887
Total assets		671,887
Current maturities of long-term debt: (Note 2)
Accrued liabilities	[8]	3,787
Total current liabilities		3,787
Long-term debt: (Note 2)
Principal	[9]	625,000
Borrowings on revolving bank credit facility	[10]	61,000
Carrying value adjustments	[11]	(17,900)
Long term debt, less current portion - carrying value		668,100
Shareholders’ deficit:
Total liabilities and shareholders' equity (deficit)		671,887
Pro Forma
Current assets:
Cash and cash equivalents		56,850
Total receivables		131,215
Prepaid expenses and other assets		21,837
Total current assets		209,902
Oil and natural gas properties and other, net		522,781
Restricted deposits for ARO		20,577
Other assets		69,014
Total assets		822,274
Current liabilities:
Accounts payable		95,502
Undistributed oil and natural gas proceeds		34,225
Advances from joint interest partners		31,012
Asset retirement obligations		30,207
Current maturities of long-term debt: (Note 2)
Accrued liabilities		19,856
Total current liabilities		210,802
Long-term debt: (Note 2)
Principal		625,000
Borrowings on revolving bank credit facility		61,000
Carrying value adjustments		(17,900)
Long term debt, less current portion - carrying value		668,100
Asset retirement obligations, less current portion		283,009
Other liabilities		73,175
Shareholders’ deficit:
Common stock		1
Additional paid-in capital		549,569
Retained earnings (deficit)		(938,215)
Treasury stock, at cost		(24,167)
Total shareholders' equity (deficit)		(412,812)
Total liabilities and shareholders' equity (deficit)		$ 822,274

[1] Cash used to extinguish debt including principal, interest, tender offer premiums and redemption premiums.

[2] Prepaid interest related to the Second Lien Term Loan and the Unsecured Senior Notes.

[3] Payment of outstanding debt principal.

[4] Elimination of carrying value adjustments either through payments or write off of remaining balances.

[5] Payment of interest related to the Second Lien Loan and the Unsecured Senior Notes accrued as of September 30, 2018.

[6] Net gain from the write off of the remaining balances of carrying value adjustments, reduced for interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes. In addition, the net gain was reduced for premiums related to repurchases pursuant to the early tender offer, redemptions premiums and certain prepayments paid on the existing notes and loans.

[7] Net proceeds from the issuance of the Senior Second Lien Notes and borrowings under the New Revolving Credit Agreement, less debt issuance costs paid of $14.1 million.

[8] Accrued debt issuance costs related to the Senior Second Lien Notes.

[9] Issuance of the Senior Second Lien Notes.

[10] Borrowings under the New Revolving Credit Agreement.

[11] Paid and accrued debt issuance costs related to the Senior Second Lien Notes and New Revolving Credit Agreement.

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Subsequent Events - Schedule of Condensed Consolidated Balance sheet on a Pro forma Basis (Parenthetical) (Details) $ in Millions	Oct. 18, 2018 USD ($)
Subsequent Event | 9.75% Senior Second Lien Notes Due on November 2023 and New Credit Agreement Due on October 2022
Subsequent Event [Line Items]
Debt issuance costs paid	$ 14.1

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Supplemental Guarantor Information - Additional Information (Details)	Sep. 30, 2018
Debt Disclosure [Abstract]
Percentage of subsidiaries owned	100.00%

