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 June 30, 2017

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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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	☑	Emerging growth company	☐
Non-accelerated filer	☐	Smaller reporting company	☐

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

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 or Rule 12b-2 of the Securities Exchange Act of 1934.   Emerging growth company  ☐

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 August 1, 2017, there were 137,821,744 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 June 30, 2017 and December 31, 2016	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016	2
	Condensed Consolidated Statement of Changes in Shareholders’ Deficit for the Six Months Ended June 30, 2017	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	48
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	49
SIGNATURE		50
EXHIBIT INDEX		51

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	June 30,			December 31,
	2017			2016
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	72,320		$	70,236
Receivables:
Oil and natural gas sales		39,397			43,073
Joint interest		19,920			21,885
Insurance reimbursement		—			30,100
Income taxes		12,027			11,943
Total receivables		71,344			107,001
Prepaid expenses and other assets (Note 1)		21,944			14,504
Total current assets		165,608			191,741
Oil and natural gas properties and other, net - at cost: (Note 1)		550,681			547,053
Restricted deposits for asset retirement obligations		28,712			27,371
Income tax receivables		68,974			52,097
Other assets (Note 1)		60,996			11,464
Total assets	$	874,971		$	829,726
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	58,283		$	81,039
Undistributed oil and natural gas proceeds		21,270			26,254
Asset retirement obligations		52,432			78,264
Long-term debt		11,147			8,272
Accrued liabilities (Note 1)		13,122			9,200
Total current liabilities		156,254			203,029
Long-term debt: (Note 2)
Principal		873,733			873,733
Carrying value adjustments		110,604			138,722
Long term debt, less current portion - carrying value		984,337			1,012,455
Asset retirement obligations, less current portion		265,428			256,174
Other liabilities (Note 1)		66,909			17,105
Commitments and contingencies (Note 9)		—			—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at    June 30, 2017 and December 31, 2016		—			—
Common stock, $0.00001 par value; 200,000,000 shares authorized;    140,690,917 issued and 137,821,744 outstanding at June 30, 2017 and    140,543,545 issued and 137,674,372 outstanding at December 31, 2016		1			1
Additional paid-in capital		543,439			539,973
Retained earnings (deficit)		(1,117,230	)		(1,174,844	)
Treasury stock, at cost; 2,869,173 shares at June 30, 2017 and December 31, 2016		(24,167	)		(24,167	)
Total shareholders’ deficit		(597,957	)		(659,037	)
Total liabilities and shareholders’ deficit	$	874,971		$	829,726

See Notes to Condensed Consolidated Financial Statements

1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands except per share data)
	(Unaudited)
Revenues	$	123,323		$	99,655		$	247,716		$	177,370
Operating costs and expenses:
Lease operating expenses		31,519			36,622			71,683			81,091
Production taxes		449			370			964			896
Gathering and transportation		5,318			6,398			11,527			11,490
Depreciation, depletion, amortization and accretion		40,364			57,493			80,354			121,226
Ceiling test write-down of oil and natural gas properties		—			104,592			—			221,151
General and administrative expenses		16,474			16,235			29,748			32,678
Derivative (gain) loss		(3,689	)		4,942			(7,644	)		2,449
Total costs and expenses		90,435			226,652			186,632			470,981
Operating income (loss)		32,888			(126,997	)		61,084			(293,611	)
Interest expense:
Incurred		11,436			29,773			22,730			57,587
Capitalized		—			(102	)		—			(445	)
Gain on exchange of debt		8,056			—			7,811			—
Other (income) expense, net		5,168			(24	)		5,114			1,282
Income (loss) before income tax benefit		24,340			(156,644	)		41,051			(352,035	)
Income tax benefit		(8,975	)		(35,722	)		(16,563	)		(40,604	)
Net income (loss)	$	33,315		$	(120,922	)	$	57,614		$	(311,431	)
Basic and diluted earnings (loss) per common share	$	0.23		$	(1.58	)	$	0.40		$	(4.07	)

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, 2016		137,674	$	1	$	539,973	$	(1,174,844	)		2,869	$	(24,167	)	$	(659,037	)
Share-based compensation		148		—		3,466		—			—		—			3,466
Net income		—		—		—		57,614			—		—			57,614
Balances at June 30, 2017		137,822	$	1	$	543,439	$	(1,117,230	)		2,869	$	(24,167	)	$	(597,957	)

See Notes to Condensed Consolidated Financial Statements.

3

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
	2017			2016
	(In thousands)
	(Unaudited)
Operating activities:
Net income (loss)	$	57,614		$	(311,431	)
Adjustments to reconcile net income (loss) to net cash provided by (used in)    operating activities:
Depreciation, depletion, amortization and accretion		80,354			121,226
Ceiling test write-down of oil and natural gas properties		—			221,151
Gain on exchange of debt		(7,811	)		—
Debt issuance costs write-down/amortization of debt items		836			1,880
Share-based compensation		3,466			5,121
Derivative (gain) loss		(7,644	)		2,449
Cash receipts on derivative settlements		2,208			4,746
Deferred income taxes		212			19,285
Changes in operating assets and liabilities:
Oil and natural gas receivables		3,675			1,226
Joint interest receivables		1,965			1,763
Insurance reimbursements		30,100			—
Income taxes		(16,960	)		(57,931	)
Prepaid expenses and other assets		(3,575	)		(10,365	)
Escrow deposit - Apache lawsuit		(49,500	)		—
Asset retirement obligation settlements		(36,021	)		(25,156	)
Accounts payable, accrued liabilities and other		6,666			14,767
Net cash provided by (used in) operating activities		65,585			(11,269	)
Investing activities:
Investment in oil and natural gas properties and equipment		(43,800	)		(17,712	)
Changes in operating assets and liabilities associated with investing activities		(827	)		(34,122	)
Proceeds from sales of assets		—			1,500
Purchases of furniture, fixtures and other		(853	)		(70	)
Net cash used in investing activities		(45,480	)		(50,404	)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility		—			340,000
Repayments of long-term debt - revolving bank credit facility		—			(192,000	)
Payment of interest on 1.5 Lien Term Loan		(4,113	)		—
Payment of interest on 2nd Lien PIK Toggle Notes		(7,335	)		—
Payment of interest on 3rd Lien PIK Toggle Notes		(6,201	)		—
Other		(372	)		83
Net cash provided by (used in) financing activities		(18,021	)		148,083
Increase in cash and cash equivalents		2,084			86,410
Cash and cash equivalents, beginning of period		70,236			85,414
Cash and cash equivalents, end of period	$	72,320		$	171,824

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 interest 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”).  

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, 2016.

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 prices of these commodities improved during the first half of 2017 compared to the average prices in the first half of 2016 and for the full year of 2016.  Operating costs were lower in the first half of 2017 on a barrel oil equivalent (“Boe”) basis compared to the first half of 2016.  In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments in the first half of 2017 compared to the first half of 2016.  In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described below, the maturities of two of the new loans will accelerate if certain events do not transpire.

We continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”).  Our 2017 capital budget is relatively modest by historical standards and we have some flexibility for the balance of the year.  The 2017 capital budget is higher than the capital expenditures incurred during 2016, but it is significantly lower than spending levels incurred during 2015 and 2014.  

During the first half of 2017, the Bureau of Ocean Energy Management (“BOEM”) extended the implementation timeline (without setting a revised implementation date) for Notice to Lessees #2016-N01 (“NTL #2016-N01”) regarding financial assurances to be provided by lessees in connection with Outer Continental Shelf (“OCS”) leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”) for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  Also, in the first quarter of 2017, the BOEM withdrew the orders related to its so called “sole liability” properties it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.

Actions are underway for the BOEM to rescind the previous orders regarding financial assurances issued in the first quarter of 2016 totaling $260.8 million.  See Note 9 and Note 10 for additional information.

5

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

During the second quarter of 2017, a final trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us.  As a result, we deposited $49.5 million in an escrow account from cash on hand as a first step to allow us to appeal the decision.  See Note 9 for additional information.  

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices.  We believe we will have adequate liquidity to fund our operations beyond September 2018, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or the future 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, 2016 concerning risks related to our business and events occurring during 2016 and other information and the Notes herein for additional information.  

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

	June 30,		December 31,
	2017		2016
Derivative assets (1)	$	6,365	$	—
Prepaid/accrued insurance		3,802		2,924
Surety bond unamortized premiums		2,855		2,462
Prepaid deposits related to royalties		6,155		6,237
Other		2,767		2,881
Prepaid expenses and other assets	$	21,944	$	14,504

(1) Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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

	June 30,		December 31,
	2017		2016
Oil and natural gas properties and equipment	$	8,007,073	$	7,932,504
Furniture, fixtures and other		21,751		20,898
Total property and equipment		8,028,824		7,953,402
Less accumulated depreciation, depletion and amortization		7,478,143		7,406,349
Oil and natural gas properties and other, net	$	550,681	$	547,053

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

	June 30,		December 31,
	2017		2016
Accrued interest	$	4,196	$	4,189
Accrued salaries/payroll taxes/benefits		4,627		2,777
Other		4,299		2,234
Total accrued liabilities	$	13,122	$	9,200

6

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

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

	June 30,		December 31,
	2017		2016
Escrow deposit - Apache lawsuit	$	49,500	$	—
Appeal bond deposits		6,925		6,925
Other		4,571		4,539
Total other assets	$	60,996	$	11,464

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

	June 30,		December 31,
	2017		2016
Apache lawsuit	$	49,500	$	—
Uncertain tax positions including interest/penalties		10,796		10,584
Other		6,613		6,521
Total other liabilities (long-term)	$	66,909	$	17,105

Recent Accounting Developments.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application (modified retrospective approach). Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is that the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  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 finance or operating lease.  However, unlike current GAAP, which requires only capital 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.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space in Houston, Texas and New Orleans, Louisiana, 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.  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.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

7

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

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  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 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the statement of cash flows (financing vs. investing) and the amount of such change would not have been material; therefore, we do not anticipate the new standard will have a material effect on our financial statements.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

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):

	June 30, 2017								December 31, 2016
			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		—		19,709			19,709			—		23,823			23,823
Subtotal		75,000		19,709			94,709			75,000		23,823			98,823
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		163,007		—			163,007			163,007		—			163,007
Future payments-in-kind		—		14,506			14,506			—		24,048			24,048
Future interest payments		—		34,873			34,873			—		36,850			36,850
Subtotal		163,007		49,379			212,386			163,007		60,898			223,905
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		145,897		—			145,897			145,897		—			145,897
Future payments-in-kind		—		18,618			18,618			—		26,844			26,844
Future interest payments		—		38,682			38,682			—		40,705			40,705
Subtotal		145,897		57,300			203,197			145,897		67,549			213,446
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(4,637	)		(4,637	)		—		(5,276	)		(5,276	)
Total long-term debt		873,733		121,751			995,484			873,733		146,994			1,020,727
Current maturities of long-term debt (2)		—		11,147			11,147			—		8,272			8,272
Long term debt, less current    maturities	$	873,733	$	110,604		$	984,337		$	873,733	$	138,722		$	1,012,455

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

(2) Future interest payments on the 1.5 Lien Term Loan and Second Lien PIK Toggle Notes due within twelve months.