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Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 339,063	$ 99,058
Receivables:
Oil and natural gas sales	49,482	45,443
Joint interest	16,493	19,754
Income taxes	65,240	13,006
Total receivables	131,215	78,203
Prepaid expenses and other assets	19,699	13,419
Total current assets	489,977	190,680
Oil and natural gas properties and other, net	522,781	579,016
Restricted deposits for asset retirement obligations	20,577	25,394
Income taxes receivable		52,097
Other assets	69,014	60,393
Total assets	1,102,349	907,580
Current liabilities:
Accounts payable	95,502	79,667
Undistributed oil and natural gas proceeds	34,225	20,129
Advances from joint interest partners	31,012	3,998
Asset retirement obligations	30,207	23,613
Current maturities of long-term debt:
Principal	189,829
Carrying value adjustments	34,985	22,925
Current maturities of long-term debt - carrying value	224,814	22,925
Accrued liabilities	31,058	17,930
Total current liabilities	446,818	168,262
Long-term debt:
Principal	713,365	889,790
Carrying value adjustments	45,758	79,337
Long term debt, less current portion - carrying value	759,123	969,127
Asset retirement obligations, less current portion	283,009	276,833
Other liabilities	73,175	66,866
Shareholders’ equity (deficit):
Common stock	1	1
Additional paid-in capital	549,569	545,820
Retained earnings (deficit)	(985,179)	(1,095,162)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders' equity (deficit)	(459,776)	(573,508)
Total liabilities and shareholders' equity (deficit)	1,102,349	907,580
Parent Company
Current assets:
Cash and cash equivalents	339,063	99,058
Receivables:
Oil and natural gas sales	7,946	5,665
Joint interest	16,493	19,754
Income taxes	199,203	128,835
Total receivables	223,642	154,254
Prepaid expenses and other assets	16,707	11,154
Total current assets	579,412	264,466
Oil and natural gas properties and other, net	372,660	430,354
Restricted deposits for asset retirement obligations	20,577	25,394
Income taxes receivable		52,097
Other assets	637,886	505,304
Total assets	1,610,535	1,277,615
Current liabilities:
Accounts payable	90,260	72,705
Undistributed oil and natural gas proceeds	32,806	18,762
Advances from joint interest partners	31,012	3,998
Asset retirement obligations	19,479	22,488
Current maturities of long-term debt:
Principal	189,829
Carrying value adjustments	34,985
Current maturities of long-term debt - carrying value	224,814	22,925
Accrued liabilities	31,076	18,058
Total current liabilities	429,447	158,936
Long-term debt:
Principal	713,365	889,790
Carrying value adjustments	45,758	79,337
Long term debt, less current portion - carrying value	759,123	969,127
Asset retirement obligations, less current portion	162,835	152,883
Other liabilities	708,461	566,375
Shareholders’ equity (deficit):
Common stock	1	1
Additional paid-in capital	549,569	545,820
Retained earnings (deficit)	(974,734)	(1,091,360)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders' equity (deficit)	(449,331)	(569,706)
Total liabilities and shareholders' equity (deficit)	1,610,535	1,277,615
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	40,972	39,778
Total receivables	40,972	39,778
Prepaid expenses and other assets	2,956	2,265
Total current assets	43,928	42,043
Oil and natural gas properties and other, net	111,907	152,464
Other assets	589,084	453,306
Total assets	744,919	647,813
Current liabilities:
Accounts payable	7,318	6,962
Undistributed oil and natural gas proceeds	1,419	1,367
Asset retirement obligations	10,728	1,125
Current maturities of long-term debt:
Accrued liabilities	133,945	115,701
Total current liabilities	153,410	125,155
Long-term debt:
Asset retirement obligations, less current portion	120,154	123,950
Shareholders’ equity (deficit):
Additional paid-in capital	704,885	704,885
Retained earnings (deficit)	(233,530)	(306,177)
Total shareholders' equity (deficit)	471,355	398,708
Total liabilities and shareholders' equity (deficit)	744,919	647,813
Non-Guarantor Adjustments
Receivables:
Oil and natural gas sales	564
Total receivables	564
Prepaid expenses and other assets	36
Total current assets	600
Oil and natural gas properties and other, net	49,476
Other assets	(51,316)
Total assets	(1,240)
Current liabilities:
Accounts payable	(2,076)
Current maturities of long-term debt:
Total current liabilities	(2,076)
Long-term debt:
Asset retirement obligations, less current portion	20
Shareholders’ equity (deficit):
Retained earnings (deficit)	816
Total shareholders' equity (deficit)	816
Total liabilities and shareholders' equity (deficit)	(1,240)
Eliminations
Receivables:
Income taxes	(133,963)	(115,829)
Total receivables	(133,963)	(115,829)
Total current assets	(133,963)	(115,829)
Oil and natural gas properties and other, net	(11,262)	(3,802)
Other assets	(1,106,640)	(898,217)
Total assets	(1,251,865)	(1,017,848)
Current maturities of long-term debt:
Accrued liabilities	(133,963)	(115,829)
Total current liabilities	(133,963)	(115,829)
Long-term debt:
Other liabilities	(635,286)	(499,509)
Shareholders’ equity (deficit):
Additional paid-in capital	(704,885)	(704,885)
Retained earnings (deficit)	222,269	302,375
Total shareholders' equity (deficit)	(482,616)	(402,510)
Total liabilities and shareholders' equity (deficit)	$ (1,251,865)	$ (1,017,848)