9

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

Exchange Transaction

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes, due June 15, 2019 (the “Unsecured Senior Notes”) for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 15, 2019, (the “1.5 Lien Term Loan”) with the largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”).  We accounted for the Exchange Transaction 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 newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Condensed Consolidated Statements of Operations during the six months ended June 30, 2017.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.     

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

During the second quarter of 2017, interest on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes was paid in cash rather than in kind.  As a result of the cash interest payment, an $8.2 million net reduction was recorded to long-term debt on the Condensed Consolidated Balance Sheet and the offset to Gain on exchange of debt in the Condensed Consolidated Statement of Operations.  We anticipate the remaining eligible interest payments will be made in kind versus paid in cash.  For the six months ended June 30, 2017, $0.4 million of additional expense was recorded to Gain on exchange of debt for differences between actual and estimated transaction expenses.

The primary terms of our long-term debt following the Exchange Transaction are described below.    

Credit Agreement

The Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), provides a revolving bank credit facility.  The primary items of the Credit Agreement are as follows, with certain terms defined under the Credit Agreement:

• The borrowing base is $150.0 million.

• Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.      

• The First Lien Leverage Ratio limits are 2.50 to 1.00 through June 30, 2017, and 2.00 to 1.00 thereafter.

• The Current Ratio must be greater than 1.00 to 1.00.

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

• We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

• Borrowings primarily are executed as Eurodollar Loans, and the applicable margins range from 3.00% to 4.00%.

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

• The Credit Agreement terminates on November 8, 2018.

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

Availability under our revolving bank credit facility 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 2017 spring redetermination reaffirmed the borrowing base amount of $150.0 million.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  The revolving bank credit facility is secured and is collateralized by a first priority lien on substantially all of our oil and natural gas properties.  

The Credit Agreement contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other long-term debt agreements, and such agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2017.

  As of June 30, 2017 and December 31, 2016, we did not have any borrowings outstanding and had $0.3 million and $0.5 million, respectively, of letters of credit outstanding under the revolving bank credit facility.  Availability as of June 30, 2017 was $149.7 million.

1.5 Lien Term Loan

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the 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 have been included in the carrying value under ASC 470-60.  Current maturities of long-term debt include the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; (vii) create liens that secure debt; and (viii) enter into transactions with affiliates.  We were in compliance with all applicable covenants as of June 30, 2017.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%.  The Second Lien Term Loan was issued at a 1.0% discount to par, matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.6%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  The Second Lien Term Loan contains covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.

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

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016 with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period.  For the initial interest period ending November 15, 2016, interest could only be paid-in-kind at the annual rate of 10.75%.  For interest periods through March 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.75% per annum.  For the six month interest period ending May 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and are effectively pari passu with the Second Lien Term Loan (discussed above).  For purposes of determining the carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid in kind versus paid in cash.  When the PIK option is utilized, the principal amount of the notes increases.  Current maturities of long-term debt include the cash interest payable for the Second Lien PIK Toggle Notes for the stub period of March 7, 2018 to May 15, 2018.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.    

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016 with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain interest provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period.  For the initial interest period ending December 15, 2016, interest could only be paid in kind at the annual rate of 10.00%.  For interest periods through September 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.00% per annum.  For the six month interest period ending June 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid in kind versus paid in cash.  When the PIK option is utilized, the principal amount of the notes increases.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.

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

Unsecured Senior Notes

Our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.3%, which includes amortization of premiums and debt issuance costs.  The Unsecured Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.  

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

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 inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads, credit risk and published commodity futures prices.  The fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as no market has developed and the holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  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 an active market; therefore, the fair value is classified within Level 2.  

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

	June 30, 2017				December 31, 2016
	Assets		Liabilities		Assets		Liabilities
Derivatives - open contracts	$	5,436	$	—	$	—	$	—
11.00% 1.5 Term Loan, due November 2019 (1)		—		75,000		—		75,000
9.00% Second Lien Term Loan, due May 2020 (1)		—		249,000		—		255,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 (1)		—		133,666		—		122,255
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 (1)		—		99,210		—		80,243
8.50% Unsecured Senior Notes, due June 2019  (1)		—		131,931		—		123,389

(1) The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2.  

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

4.  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, 2016	$	334,438
Liabilities settled		(36,021	)
Accretion of discount		8,560
Revisions of estimated liabilities (1)		10,883
Balance, June 30, 2017		317,860
Less current portion		52,432
Long-term	$	265,428

(1) Revisions were primarily related to changes from sustained casing pressure at four fields.  Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project.  

5.  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 oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  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.

For information about fair value measurements, refer to Note 3.

Commodity Derivatives

As of June 30, 2017, we had open crude oil and natural gas derivative contracts for a portion of our anticipated future production for the remainder of 2017.  These contracts were entered into during the first quarter of 2017.  For crude oil, we entered into two types of contracts.  The first type is a swap contract, where we either receive or pay depending on whether the crude oil price is below or above the contract price.   The second type is known as “two-way collar” consisting of a purchased put option and a sold call option.  These two-way collars provide price risk protection if commodity prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  For natural gas, we entered into “two-way collar” contracts.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  The strike prices of both the oil and natural gas two-way collar contracts were set so that the contracts were premium neutral (“costless”), which means no net premiums were paid to or received from a counterparty.  Settlement occurs monthly using the per day notional quantity.  As of December 31, 2016, we did not have any open derivative contracts.    

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

As of June 30, 2017, our open commodity derivative contracts were as follows:

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)
		Quantity		Quantity		Strike
Termination Period		(Bbls/day)		(Bbls)		Price
2017	4th Quarter		1,000		184,000	$	55.25
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day)		(Bbls)		(Bought)		(Sold)
2017	4th Quarter		4,000		736,000	$	50.00	$	60.15
Natural Gas:  Two-way collars, Priced off Henry Hub (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(MMBtu's/day)		(MMBtu's)		(Bought)		(Sold)
2017	4th Quarter (2)		30,000		4,590,000	$	3.07	$	3.96

(1) Volume Measurements:   Bbls – barrelsMMBtu’s – million British Thermal Units.

(2) The natural gas derivative contracts are priced and closed in the last week prior to the related production month.  Natural gas derivative contracts related to July 2017 production were priced and closed in June 2017 and are not included in the above table as these were not open derivative contracts as of June 30, 2017.

Our open and closed (not settled) commodity derivative contracts were recorded within the line Prepaid expenses and other assets on the Condensed Consolidated Balance Sheets summarized in the following table (in thousands):

	June 30,		December 31,
	2017		2016
Open contracts	$	5,436	$	—
Closed contracts - not settled		929		—
Total contracts	$	6,365	$	—

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017			2016		2017			2016
Derivative (gain) loss	$	(3,689	)	$	4,942	$	(7,644	)	$	2,449

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

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

	Six Months Ended
	June 30,
	2017		2016
Cash receipts on derivative settlements, net	$	2,208	$	4,746

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 revolving bank credit facility, that event may also trigger an acceleration of settlement 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.  

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

Awards to Employees.  In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders, and amendments to the Plan were approved by our shareholders in May 2013, May 2016 and May 2017.  The May 2017 amendment increased the number of shares available in the Plan by 7,700,000 shares.  As allowed by the Plan, during the six months ended June 30, 2017 and the years 2016 and 2015, the Company granted restricted stock units (“RSUs”) to certain of its employees.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the results of certain predetermined criteria.  In addition to share-based compensation, the Company may grant to its employees cash-based incentive awards, which are a short-term component of the Plan and are typically based on the Company and the employee achieving certain pre-defined performance criteria.

As of June 30, 2017, there were 14,633,337 shares of common stock available for issuance in satisfaction of awards under the Plan.  The shares available for issuance are reduced when RSUs are settled in shares of common stock, net of withholding tax.  The Company has the option at vesting to settle RSUs in stock or cash, or a combination of stock and cash.  Prior to 2017, only shares of common stock were used to settle vested RSUs.  For the six months ended June 30, 2017, cash was used to settle vested RSUs related to the retirement of an executive officer.  The Company plans to settle RSUs that vest in the future using shares of common stock.  

RSUs currently outstanding related to the 2016 and 2015 grants have been adjusted for performance achieved against predetermined criteria for the applicable performance year.  These RSUs continue to be subject to employment-based criteria and vesting occurs in December of the second year after the grant.  The RSUs related to the 2017 grants are subject to performance-based criteria and employment-based criteria.  See the second table below for potential 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 2017, 2016 and 2015 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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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

A summary of activity related to RSUs during the six months ended June 30, 2017 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2016		6,107,248		$	2.73
Granted		2,080,181			2.77
Vested		(323,870	)		2.73
Forfeited		(268,173	)		2.77
Nonvested, June 30, 2017		7,595,386			2.74

For the outstanding RSUs issued to the eligible employees as of June 30, 2017, vesting is expected to occur as follows:  

	Restricted Stock Units
2017		2,108,397
2018		3,477,267
2019		2,009,722
Total		7,595,386

The fair value of RSUs granted during the six months ended June 30, 2017 was $5.8 million based on the closing price of the Company’s common stock on the date of grant.

Awards to Non-Employee Directors.  Under the Director Compensation Plan, shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during the six months ended June 30, 2017, and the years 2016 and 2015.  As of June 30, 2017, there were 170,524 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced 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 during the six months ended June 30, 2017 is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2016		161,296		$	3.47
Granted		147,372			1.90
Vested		(62,140	)		4.51
Nonvested, June 30, 2017		246,528			2.27

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

For the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2017, vesting is expected to occur as follows:

	Restricted Shares
2018		106,240
2019		91,164
2020		49,124
Total		246,528

The fair value of Restricted Shares granted during the six months ended June 30, 2017 was $0.3 million based on the closing price of the Company’s common stock on the date of grant.

  Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation expense from:
Restricted stock units	$	2,342	$	2,439	$	4,200	$	4,888
Restricted Shares		70		146		140		233
Total	$	2,412	$	2,585	$	4,340	$	5,121
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	844	$	904	$	1,519	$	1,792

Unrecognized Share-Based Compensation.As of June 30, 2017, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $9.7 million and $0.5 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2019 for RSUs and April 2019 for Restricted Shares.

Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees and are typically payable in cash.  These awards are performance-based awards consisting of one or more business or individual performance criteria and a targeted level or levels of performance with respect to each such criterion.  Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.  

During the six months ended June 30, 2017, and the years 2016 and 2015, the Company issued cash-based incentive awards.  In addition to being performance-based awards related to respective 2017, 2016 and 2015 criteria, the payment of such awards is contingent on the Company achieving the following financial condition on or before December 31, 2019, December 31, 2018 and December 31, 2017, respectively:  Adjusted EBITDA less Interest Expense, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $200.0 million for the 2017 awards and exceeds $300.0 million for the 2016 and 2015 awards.  As the Company did not achieve the financial condition for the 2016 and 2015 awards up through June 30, 2017, and we do not estimate the Company will achieve the financial condition within the respective measurement period, no amounts have been recognized to date related to the 2015 and 2016 awards.  For the 2017 awards, amounts were recognized as reported in the table below as it is anticipated the Company will achieve some of the performance-based criteria and will achieve the financial condition within the respective measurement period.      

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation included in:
General and administrative expenses	$	2,412	$	2,585	$	4,340	$	5,121
Cash-based incentive compensation included in:
Lease operating expense		394		—		394		364
General and administrative expenses		1,004		—		1,004		(233	)
Total charged to operating income	$	3,810	$	2,585	$	5,738	$	5,252

7.  Income Taxes

Our income tax benefit for the three and six months ended June 30, 2017 was $9.0 million and $16.6 million, respectively.  Our income tax benefit for the three and six months ended June 30, 2016 was $35.7 million and $40.6 million, respectively.  Our annualized effective tax rate was not meaningful for any period presented.  The income tax benefit for all periods presented relates to net operating loss (“NOL”) 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 six months ended June 30, 2017, we did not pay any income tax or receive any income tax refunds of significance.  During the six months ended June 30, 2016, we made payments of $0.3 million and received $2.3 million of refunds.         

As of June 30, 2017, we recorded current income tax receivables of $12.0 million and non-current income tax receivables of $69.0 million.  As of December 31, 2016, we recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million (in July 2017, we received income tax refunds of $11.9 million).  The current income tax receivables primarily relates to our NOL claim for 2016 carried back to 2006.  The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years and to an estimated NOL claim for 2017 that is expected to be filed subsequent to December 31, 2017.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims related to the years 2012, 2013 and 2014 will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current as these refund claims are expected to be received in the latter part of 2018.

 As of June 30, 2017 and December 31, 2016, our valuation allowance was $270.4 million and $290.2 million, respectively, related to Federal, Louisiana and Alabama NOLs and other deferred 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 NOLs are deductible.  In addition, the realization depends on the ability to carryback certain items to prior years for refunds of taxes previously paid.  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.  

We recognize interest and penalties related to unrecognized tax benefits in income tax expense.  During the six months ended June 30, 2017 and 2016, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

The tax years 2013 through 2016 remain open to examination by the tax jurisdictions to which we are subject.   

19

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

8.  Earnings/ (Loss) Per Share

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
Net income (loss)	$	33,315	$	(120,922	)	$	57,614	$	(311,431	)
Less portion allocated to nonvested shares		1,374		—			2,442		—
Net income (loss) allocated to common shares	$	31,941	$	(120,922	)	$	55,172	$	(311,431	)
Weighted average common shares outstanding		137,552		76,457			137,533		76,443
Basic and diluted earnings (loss) per common share	$	0.23	$	(1.58	)	$	0.40	$	(4.07	)
Shares excluded due to being anti-dilutive (weighted-average)		—		3,531			—		3,529

9.  Contingencies  

Supplemental Bonding Requirements by the BOEM.  The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM issued NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.

• In the first quarter of 2016, we received several orders from the BOEM pursuant to NTL #2008-N07 demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the Interior Board of Land Appeals (the “IBLA”) concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to August 31, 2017.      

• On June 20, 2017, we notified the BOEM that we had satisfied our financial assurance obligations for our sole liability properties as designated by BOEM.  Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  

• Based on our satisfaction of the BOEM demand for our sole liability properties, on June 28, 2017, the BOEM commenced the process necessary to rescind the prior orders issued in 2016 ordering us to provide $260.8 million in financial assurance obligations.

• Since these BOEM orders are the subject of appeals by us before the IBLA, the Office of the Solicitor for the Department of the Interior, on behalf of BOEM, filed motions to remand the four IBLA appeals back to the BOEM.  This will allow the BOEM to rescind the orders.

• As described in Note 10, the motions to remand were granted by the IBLA on July 31, 2017.  

• We are currently in compliance with our financial assurance obligations to the BOEM and, upon rescission of the 2016 orders, we will be under no outstanding BOEM orders related to financial assurance obligations. 

20

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

W&T and other offshore Gulf of Mexico producers may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurances.  

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 six months ended June 30, 2017.

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.  The dispute relates to Apache's use of drilling rigs instead of a previously contracted intervention vessel for the plugging and abandonment work.  We contended that the costs to use the drilling rigs were unnecessary and unreasonable, and that Apache chose to use the rigs without W&T's consent because they otherwise would have been idle at Apache's expense.  We believe the use of the rigs was in bad faith, as found by the jury, and that such conduct caused W&T not to comply with the applicable joint operating agreement, particularly since another vessel had been contracted by Apache for the abandonment a year in advance.  We had previously paid $24.9 million to Apache as an undisputed amount for the plug and abandonment work.

On October 28, 2016, the jury made the following findings:

1. W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells.

2. The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million.

3. The $43.2 million referred to in #2 should be offset by $17.0 million.

4. Apache acted in bad faith thereby causing W&T to not comply with the contract.

A final 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 intend to appeal the trial court judgment in this lawsuit.  In June 2017, in order to stay execution of the judgment, and pending the disposition of post judgment motions, we deposited with the court $49.5 million in escrow.  This amount in escrow is recorded in Other assets (long-term) with a corresponding reduction to Cash and cash equivalents on the Condensed Consolidated Balance Sheet.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) and $43.2 million as capitalized ARO included in Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheet and have recognized $6.3 million of expense included in Other income/expense on the Condensed Statement of Operations.    

Notification by ONRR of Fine for Non-compliance.  In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to approximately $1.1 million) relative to such underpayment.  We filed for a hearing on the matter and a decision was issued by an Administrative Law Judge in June 2017 cancelling the civil penalty in its entirety under the applicable provisions of the Federal Oil and Gas Royalty Management Act.  

21

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

Appeal with 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 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.  After discussing with counsel, we have decided to seek judicial review of the IBLA decision in federal court in New Orleans.

Royalties – “Unbundling” Initiative.  The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas.  In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant.  We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases.  We have submitted revised calculations covering certain plants and time periods to the ONRR.  As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods.  For the six months ended June 30, 2017, we have made additional royalty payments of $1.1 million.  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.  As of June 30, 2017, we had five open civil penalties issued by the Bureau of Safety and Environmental Enforcement (“BSEE”) arising from Incidents of Noncompliance (“INCs”), which have not been settled as of the filing date of this Form 10-Q.  The INC’s underlying the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to March 2016.  The proposed civil penalties for these INCs total $7.5 million and we are appealing these proposed assessments.  During the six months ended June 30, 2017, we made $0.1 million of payments related to civil penalties.  During the six months ended June 30, 2017, we increased the estimated liability by $1.8 million and have accrued approximately $3.3 million as of June 30, 2017, which is our best estimate of the final settlement 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.     

Iberville School Board Lawsuit.In August 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against us (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities. The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  All parties have reached a settlement in principle for this matter.  A motion has been filed with the court seeking approval of the settlement.  The effect of the settlement on the financial statements was immaterial from the previously recorded liability.  

22

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

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

10.  Subsequent Event

On July 31, 2017, the motions to remand were granted by the IBLA concerning the four appeals filed by us related to the four orders issued by the BOEM instructing us to provide $260.8 million in financial assurance obligations.  This will allow the BOEM to rescind the orders, which we anticipate in the ordinary course over the next few weeks.  

11.  Supplemental Guarantor Information

Our payment obligations under the 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 (see Note 2) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Guarantees will 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 applicable indenture);

(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 indenture 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 certain debt documents;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the applicable indenture) or upon satisfaction and discharge of the certain debt documents;

(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 certain debt documents, 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 to the ceiling test write-down recorded in 2016, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company.  Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately.  

23

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

Condensed Consolidating Balance Sheet as of June 30, 2017

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	72,320		$	—		$	—		$	72,320
Receivables:
Oil and natural gas sales		3,268			36,129			—			39,397
Joint interest		19,920			—			—			19,920
Income taxes		119,732			—			(107,705	)		12,027
Total receivables		142,920			36,129			(107,705	)		71,344
Prepaid expenses and other assets		19,480			2,464			—			21,944
Total current assets		234,720			38,593			(107,705	)		165,608
Oil and natural gas properties and other, net		392,445			160,708			(2,472	)		550,681
Restricted deposits for asset retirement obligations		28,712			—			—			28,712
Income tax receivables		68,974			—			—			68,974
Other assets		481,201			418,924			(839,129	)		60,996
Total assets	$	1,206,052		$	618,225		$	(949,306	)	$	874,971
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	51,932		$	6,351		$	—		$	58,283
Undistributed oil and natural gas proceeds		19,626			1,644			—			21,270
Asset retirement obligations		44,776			7,656			—			52,432
Long-term debt		11,147			—			—			11,147
Accrued liabilities		13,122			107,705			(107,705	)		13,122
Total current liabilities		140,603			123,356			(107,705	)		156,254
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		110,604			—			—			110,604
Long term debt, less current portion - carrying value		984,337			—			—			984,337
Asset retirement obligations, less current portion		144,292			121,136			—			265,428
Other liabilities		532,305			—			(465,396	)		66,909
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		543,439			704,885			(704,885	)		543,439
Retained earnings (deficit)		(1,114,758	)		(331,152	)		328,680			(1,117,230	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(595,485	)		373,733			(376,205	)		(597,957	)
Total liabilities and shareholders’ equity (deficit)	$	1,206,052		$	618,225		$	(949,306	)	$	874,971