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Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Condensed Income Statements Captions [Line Items]
Revenues	$ 153,459	$ 110,281	$ 437,284	$ 357,997
Operating costs and expenses:
Lease operating expenses	37,430	35,134	109,855	106,817
Production taxes	432	340	1,326	1,304
Depreciation, depletion, amortization and accretion	36,969	36,489	114,807	116,843
General and administrative expenses	15,990	15,631	45,248	45,379
Derivative (gain) loss	(288)	2,879	5,931	(4,765)
Total costs and expenses	96,312	94,581	292,931	281,213
Operating income	57,147	15,700	144,353	76,784
Interest expense	11,630	11,554	35,100	34,284
Gain on exchange of debt				7,811
Other (income) expense, net	(885)	(41)	(1,093)	5,073
Income before income tax expense (benefit)	46,402	4,187	110,346	45,238
Income tax expense (benefit)	142	5,484	363	(11,079)
Net income (loss)	46,260	(1,297)	109,983	56,317
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues	79,740	51,981	220,796	163,105
Operating costs and expenses:
Lease operating expenses	22,188	18,796	63,565	59,823
Production taxes	432	340	1,326	1,304
Depreciation, depletion, amortization and accretion	19,170	18,804	58,544	59,391
General and administrative expenses	8,812	7,131	22,869	20,569
Derivative (gain) loss	(288)	2,879	5,931	(4,765)
Total costs and expenses	53,507	49,754	160,965	143,270
Operating income	26,233	2,227	59,831	19,835
Earnings of affiliates	25,977	13,251	72,646	49,719
Interest expense	11,630	11,554	35,100	34,284
Gain on exchange of debt				7,811
Other (income) expense, net	(912)	(41)	(1,369)	5,073
Income before income tax expense (benefit)	41,492	3,965	98,746	38,008
Income tax expense (benefit)	(5,467)	4,432	(17,880)	(20,658)
Net income (loss)	46,959	(467)	116,626	58,666
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues	71,964	58,300	214,264	194,892
Operating costs and expenses:
Lease operating expenses	15,182	16,338	46,194	46,994
Depreciation, depletion, amortization and accretion	15,568	16,855	48,125	55,103
General and administrative expenses	7,083	8,500	22,073	24,810
Total costs and expenses	40,378	43,997	123,375	135,594
Operating income	31,586	14,303	90,889	59,298
Income before income tax expense (benefit)	31,586	14,303	90,889	59,298
Income tax expense (benefit)	5,609	1,052	18,243	9,579
Net income (loss)	25,977	13,251	72,646	49,719
Non-Guarantor Adjustments
Condensed Income Statements Captions [Line Items]
Revenues	1,755		2,224
Operating costs and expenses:
Lease operating expenses	60		96
Depreciation, depletion, amortization and accretion	514		678
General and administrative expenses	95		306
Total costs and expenses	710		1,131
Operating income	1,045		1,093
Other (income) expense, net	27		276
Income before income tax expense (benefit)	1,018		817
Net income (loss)	1,018		817
Gathering and transportation
Operating costs and expenses:
Operating costs and expenses	5,779	4,108	15,764	15,635
Gathering and transportation | Parent Company
Operating costs and expenses:
Operating costs and expenses	3,193	1,804	8,730	6,948
Gathering and transportation | Guarantor Subsidiaries
Operating costs and expenses:
Operating costs and expenses	2,545	2,304	6,983	8,687
Gathering and transportation | Non-Guarantor Adjustments
Operating costs and expenses:
Operating costs and expenses	41		51
Eliminations
Operating costs and expenses:
Depreciation, depletion, amortization and accretion	1,717	830	7,460	2,349
Total costs and expenses	1,717	830	7,460	2,349
Operating income	(1,717)	(830)	(7,460)	(2,349)
Earnings of affiliates	(25,977)	(13,251)	(72,646)	(49,719)
Income before income tax expense (benefit)	(27,694)	(14,081)	(80,106)	(52,068)
Net income (loss)	$ (27,694)	$ (14,081)	$ (80,106)	$ (52,068)