24

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

Condensed Consolidating Balance Sheet as of December 31, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	70,236		$	—		$	—		$	70,236
Receivables:
Oil and natural gas sales		2,173			40,900			—			43,073
Joint interest		21,885			—			—			21,885
Insurance reimbursement		30,100			—			—			30,100
Income taxes		111,215			—			(99,272	)		11,943
Total receivables		165,373			40,900			(99,272	)		107,001
Prepaid expenses and other assets		12,448			2,056			—			14,504
Total current assets		248,057			42,956			(99,272	)		191,741
Oil and natural gas properties and other, net		360,966			187,040			(953	)		547,053
Restricted deposits for asset retirement obligations		27,371			—			—			27,371
Income tax receivables		52,097			—			—			52,097
Other assets		394,931			344,742			(728,209	)		11,464
Total assets	$	1,083,422		$	574,738		$	(828,434	)	$	829,726
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	74,306		$	6,733		$	—		$	81,039
Undistributed oil and natural gas proceeds		24,493			1,761			—			26,254
Asset retirement obligations		62,261			16,003			—			78,264
Long-term debt		8,272			—			—			8,272
Accrued liabilities		9,293			99,179			(99,272	)		9,200
Total current liabilities		178,625			123,676			(99,272	)		203,029
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		138,722			—			—			138,722
Long term debt, less current portion - carrying value		1,012,455			—			—			1,012,455
Asset retirement obligations, less current portion		142,376			113,798			—			256,174
Other liabilities		408,050			—			(390,945	)		17,105
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		539,973			704,885			(704,885	)		539,973
Retained earnings (deficit)		(1,173,891	)		(367,621	)		366,668			(1,174,844	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ deficit		(658,084	)		337,264			(338,217	)		(659,037	)
Total liabilities and shareholders’ deficit	$	1,083,422		$	574,738		$	(828,434	)	$	829,726

25

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

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

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	57,417		$	65,906	$	—		$	123,323
Operating costs and expenses:
Lease operating expenses		17,325			14,194		—			31,519
Production taxes		449			—		—			449
Gathering and transportation		2,578			2,740		—			5,318
Depreciation, depletion, amortization and accretion		21,433			18,143		788			40,364
General and administrative expenses		7,662			8,812		—			16,474
Derivative gain		(3,689	)		—		—			(3,689	)
Total costs and expenses		45,758			43,889		788			90,435
Operating income		11,659			22,017		(788	)		32,888
Earnings of affiliates		18,941			—		(18,941	)		—
Interest expense incurred		11,436			—		—			11,436
Gain on exchange of debt		8,056			—		—			8,056
Other expense, net		5,168			—		—			5,168
Income before income tax benefit		22,052			22,017		(19,729	)		24,340
Income tax benefit		(12,051	)		3,076		—			(8,975	)
Net income	$	34,103		$	18,941	$	(19,729	)	$	33,315

26

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

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	111,124		$	136,592	$	—		$	247,716
Operating costs and expenses:
Lease operating expenses		41,027			30,656		—			71,683
Production taxes		964			—		—			964
Gathering and transportation		5,144			6,383		—			11,527
Depreciation, depletion, amortization and accretion		40,587			38,248		1,519			80,354
General and administrative expenses		13,438			16,310		—			29,748
Derivative gain		(7,644	)		—		—			(7,644	)
Total costs and expenses		93,516			91,597		1,519			186,632
Operating income		17,608			44,995		(1,519	)		61,084
Earnings of affiliates		36,468			—		(36,468	)		—
Interest expense incurred		22,730			—		—			22,730
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,114			—		—			5,114
Income before income tax benefit		34,043			44,995		(37,987	)		41,051
Income tax benefit		(25,090	)		8,527		—			(16,563	)
Net income	$	59,133		$	36,468	$	(37,987	)	$	57,614

27

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

Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	43,914		$	55,741		$	—		$	99,655
Operating costs and expenses:
Lease operating expenses		19,254			17,368			—			36,622
Production taxes		370			—			—			370
Gathering and transportation		2,469			3,929			—			6,398
Depreciation, depletion, amortization and accretion		22,648			31,934			2,911			57,493
Ceiling test write-down of oil and natural gas    properties		—			35,008			69,584			104,592
General and administrative expenses		7,360			8,875			—			16,235
Derivative loss		4,942			—			—			4,942
Total costs and expenses		57,043			97,114			72,495			226,652
Operating loss		(13,129	)		(41,373	)		(72,495	)		(126,997	)
Loss of affiliates		(40,765	)		—			40,765			—
Interest expense:
Incurred		29,735			38			—			29,773
Capitalized		(64	)		(38	)		—			(102	)
Other expense, net		(24	)		—			—			(24	)
Loss before income tax benefit		(83,541	)		(41,373	)		(31,730	)		(156,644	)
Income tax benefit		(35,114	)		(608	)		—			(35,722	)
Net loss	$	(48,427	)	$	(40,765	)	$	(31,730	)	$	(120,922	)

28

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

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	74,426		$	102,944		$	—		$	177,370
Operating costs and expenses:
Lease operating expenses		44,199			36,892			—			81,091
Production taxes		896			—			—			896
Gathering and transportation		4,022			7,468			—			11,490
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas    properties		—			85,392			135,759			221,151
General and administrative expenses		13,973			18,705			—			32,678
Derivative loss		2,449			—			—			2,449
Total costs and expenses		108,810			218,552			143,619			470,981
Operating loss		(34,384	)		(115,608	)		(143,619	)		(293,611	)
Loss of affiliates		(113,794	)		—			113,794			—
Interest expense:
Incurred		57,430			157			—			57,587
Capitalized		(288	)		(157	)		—			(445	)
Other expense, net		1,282			—			—			1,282
Loss before income tax benefit		(206,602	)		(115,608	)		(29,825	)		(352,035	)
Income tax benefit		(38,790	)		(1,814	)		—			(40,604	)
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)

29

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

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2017

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net income	$	59,133		$	36,468		$	(37,987	)	$	57,614
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		40,587			38,248			1,519			80,354
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		836			—			—			836
Share-based compensation		3,466			—			—			3,466
Derivative gain		(7,644	)		—			—			(7,644	)
Cash receipts on derivative settlements, net		2,208			—			—			2,208
Deferred income taxes		212			—			—			212
Earnings of affiliates		(36,468	)		—			36,468			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(1,095	)		4,770			—			3,675
Joint interest receivables		1,965			—			—			1,965
Insurance reimbursements		30,100			—			—			30,100
Income taxes		(25,487	)		8,527			—			(16,960	)
Prepaid expenses and other assets		(3,165	)		(74,591	)		74,181			(3,575	)
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligation settlements		(25,044	)		(10,977	)		—			(36,021	)
Accounts payable, accrued liabilities and other		81,785			(938	)		(74,181	)		6,666
Net cash provided by operating activities		64,078			1,507			—			65,585
Investing activities:
Investment in oil and natural gas properties and equipment		(41,854	)		(1,946	)		—			(43,800	)
Changes in operating assets and liabilities associated with    investing activities		(1,266	)		439			—			(827	)
Purchases of furniture, fixtures and other		(853	)		—			—			(853	)
Net cash used in investing activities		(43,973	)		(1,507	)		—			(45,480	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(4,113	)		—			—			(4,113	)
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 provided by financing activities		(18,021	)		—			—			(18,021	)
Increase in cash and cash equivalents		2,084			—			—			2,084
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	72,320		$	—		$	—		$	72,320

30

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

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2016

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas properties		—			85,392			135,759			221,151
Debt issuance costs write-off/ amortization of debt items		1,880			—			—			1,880
Share-based compensation		5,121			—			—			5,121
Derivative gain		2,449			—			—			2,449
Cash receipts on derivative settlements		4,746			—			—			4,746
Deferred income taxes		21,099			(1,814	)		—			19,285
Loss of affiliates		113,794			—			(113,794	)		—
Changes in operating assets and liabilities:
Oil and natural gas receivables		1,177			49			—			1,226
Joint interest receivables		1,763			—			—			1,763
Income taxes		(57,931	)		—			—			(57,931	)
Prepaid expenses and other assets		(9,405	)		(17,424	)		16,464			(10,365	)
Asset retirement obligations		(12,702	)		(12,454	)		—			(25,156	)
Accounts payable, accrued liabilities and other		(783	)		32,014			(16,464	)		14,767
Net cash provided by operating activities		(53,333	)		42,064			—			(11,269	)
Investing activities:
Investment in oil and natural gas properties and equipment		(8,600	)		(9,112	)		—			(17,712	)
Changes in operating assets and liabilities associated with    investing activities		(670	)		(33,452	)		—			(34,122	)
Proceeds from sales of assets		1,000			500			—			1,500
Purchases of furniture, fixtures and other		(70	)		—			—			(70	)
Net cash used in investing activities		(8,340	)		(42,064	)		—			(50,404	)
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		340,000			—			—			340,000
Repayments of long-term debt – revolving bank credit facility		(192,000	)		—			—			(192,000	)
Other		83			—			—			83
Net cash provided by financing activities		148,083			—			—			148,083
Increase in cash and cash equivalents		86,410			—			—			86,410
Cash and cash equivalents, beginning of period		85,414			—			—			85,414
Cash and cash equivalents, end of period	$	171,824		$	—		$	—		$	171,824

31

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, 2016 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 acquisitions 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 50 offshore producing fields in federal and state waters.  We currently have under lease approximately 730,000 gross acres, with approximately 480,000 gross acres on the shelf and approximately 250,000 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.  

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the six months ended June 30, 2017 were comprised of 48.0% oil and condensate, 9.3% NGLs and 42.7% 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 Boe for oil, NGLs and natural gas has differed significantly in the past.  For the six months ended June 30, 2017, revenues from the sale of oil and NGLs made up 75.2% of our total revenues compared to 75.9% for the same period in 2016.  For the six months ended June 30, 2017, our combined total production was 1.0% lower than the same period in 2016, with NGLs having the largest decline.  For the six months ended June 30, 2017, our total revenues were 39.7% higher than the same period in 2016 due primarily to significantly higher realized prices for all three of our commodities - oil, NGLs and natural gas.  See Results of Operations – Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016 in this Item for additional information on our revenues and production.

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes due 2019 for new secured notes and common stock.  At the same time, we closed on a new $75.0 million, 1.5 Lien Term Loan and entered into an amendment to our Credit Agreement.  See Financial Statements - Note 2 – Long-Term Debt underPart I, Item 1of this Form 10-Q and Liquidity and Capital Resources in this Item for additional information.

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Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  During the six months ended June 30, 2017, our average realized oil price was $45.76 per barrel.  This is an increase over our average realized oil price of $32.80 for the six months ended June 30, 2016 and an increase over our average realized oil price of $37.35 per barrel for the year 2016.  In addition, average realized prices of NGLs and natural gas for the six months ended June 30, 2017 were higher than average realized prices for the six months ended June 30, 2016 and the year 2016.  

The overall crude oil and other petroleum liquids market remains in an oversupply position.  This is important as excess supplies necessarily limit price increases and could cause future prices to fall until such time as the market becomes more balanced.  

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

For the second quarter of 2017, the U.S. Energy Information Administration (“EIA”) had previously forecast an inventory build.  In its July 2017 report, the EIA now estimates there was an inventory draw in the second quarter of 2017.  For the year 2017, the EIA estimates the worldwide crude oil and petroleum liquids supply will be close to parity with demand in 2017, resulting in crude oil and other petroleum liquids inventories decreasing less than 0.1 million barrels per day.  As this overall decrease is small, it will not allow for a meaningful reduction in the excess inventory supply that continues to exist in the market place.  EIA expects worldwide production to increase by 1.2 million barrels per day in 2017 over 2016 and increase by 1.9 million barrels per day in 2018 over 2017.  The expected increases are primarily in the U.S.  Other countries with expected increases are Canada, Brazil and Kazakhstan.  Production by the Organization of the Petroleum Exporting Countries (“OPEC”) is expected to be fairly flat in 2017.  China and Mexico are expected to experience production declines in 2017.  EIA reports that the OPEC members have agreed to limit their current production and that the agreement was extended to the first quarter of 2018.  For 2018, the anticipated increase in supply is expected to be driven by the U.S. and Iraq.  Consumption is forecast to increase in 2017 by 1.5 million barrels per day in 2017 over 2016, and further increase by 1.6 million barrels per day in 2018 over 2017.  India and China are expected to be the largest contributors to the increased demand for 2017 and 2018.  

According to data provided by EIA, U.S. production of crude oil (excluding other petroleum liquids) increased in the first half of 2017 by 1% compared to the first half of 2016.  EIA’s estimate for 2017 of U.S. crude oil production is an increase of 5% from 2016 and a further increase by 6% in 2018 over 2017.  If EIA’s forecast is achieved in 2018, oil production in the U.S will be at the highest level in recorded history.  As noted below, the number of rigs drilling for oil more than doubled at the end of the first half of 2017 compared to a year ago.  

In addition, it is important to note that geopolitical events could greatly affect the prices for oil, natural gas and other petroleum products.  While these events are difficult to predict, we note the deteriorating political environment in Venezuela could affect approximately 0.7 million barrels per day of crude oil exports to the U.S.  In addition, the political environments in other international areas, such as the Middle East and North Korea, could also affect prices for oil, natural gas and other petroleum products.  

During the first half of 2017, our average realized oil sales price was $45.76, up from $32.80 per barrel (39.5% higher) for the same period in 2016.  The two primary benchmarks are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $49.85 per barrel for the first half of 2017, up from $39.55 per barrel (26.0% higher) for the same period in 2016.  Brent crude oil prices averaged $51.57 per barrel for the first half of 2017, up from $39.80 per barrel (29.6% higher) for the same period in 2016.  The reductions in international crude oil supply and rising U.S. crude oil production put upward price pressure on the premium of Brent to WTI, as the premium increased in the first half of 2017 compared to the first half of 2016.  

Our average realized oil sales price ($45.76 per barrel compared to a WTI benchmark price of $49.85 per barrel) for the first half of 2017 differs from the benchmark crude prices due to premiums or discounts (referred to as differentials), crude quality adjustments, volume weighting and other factors.  All of our oil was 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 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 first half of 2017 were a negative $2.29, a positive $1.77 and a positive $1.32 per barrel, respectively, compared to a negative $3.69, a positive $1.82 and a positive $1.02 per barrel, respectively, for the same period in 2016.  The majority of our crude oil is priced similar to Poseidon and therefore, is experiencing negative differentials.  In addition, a few of our crude oil fields have a negative quality bank adjustment.

33

EIA projects average crude oil prices for WTI and Brent to increase by approximately $5.00 per barrel and $7.00 per barrel, respectively, for the year 2017 compared to 2016.  EIA’s forecast of crude oil prices for both WTI and Brent are relatively flat in 2018 compared to 2017.  Global inventories are forecasted to be relatively unchanged for the second half of 2017 before returning to an average inventory build of 0.2 million barrels per day in 2018.  Per EIA, uncertainty remains regarding the duration of, and adherence to, the current OPEC production cuts, which could influence prices in either direction.  Also, the U.S. tight oil sector continues to be dynamic, and quickly evolving trends in this sector could affect both current prices and the expectations for future prices.  However, lasting upward and downward price movements could be limited over the next year because U.S. tight oil producers have locked in higher production levels at the higher oil prices seen in early 2017.  In addition, the strength in the U.S. dollar relative to other currencies also has an impact on crude pricing.  Because all barrels are traded in U.S. dollars, as the U.S. dollar gains strength, crude prices are lower in U.S. dollars but are more expensive in other currencies.

During the six months ended June 30, 2017, our average realized NGLs sales price increased 46.8% compared to the same period in 2016.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During the six months ended June 30, 2017, average prices for domestic ethane increased 25% and average domestic propane prices increased 53% from the same period in 2016.  Average price changes for other domestic NGLs were an increase of 25% to 51% between the two periods.  We believe the increase in prices for NGLs is mostly a function of the change in oil and natural gas prices.  Per EIA, production of ethane increased by 7% in the six months ended June 30, 2017 over the same period in 2016 and propane production increased by 2% in the six months ended June 30, 2017 over the same period in 2016.  Production continues to exceed demand for ethane, leading to a 31% increase in inventories in the second quarter of 2017 compared to the same period in 2016 and an increase of 11% compared to the first quarter of 2017.  Many natural gas processing facilities have been and, from time to time, will likely continue re-injecting ethane back into the natural gas stream after processing until there is sufficient ethane demand.  This practice of re-injecting ethane negatively impacts production and natural gas prices.  Ethane usage is not impacted by weather, but primarily by demand from petrochemical plants.  Ethane demand is expected to increase in 2017 over 2016 as two new petrochemical plants came on line in the first half of 2017 and five more are expected to be operational by the end of 2018.  On the other hand, 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 lower coming out of the winter season and are 29% lower than the comparable period in 2016 even with the winter of 2016-2017 being unseasonably warm compared to the ten-year average.  

During the six months ended June 30, 2017, our average realized natural gas sales price increased 46.3% compared to the same period in 2016.  According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 47.1% higher in the six months ended June 30, 2017 from the same period in 2016.  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.  Average spot prices in the first half of 2017 were similar to levels in the fourth quarter of 2016.  During the 2016-2017 winter season, inventory drawdowns were higher than the prior year period due to lower production and higher exports, partially offset by lower consumption.  Inventories at the end of the first half of 2017 were 9% lower than the prior year period, but were above the five-year average by 9%.  The narrowing of inventory levels is reflected in EIA’s forecast of rising natural gas prices discussed below.  U.S. consumption was lower in the first half of 2017 compared to the same period in 2016, primarily due to decreases in natural gas used for electrical power generation.

The average price of natural gas continues to be weak from an overall economic standpoint, and we expect 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 (iv) higher inventory levels and (v) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply.

34

EIA projects natural gas prices to increase in 2017 compared to 2016 by 23% and to be basically flat in 2018 compared to 2017.  U.S. supply is projected to be approximately equal to consumption in 2017 and 2018.  As a result, excess inventory is not expected to be drawn down, which limits any significant upward price movement.  During 2016, natural gas overtook coal as being the largest fuel source for electrical power generation, supplying 34% of the megawatts generated compared to 30% from coal.  EIA’s forecast of fuel used for electrical power generation has natural gas declining in 2017 to 31% and being approximately equal with coal.  Electrical power from hydropower is expected to increase in 2017 to 17% compare to 15% in 2016.  For 2018, electrical power from natural gas is expected to increase to 32%, with coal and hydropower being relatively unchanged from 2017 levels.  

During the six months ended June 30, 2017, the number of working rigs drilling for oil and natural gas in the U.S. was significantly above year ago levels for land based rigs, and slightly higher for offshore rigs.  According to Baker Hughes, the oil rig count at June 2016, December 2016 and June 2017 was 341, 525 and 756 (a 122% increase from year ago levels), respectively.  The U.S. natural gas rig count at June 2016, December 2016 and June 2017 was 89, 132 and 184, respectively. In the Gulf of Mexico, the number of working rigs was 18 rigs (15 oil and three natural gas) at June 2016; 22 rigs (22 oil and no natural gas) at December 2016; and 21 rigs (18 oil and three natural gas) at June 30 2017.  The majority of working rigs in the Gulf of Mexico are currently “floaters” with very few jack-up rigs working.

As required by the full cost accounting rules, we perform our ceiling test calculation each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials.  The average price using the SEC required methodology at June 30, 2017 was $45.42 per barrel for WTI crude oil and $3.01 per MMBtu for Henry Hub natural gas before adjustments.  For the six months ended June 30, 2017, we did not have a ceiling test write-down.  For the six months ended June 30, 2016, we recorded a ceiling test write-down of the carrying value of our oil and natural gas properties of $221.2 million due primarily to lower prices for crude oil and natural gas.  Incurrence of write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs.  Using prices, reserve balances and other information available as of the filing date of this Form 10-Q, we do not anticipate a ceiling test write down in the third quarter of 2017.  

During the first half of 2017, the BOEM issued notices that provide for an extension for both “sole-liability” and “non-sole liability” properties related to the implementation of NTL #2016-01, which includes financial assurances related to asset retirement obligations for leases, ROWs and RUEs.  A revised effective implementation date has not yet been issued by the BOEM.  We are currently in compliance with our financial assurance obligations.  The BOEM has indicated that once certain procedural motions have been granted by the IBLA, it will rescind the orders issued in the first quarter of 2016 totaling $260.8 million for financial assurance.  Upon rescission of the 2016 orders, we will be under no outstanding BOEM orders related to financial assurances.  We and other offshore Gulf of Mexico producers may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurances.  These matters are more fully discussed in Financial Statements - Note 9 – Contingencies and Note 10 – Subsequent Events under Part I, Item 1 of this Form 10-Q. 