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Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating activities:
Net income	$ 46,260	$ (1,297)	$ 109,983	$ 56,317
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	36,969	36,489	114,807	116,843
Gain on exchange of debt				(7,811)
Amortization of debt items and other items			1,796	1,271
Share-based compensation			3,808	5,449
Derivative (gain) loss	(288)	2,879	5,931	(4,765)
Cash receipts on derivative settlements, net			(3,091)	3,924
Deferred income taxes			363	321
Changes in operating assets and liabilities:
Oil and natural gas receivables			(4,039)	3,906
Joint interest receivables			3,261	8
Insurance reimbursements				31,740
Income taxes			(139)	320
Prepaid expenses and other assets			(8,467)	2,194
Escrow deposit - Apache lawsuit				(49,500)
Asset retirement obligation settlements			(22,764)	(56,226)
Cash advances from JV partners			27,014	(786)
Accounts payable, accrued liabilities and other			66,389	27,115
Net cash provided by operating activities			294,852	130,320
Investing activities:
Investment in oil and natural gas properties and equipment			(59,161)	(79,088)
Changes in operating assets and liabilities associated with investing activities			(20,261)	5,679
Acquisition of property interest			(16,782)
Purchases of furniture, fixtures and other				(905)
Proceeds from sale of assets			50,474
Net cash used in investing activities			(45,730)	(74,314)
Financing activities:
Other			(26)	(372)
Net cash used in financing activities			(9,117)	(20,078)
Increase in cash and cash equivalents			240,005	35,928
Cash and cash equivalents, beginning of period			99,058	70,236
Cash and cash equivalents, end of period	339,063	106,164	339,063	106,164
Parent Company
Operating activities:
Net income	46,959	(467)	116,626	58,666
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	19,170	18,804	58,544	59,391
Gain on exchange of debt				(7,811)
Amortization of debt items and other items			1,796	1,271
Share-based compensation			3,808	5,449
Derivative (gain) loss	(288)	2,879	5,931	(4,765)
Cash receipts on derivative settlements, net			(3,091)	3,924
Deferred income taxes			363	321
Earnings of affiliates	(25,977)	(13,251)	(72,646)	(49,719)
Changes in operating assets and liabilities:
Oil and natural gas receivables			(2,281)	(2,694)
Joint interest receivables			3,261	8
Insurance reimbursements				31,740
Income taxes			(18,382)	(9,259)
Prepaid expenses and other assets			(36,764)	1,326
Escrow deposit - Apache lawsuit				(49,500)
Asset retirement obligation settlements			(15,860)	(41,381)
Cash advances from JV partners			27,014	(786)
Accounts payable, accrued liabilities and other			196,880	127,387
Net cash provided by operating activities			265,199	123,568
Investing activities:
Investment in oil and natural gas properties and equipment			(36,462)	(68,831)
Changes in operating assets and liabilities associated with investing activities			(13,307)	2,174
Acquisition of property interest			(16,782)
Purchases of furniture, fixtures and other				(905)
Proceeds from sale of assets			50,474
Net cash used in investing activities			(16,077)	(67,562)
Financing activities:
Other			(26)	(372)
Net cash used in financing activities			(9,117)	(20,078)
Increase in cash and cash equivalents			240,005	35,928
Cash and cash equivalents, beginning of period			99,058	70,236
Cash and cash equivalents, end of period	339,063	106,164	339,063	106,164
Guarantor Subsidiaries
Operating activities:
Net income	25,977	13,251	72,646	49,719
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	15,568	16,855	48,125	55,103
Changes in operating assets and liabilities:
Oil and natural gas receivables			(1,194)	6,600
Income taxes			18,243	9,579
Prepaid expenses and other assets			(116,777)	(95,523)
Asset retirement obligation settlements			(6,904)	(14,845)
Accounts payable, accrued liabilities and other			8,157	(3,881)
Net cash provided by operating activities			22,296	6,752
Investing activities:
Investment in oil and natural gas properties and equipment			(14,547)	(10,257)
Changes in operating assets and liabilities associated with investing activities			(7,749)	3,505
Net cash used in investing activities			(22,296)	(6,752)
Non-Guarantor Adjustments
Operating activities:
Net income	1,018		817
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	514		678
Changes in operating assets and liabilities:
Oil and natural gas receivables			(564)
Prepaid expenses and other assets			9,297
Accounts payable, accrued liabilities and other			(2,871)
Net cash provided by operating activities			7,357
Investing activities:
Investment in oil and natural gas properties and equipment			(8,152)
Changes in operating assets and liabilities associated with investing activities			795
Net cash used in investing activities			(7,357)
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Payment of interest			(6,171)	(6,170)
11.00% 1.5 Lien Term Loan, Due November 2019 | Parent Company
Financing activities:
Payment of interest			(6,171)	(6,170)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest			(2,920)	(7,335)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Parent Company
Financing activities:
Payment of interest			(2,920)	(7,335)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Financing activities:
Payment of interest				(6,201)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Parent Company
Financing activities:
Payment of interest				(6,201)
Eliminations
Operating activities:
Net income	(27,694)	(14,081)	(80,106)	(52,068)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,717	830	7,460	2,349
Earnings of affiliates	$ 25,977	$ 13,251	72,646	49,719
Changes in operating assets and liabilities:
Prepaid expenses and other assets			135,777	96,391
Accounts payable, accrued liabilities and other			$ (135,777)	$ (96,391)