Our current 2017 capital expenditure budget remains unchanged at $125.0 million, which is above the capital expenditures incurred in 2016 of $48.6 million, but reduced from investment levels in 2015 and 2014 of $231.4 million and $630.0 million, respectively.  Because of the level of commodity prices and the outlook for the remainder of the 2017, we believe this capital expenditure level should enable us to maintain production in 2017 comparable to 2016, while allowing for adequate cash balances and leaving our revolving bank credit facility undrawn (assuming current commodity price and cost levels).  While the remaining 2017 capital projects are expected to impact 2017 production to some degree, the bulk of the impact on production is expected to be in 2018 and beyond.  We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments.  

With respect to our costs, we have realized reductions in our lease operating expenses and general and administrative expenses as a result of our cost reduction programs, which included headcount and contractor usage reductions, combined with reduced rates from vendors for supplies, equipment and contract labor.  These cost reduction programs and reduced supplier rates have also lowered capital expenditures, ARO settlements and ARO estimates.  

35

Our short term focus is on liquidity, cost reductions, fulfilling our obligations and making investments with short payback time frames.  In light of our somewhat limited access to capital and liquidity, we are continually assessing our plans.  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, 2016, Item 1A, Risk Factors, for additional information.  

36

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												Six Months Ended
	June 30,												June 30,
	2017			2016			Change			%			2017			2016			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	85,622		$	71,751		$	13,871			19.3	%	$	170,593		$	122,687		$	47,906			39.0	%
NGLs		7,054			7,018			36			0.5	%		15,796			12,013			3,783			31.5	%
Natural gas		29,258			19,833			9,425			47.5	%		59,016			40,103			18,913			47.2	%
Other		1,389			1,053			336			31.9	%		2,311			2,567			(256	)		(10.0	)%
Total revenues		123,323			99,655			23,668			23.7	%		247,716			177,370			70,346			39.7	%
Operating costs and expenses:
Lease operating expenses		31,519			36,622			(5,103	)		(13.9	)%		71,683			81,091			(9,408	)		(11.6	)%
Production taxes		449			370			79			21.4	%		964			896			68			7.6	%
Gathering and transportation		5,318			6,398			(1,080	)		(16.9	)%		11,527			11,490			37			0.3	%
Depreciation, depletion, amortization    and accretion		40,364			57,493			(17,129	)		(29.8	)%		80,354			121,226			(40,872	)		(33.7	)%
Ceiling test write-down of oil and    natural gas properties		—			104,592			(104,592	)		(100.0	)%		—			221,151			(221,151	)		(100.0	)%
General and administrative expenses		16,474			16,235			239			1.5	%		29,748			32,678			(2,930	)		(9.0	)%
Derivative (gain) loss		(3,689	)		4,942			(8,631	)	NM				(7,644	)		2,449			(10,093	)	NM
Total costs and expenses		90,435			226,652			(136,217	)		(60.1	)%		186,632			470,981			(284,349	)		(60.4	)%
Operating income (loss)		32,888			(126,997	)		159,885		NM				61,084			(293,611	)		354,695		NM
Interest expense, net of amounts    capitalized		11,436			29,671			(18,235	)		(61.5	)%		22,730			57,142			(34,412	)		(60.2	)%
Gain on exchange of debt		8,056			—			8,056		NM				7,811			—			7,811		NM
Other (income) expense, net		5,168			(24	)		5,192		NM				5,114			1,282			3,832		NM
Income (loss) before income tax benefit		24,340			(156,644	)		180,984		NM				41,051			(352,035	)		393,086		NM
Income tax benefit		(8,975	)		(35,722	)		26,747		NM				(16,563	)		(40,604	)		24,041		NM
Net income (loss)	$	33,315		$	(120,922	)	$	154,237		NM			$	57,614		$	(311,431	)	$	369,045		NM
Basic and diluted earnings (loss)    per common share	$	0.23		$	(1.58	)	$	1.81		NM			$	0.40		$	(4.07	)	$	4.47		NM

NM – not meaningful

37

	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2017		2016		Change			% (2)			2017		2016		Change			% (2)
Operating: (1)
Net sales:
Oil (MBbls)		1,923		1,835		88			4.8	%		3,728		3,740		(12	)		(0.3	)%
NGLs (MBbls)		351		451		(100	)		(22.2	)%		725		809		(84	)		(10.4	)%
Natural gas (MMcf)		9,890		9,690		200			2.1	%		19,875		19,761		114			0.6	%
Total oil equivalent (MBoe)		3,921		3,901		20			0.5	%		7,765		7,843		(78	)		(1.0	)%
Total natural gas equivalents (MMcfe)		23,524		23,404		120			0.5	%		46,589		47,055		(466	)		(1.0	)%
Average daily equivalent sales (Boe/day)		43,084		42,864		220			0.5	%		42,899		43,091		(192	)		(0.4	)%
Average daily equivalent sales (Mcfe/day)		258,503		257,186		1,317			0.5	%		257,395		258,544		(1,149	)		(0.4	)%
Average realized sales prices:
Oil ($/Bbl)	$	44.54	$	39.11	$	5.43			13.9	%	$	45.76	$	32.80	$	12.96			39.5	%
NGLs ($/Bbl)		20.15		15.56		4.59			29.5	%		21.80		14.85		6.95			46.8	%
Natural gas ($/Mcf)		2.96		2.05		0.91			44.4	%		2.97		2.03		0.94			46.3	%
Oil equivalent ($/Boe)		31.10		25.28		5.82			23.0	%		31.61		22.29		9.32			41.8	%
Natural gas equivalent ($/Mcfe)		5.18		4.21		0.97			23.0	%		5.27		3.71		1.56			42.0	%
Average per Boe ($/Boe):
Lease operating expenses	$	8.04	$	9.39	$	(1.35	)		(14.4	)%	$	9.23	$	10.34	$	(1.11	)		(10.7	)%
Gathering and transportation		1.36		1.64		(0.28	)		(17.1	)%		1.48		1.47		0.01			0.7	%
Production costs		9.40		11.03		(1.63	)		(14.8	)%		10.71		11.81		(1.10	)		(9.3	)%
Production taxes		0.11		0.09		0.02			22.2	%		0.12		0.11		0.01			9.1	%
DD&A		10.29		14.74		(4.45	)		(30.2	)%		10.35		15.46		(5.11	)		(33.1	)%
General and administrative expenses		4.20		4.16		0.04			1.0	%		3.83		4.17		(0.34	)		(8.2	)%
	$	24.00	$	30.02	$	(6.02	)		(20.1	)%	$	25.01	$	31.55	$	(6.54	)		(20.7	)%
Average per Mcfe ($/Mcfe):
Lease operating expenses	$	1.34	$	1.56	$	(0.22	)		(14.1	)%	$	1.54	$	1.72	$	(0.18	)		(10.5	)%
Gathering and transportation		0.23		0.27		(0.04	)		(14.8	)%		0.25		0.24		0.01			4.2	%
Production costs		1.57		1.83		(0.26	)		(14.2	)%		1.79		1.96		(0.17	)		(8.7	)%
Production taxes		0.02		0.02		—			—			0.02		0.02		—			—
DD&A		1.72		2.46		(0.74	)		(30.1	)%		1.72		2.58		(0.86	)		(33.3	)%
General and administrative expenses		0.70		0.69		0.01			1.4	%		0.64		0.69		(0.05	)		(7.2	)%
	$	4.01	$	5.00	$	(0.99	)		(19.8	)%	$	4.17	$	5.25	$	(1.08	)		(20.6	)%

(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 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

38

Completed Wells

During the six months ended June 30, 2017, we completed three offshore wells and during the six months ended June 30, 2016, we completed one offshore well.  All four wells were productive.  

Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016

Revenues.  Total revenues increased $23.7 million, or 23.7%, to $123.3 million for the second quarter of 2017 as compared to the second quarter of 2016.  Oil revenues increased $13.9 million, or 19.3%, NGLs revenues were flat, natural gas revenues increased $9.4 million, or 47.5% and other revenues increased $0.3 million.  The increase in oil revenues was attributable to a 13.9% increase in the average realized sales price to $44.54 per barrel for the second quarter of 2017 from $39.11 per barrel for the second quarter of 2016, combined with an increase of sales volumes of 4.8%.  NGLs revenue were relatively unchanged, as the average realized sales price increased by 29.5% to $20.15 per barrel for the second quarter of 2017 from $15.56 per barrel for the second quarter of 2016, and was offset by a sales volumes decrease of 22.2%.  The increase in natural gas revenues resulted from a 44.4% increase in the average realized natural gas sales price to $2.96 per Mcf for the second quarter of 2017 from $2.05 per Mcf for the second quarter of 2016, combined with an increase of 2.1% in sales volumes.  Overall, production was relatively flat, increasing by 0.5% on a MBoe basis.  The largest production increases for the second quarter of 2017 compared to the second quarter of 2016 were at the Ship Shoal 349 (“Mahogany”), Garden Banks 302 (“Powerplay”) and Viosco Knoll 783 “(Tahoe/SE Tahoe”) fields.  In addition, we received royalty relief for a portion of 2016 crude oil royalties related to the Mississippi Canyon 698 (“Big Bend”) field, which increased oil revenues by $4.1 million and oil sales volumes by approximately 115,000 barrels.  Offsetting were production decreases primarily due to natural production declines.  

Revenues from oil and liquids as a percent of our total revenues were 75.1% for the second quarter of 2017 compared to 79.0% for the second quarter of 2016.  Our average realized NGLs sales price as a percent of our average realized oil sales price increased to 45.2% for the second quarter of 2017 compared to 39.8% for the second quarter of 2016.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $5.1 million, or 13.9%, to $31.5 million in the second quarter 2017 compared to the second quarter of 2016.  On a per Boe basis, lease operating expenses decreased to $8.04 per Boe during the second quarter of 2017 compared to $9.39 per Boe during the second quarter of 2016.  On a component basis, base lease operating expenses decreased $4.0 million, insurance premiums decreased $1.2 million and facilities maintenance expense decreased $0.8 million, partially offset by increases in workover expenses of $0.9 million.  Base lease operating expenses decreased primarily due to continued cost reduction efforts by the Company, cost reductions at non-operated properties and from increased product handling fees (credits to costs).  Insurance premium reductions are primarily due to revisions in our insurance policies related to named windstorms.  The facility maintenance expense decrease is primarily due to reimbursement of repairs to a pipeline we own, which was damaged by a third-party.  The increase in workover costs was primarily due to well work at the Mahogany field.

Production taxes.  Production taxes increased less than $0.1 million for the second quarter of 2017 compared to the second quarter of 2016.  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 decreased $1.1 million to $5.3 million for the second quarter of 2017 compared to the second quarter of 2016 primarily due to decreases at our Brazos A133 field.  

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, decreased to $10.29 per Boe for the second quarter of 2017 from $14.74 per Boe for the second quarter of 2016.  On a nominal basis, DD&A decreased to $40.4 million, (29.8%), for the second quarter of 2017 from $57.5 million for the second quarter of 2016.  DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2016 and lower capital expenditures in relation to DD&A expense during 2016 and 2017, which lowers the full-cost pool subject to DD&A.  Other factors affecting the DD&A rate are changes in future development costs on remaining reserves and an increase in proved reserves volumes.    

39

Ceiling test write-downof oil and natural gas properties. For the second quarter of 2017, we did not have a ceiling test write-down of the carrying value of our oil and gas properties.  For the second quarter of 2016, we recorded a non-cash ceiling test write-down of $104.6 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down was primarily the result of lower prices on all commodities for our proved reserves.  See our Annual Report on Form 10-K for the year ended December 31, 2016, Item 8, Financial Statements and Supplementary Data for additional information on the ceiling test.  

General and administrative expenses (“G&A”).  G&A was $16.5 million for the second quarter of 2017, up 1.5% from the $16.2 million for the second quarter of 2016.  During the second quarter of 2017, we experienced increases in accrued civil penalties from the BSEE (which we are appealing to the IBLA), surety bond costs and incentive compensation programs, partially offset by lower salary expense, legal expenses and professional fees.  G&A on a per Boe basis was $4.20 per Boe for the second quarter of 2017 compared to $4.16 per Boe for the second quarter of 2016.

Derivative (gain) loss. For the second quarter of 2017, there was a $3.7 million derivative gain recorded for both crude oil and natural gas derivative contracts, which includes settled contracts and open contracts recorded at fair value as of June 30, 2017.  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.  For the second quarter of 2016, there was a $4.9 million derivative loss recorded for derivative contracts for crude oil and natural gas.  

Interest expense.  Interest expense, net of amounts capitalized, was $11.4 million in the second quarter of 2017, decreasing 61.5% from the $29.7 million for the second quarter of 2016.  The decrease was primarily attributable to the Exchange Transaction that was completed on September 7, 2016, when we exchanged $710.2 million of our Unsecured Senior Notes for $301.8 million of new secured notes and 60.4 million shares of common stock, and at the same time, closed on a new $75.0 million secured loan.  The Exchange Transaction and the related accounting are more fully described in the Liquidity and Capital Resource section below.  In addition, interest expense was lower as we had no borrowings on the revolving bank credit facility during the second quarter of 2017 compared to borrowings averaging over $250 million during the second quarter of 2016.

Gain on exchange of debt.  During the second quarter of 2017, an additional net gain of $8.1 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 the 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 Exchange Transaction for differences between estimated and actual expense.  

Other (income) expense, net.  During the second quarter of 2017, other (income) expense, net, was $5.2 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 9 – Contingencies under Part I, Item 1 of this Form 10-Q for additional information on the Apache lawsuit.    

Income tax benefit.Our income tax benefit for the second quarter of 2017 and 2016 was $9.0 million and $35.7 million, respectively.  Our annualized effective tax rate using book pre-tax income was not meaningful for either period.  The income tax benefit for both periods relates to NOL carryback claims made pursuant to 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.  For both periods, adjustments in the valuation allowance offset changes in net deferred tax assets.  See Financial Statements – Note 7 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

40

Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

Revenues.  Total revenues increased $70.3 million, or 39.7%, to $247.7 million for the first half of 2017 as compared to the first half of 2016.  Oil revenues increased $47.9 million, or 39.0%, NGLs revenues increased $3.8 million, or 31.5%, natural gas revenues increased $18.9 million, or 47.2% and other revenues decreased $0.3 million.  The increase in oil revenues was attributable to a 39.5% increase in the average realized sales price to $45.76 per barrel for the first half of 2017 from $32.80 per barrel for the first half of 2016 and sales volumes were virtually unchanged.  The increase in NGLs revenues was attributable to a 46.8% increase in the average realized sales price to $21.80 per barrel for the first half of 2017 from $14.85 per barrel for the first half of 2016, partially offset by a decrease in sales volumes by 10.4%.  The increase in natural gas revenues resulted from a 46.3% increase in the average realized natural gas sales price to $2.97 per Mcf for the first half of 2017 from $2.03 per Mcf for the first half of 2016 and sales volumes increased marginally.  Overall, production declined 1.0% on an MBoe basis.  The largest production increases for the first half of 2017 compared to the first half of 2016 were at the Mahogany, Ewing Bank 910, Viosco Knoll 823 (“Virgo”), Powerplay, East Cameron 321, and Main Pass 108 fields.  In addition, we received royalty relief for a portion of 2016 crude oil royalties and all 2016 natural gas royalties related to the Mississippi Canyon 698 (“Big Bend”) and Mississippi Canyon 782 (“Dantzler”) fields, which increased revenues by $5.0 million and sales volumes by approximately 175,000 MBoe.  Offsetting were production decreases primarily due to natural production declines.  

Revenues from oil and liquids as a percent of our total revenues were 75.2% for the first half of 2017 compared to 75.9% for the first half of 2016.  Our average realized NGLs sales price as a percent of our average realized oil sales price increased to 47.6% for the first half of 2017 compared to 45.3% for the first half of 2016.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $9.4 million, or 11.6%, to $71.7 million in the first half 2017 compared to the first half of 2016.  On a per Boe basis, lease operating expenses decreased to $9.23 per Boe during the first half of 2017 compared to $10.34 per Boe during the first half of 2016.  On a component basis, base lease operating expenses decreased $8.7 million, insurance premiums decreased $3.7 million and facilities maintenance expense decreased of $0.6 million, partially offset by increases in workover expenses of $3.6 million.  Base lease operating expenses decreased primarily due to continued cost reduction efforts by the Company, cost reductions at non-operated properties and from increased product handling fees (credits to costs).  Insurance premium reductions are primarily due to revisions in our insurance policies related to named windstorms.  The increase in workover costs was primarily due to increases for well work at the Mahogany field.

Production taxes.  Production taxes increased less than $0.1 million for the first half of 2017 compared to the first half of 2016.  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 were basically flat for the first half of 2017 compared to the first half of 2016.  

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, decreased to $10.35 per Boe for the first half of 2017 from $15.46 per Boe for the first half of 2016.  On a nominal basis, DD&A decreased to $80.4 million, (33.7%), for the first half of 2017 from $121.2 million for the first half of 2016.  DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2016 and lower capital expenditures in relation to DD&A expense during 2016 and 2017, which lowers the full-cost pool subject to DD&A.  Other factors affecting the DD&A rate are changes in future development costs on remaining reserves and an increase in proved reserves volumes.    

Ceiling test write-downof oil and natural gas properties. For the first half of 2017, we did not have a ceiling test write-down of the carrying value of our oil and gas properties.  For the first half of 2016, we recorded a non-cash ceiling test write-down of $221.2 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down was primarily the result of lower prices on all commodities for our proved reserves.  See our Annual Report on Form 10-K for the year ended December 31, 2016, Item 8, Financial Statements and Supplementary Data for additional information on the ceiling test.  

41

General and administrative expenses.  G&A was $29.7 million for the first half of 2017, decreasing 9.0% from $32.7 million for the first half of 2016.  During the first half of 2017, we experienced reductions in legal expense, salary expense and benefits costs, partially offset by increases in accrued civil penalties from the BSEE (which we are appealing to the IBLA) and surety bond costs.  G&A on a per BOE basis was $3.83 per Boe for the first half of 2017 compared to $4.17 per Boe for the first half of 2016.

Derivative (gain) loss. For the first half of 2017, there was a $7.6 million derivative gain recorded for both crude oil and natural gas derivative contracts, which includes settled contracts and open contracts recorded at fair value as of June 30, 2017.  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.  For the first half of 2016, there was a $2.4 million derivative loss recorded for derivative contracts for crude oil and natural gas.  

Interest expense.  Interest expense, net of amounts capitalized, was $22.7 million in the first half of 2017, decreasing 60.2% from the $57.1 million for the first half of 2016.  The decrease was primarily attributable to the Exchange Transaction that was completed on September 7, 2016, when we exchanged $710.2 million of our Unsecured Senior Notes for $301.8 million of new secured notes and 60.4 million shares of common stock, and at the same time, closed on a new $75.0 million secured loan.  The Exchange Transaction and the related accounting are more fully described in the Liquidity and Capital Resource section below.  In addition, interest expense was lower as we had no borrowings on the revolving bank credit facility during the first half of 2017 compared to borrowings averaging approximately $200 million during the first half of 2016.

Gain on exchange of debt.  During the first half of 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 Exchange Transaction for differences between estimated and actual expense.  

Other income (expense), net.  During the first half of 2017 and 2016, other (income) expense, net, was $5.1 million of net expense and $1.3 million of net expense, respectively.  For the first half of 2017, the amount 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 9 – Contingencies under Part I, Item 1 of this Form 10-Q for additional information on the Apache lawsuit.  For the first half of 2016, the amount was primarily due to write-down of debt issuance costs related to a reduction in the borrowing base of the revolving bank credit facility.  

Income tax benefit.Our income tax benefit for the first half of 2017 and 2016 was $16.6 million and $40.6 million, respectively.  Our annualized effective tax rate using book pre-tax income was not meaningful for either period.  The income tax benefit for both periods relates to NOL carryback claims made pursuant to 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.  For both periods, adjustments in the valuation allowance offset changes in net deferred tax assets.  See Financial Statements – Note 7 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

42

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 demands for additional financial assurances from the BOEM.  If such events were to occur in the future, we may seek relief under the U.S. Bankruptcy Code, which relief may include (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Additionally, a prolonged period of weak commodity prices could have other potential negative impacts including:

• recognizing additional ceiling test write-downs of the carrying value of our oil and gas properties;

• reductions in our proved reserves and the estimated value thereof;

• additional supplemental bonding and potential collateral requirements;

• further reductions in our borrowing base under the Credit Agreement; and

• our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs described above.

During 2016, we engaged legal and financial advisors to assist the Board of Directors and our management team to evaluate the various alternatives available to us and executed the transaction described below:

Exchange Transaction.On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes, due June 15, 2019 for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Second Lien PIK Toggle Notes, due May 15, 2020; (ii) $142.0 million in aggregate principal of 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021; and (iii) 60.4 million shares of our common stock.  

At the same time on closing on the Debt Exchange described above, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the largest holder of our Unsecured Senior Notes.  We accounted for the Exchange Transaction as a Troubled Debt Restructuring under ASC 470-60.  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Condensed Consolidated Statements of Operations during the six months ended June 30, 2017.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.  Under ASC 470-60, payments related to the New Debt are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.

For the six month period ending June 30, 2017, we paid the interest payment for the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes in cash rather than in kind.  These cash payments and the cash payments related to the 1.5 Lien Term Loan are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.  In addition, the cash interest payments on the Second Lien PIK Toggle 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 for the three and six month period ended June 30, 2017.    

For the Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan, the maturity of both will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes are not extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  A total of $239.5 million would become due on February 28, 2019 if acceleration were to occur.    

43

Credit Agreement.  Availability on our revolving bank credit facility as of June 30, 2017 was $149.7 million.  At June 30, 2017 and December 31, 2016, no amounts were outstanding and letters of credit were minimal.  During the six months ended June 30, 2017, no borrowings were made on the revolving bank credit facility.

Availability under our revolving bank credit facility 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 2017 spring redetermination reaffirmed the borrowing base amount at $150.0 million.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.    The revolving bank credit facility is secured and is collateralized by substantially all of our oil and natural gas properties.  

The 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 Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement and the other debt instruments as of June 30, 2017.

Long-Term Debt.  The recorded amounts of our long-term debt and the primary terms are disclosed in Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.  

BOEM Matters.  During the first half of 2017, the BOEM issued notices that provide for an extension for both “sole-liability” and “non-sole liability” properties related to the implementation of NTL #2016-01, which includes financial assurances related to asset retirement obligations for leases, ROWs and RUEs.  A revised effective implementation date has not yet been issued by the BOEM.  We are currently in compliance with our financial assurance obligations.  The BOEM has indicated that once certain procedural motions have been granted by the IBLA, it will rescind the orders issued in the first quarter of 2016 totaling $260.8 million for financial assurance.  Upon rescission of the 2016 orders, we will be under no outstanding BOEM orders related to financial assurances.  These matters are more fully discussed in Financial Statements - Note 9 – Contingencies under Part I, Item 1 of this Form 10-Q. 

Surety Bond Collateral.  Some of the sureties under our existing supplemental surety bonds have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could 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.

The issuance of any additional surety bonds or other security to satisfy the BOEM orders, any 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 the creation of escrow accounts.  

Cash Flow and Working Capital.  Net cash provided by operating activities for the six months ended June 30, 2017 was $65.6 million and net cash used by operating activities for the six months ended June 30, 2016 was $11.3 million.  Cash flows from operating activities, before changes in working capital, insurance reimbursements, escrow deposits and ARO, were $112.3 million for the six months ended June 30, 2017, compared to $6.5 million in the comparable period.  The increase in cash flows was primarily due to higher realized prices for all our commodities - oil, NGLs and natural gas, lower operating costs and lower interest payments.  Our combined average realized sales price per Boe increased 41.8% in the first half of 2017, which caused total revenues to increase $70.3 million.  Lease operating expenses decreased $9.4 million, G&A expenses decreased $2.9 million and interest expense, net of amounts capitalized, (the portion of interest that is including in net cash provided by operating activities) decreased $34.4 million.  (Interest related to the New Debt is reported within cash flows from financing activities under ASC 470-60).    

Other items affecting operating cash flows for the six months ended June 30, 2017 were ARO settlements of $36.0 million and the escrow payment related to the Apache lawsuit of $49.5 million, partially offset by insurance reimbursements of $30.1 million and changes in receivables, accounts payable and accrued liabilities of $12.3 million.  

44

Net cash used in investing activities during the six months ended June 30, 2017and 2016 was $45.5 million and $50.4 million, respectively, which represents our investments in oil and gas properties and equipment.  There were no acquisitions of properties during either period.  Investments in oil and natural gas properties on an accrual basis in the six months ended June 30, 2017were $43.8 million compared to $17.7 million for the same period in 2016.  The capital expenditures during the six months ended June 30, 2017 related primarily to investments on the conventional shelf.  In addition, adjustments from working capital changes associated with investing activities was a net cash usage of $0.8 million in the six months ended June 30, 2017 compared to net cash usage of $34.1 million for the same period in 2016.  These amounts represent timing differences between when the work was performed and the payment made.  During the six months ended June 30, 2016, assets sales were $1.5 million.      

Net cash used by financing activities for the six months ended June 30, 2017 was $18.0 million and net cash provided by financing activities for the six months ended June 30, 2016 was $148.1 million.  The net cash used for the six months ended June 30, 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 a financing activities under ASC 470-60.  The net cash provided for the six months ended June 30, 2016 was attributable to the net borrowings on the revolving bank credit facility.  

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 revolving bank credit facility.  As of June 30, 2017, we had outstanding open derivatives for crude oil and natural gas.  These derivatives provide downside protection against a portion of our remaining 2017 production.  The oil swap contract provides cash inflows when the oil price is below $55.25.  The “two-way collar” contracts will provide cash inflows when crude oil or natural gas prices average are below $50.00 per barrel and $3.07 per MMBtu, respectively, in a month.  Conversely, these contracts may require cash payments and limit upside potential if prices exceed certain amounts.  See Financial Statements - Note 5 - Derivative Financial Instruments 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 $150.0 million aggregate limit covering all of our properties, subject to a retention (deductible) of $30.0 million.  We carry $150.0 million for a total loss only (“TLO”) on our Mahogany platform.  The operational and named windstorm coverages are effective until June 1, 2018.  Coverage for pollution causing a negative environmental impact is provided under the well control and other section within the policy.

Our general and excess liability policies are effective until 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, 2017, and our Energy Package effective on June 1, 2017, 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.  However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims.  We do not carry business interruption insurance.

45

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 oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  The following table presents our capital expenditures on an accrual basis for exploration, development and other leasehold costs and acquisitions:

	Six Months Ended
	June 30,
	2017			2016
	(In thousands)
Exploration (1)	$	(401	)	$	2,108
Development (1)		42,440			13,765
Seismic, capitalized interest, and other		1,761			1,839
Investments in oil and gas property/equipment	$	43,800		$	17,712

(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:

	Six Months Ended
	June 30,
	2017		2016
	(In thousands)
Conventional shelf	$	41,032	$	7,466
Deepwater		1,007		8,514
Deep shelf		—		(107	)
Exploration and development capital expenditures	$	42,039	$	15,873

Our capital expenditures for the six months ended June 30, 2017 were financed by cash flow from operations and cash on hand.  

The following table presents our offshore wells drilled based on a completed basis:

	Six Months Ended June 30,
	2017				2016
	Gross		Net		Gross		Net
Development wells -  Productive		3		3.0		—		—
Exploration wells -    Productive		—		—		1		0.5
Total wells		3		3.0		1		0.5

All wells in the above table were successful.  

Exploration/Development Activities.  During the first quarter of 2017, the A-18 well at Mahogany was completed and began producing in January 2017.  At March 31, 2017, the A-16 BP1 well at Mahogany was completed and began producing in April 2017.  In June 2017, the A-8 well at Mahogany was completed and began producing in July 2017.    

Divestitures.  Periodically, we sell properties as part of the management of our property portfolio.  During the six months ended June 30, 2017, we did not have any property sales.

46

Capital Expenditure Budget and Expected Production for 2017.With consideration of the current commodity price environment and the outlook for the remainder of 2017, our 2017 capital expenditure budget remains unchanged at $125.0 million, which excludes potential acquisitions.  Although this is an increase from the $48.6 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231.4 million and $630.0 million, respectively.  We have some flexibility for the remaining 2017 capital expenditure budget, although we have contracted, or are in the process of contracting, rigs for the drilling program in the second half of 2017.  Our 2017 production is expected to be positively impacted by the Ewing Bank 910 A-8 well, which began producing during March 2016 and had a workover performed in October 2016, the Mahogany A-18 well, which began producing in January 2017, the Mahogany A-16 BP1 well, which began producing in April 2017, and the Mahogany A-8 well, which began producing in July 2017.  For the expenditures planned for the remainder of 2017, these may impact production for 2017 to some degree, but most of the production impact is expected in 2018 and beyond.  We expect 2017 production volumes to approximate 2016, but factors such as natural production declines, unplanned downtime and well performance could lead to lower production in 2017.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.

Income Taxes.  As of June 30, 2017, we recorded current income tax receivables of $12.0 million and non-current income tax receivables of $69.0 million.  The current income tax receivables relates primarily to an NOL claim for 2016 carried back to 2006.  During the six months ended June 30, 2017, we did not make any income tax payments or receive any refunds of significance, but in July 2017, we received $11.9 million of income tax refunds.  The non-current income taxes receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years and to an estimated NOL claim for 2017 that is expected to be filed subsequent to December 31, 2017.  The non-current income tax receivables are expected to be received in the latter part of 2018.  These receivables relate to claims made pursuant to IRC Section 172(f), (related to rules for “specified liability losses”) which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  See Financial Statements – Note 7 –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 June 30, 2017 and December 31, 2016 were $317.9 million and $334.4 million, respectively.  Our plans include spending $82.8 million in 2017 for ARO compared to $72.3 million spent on ARO in 2016.  As our ARO are estimates for work to be performed in the future, and in the case of our non-current ARO, are for 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, 2016 for additional information.    

Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-TermandNote 4 – Asset Retirement Obligation, and under Part I, Item 1 of this Form 10-Q.  As of June 30, 2017, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $6.7 million compared to $4.4 million as of December 31, 2016.  Except for scheduled utilization, other contractual obligations as of June 30, 2017 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, 2016.

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, 2016.  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.  

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the six months ended June 30, 2017 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, 2016.  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, 2016.  

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely.  Oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability and could have further impact on our business in the future.  As of June 30, 2017, we had open derivative contracts related to a portion of our estimated production for the remainder of 2017.  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 oil and natural gas prices, but they also may limit future income from favorable price movements.  See Financial Statements - Note 5 - Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk.  As of June 30, 2017, we had no outstanding borrowings on our revolving bank credit facility.  The revolving bank credit facility has a variable interest rate, which is primarily impacted by the London Interbank Offered Rate and the margin, which ranges from 3.00% to 4.00% depending on the amount outstanding.  As of June 30, 2017, we did not have any derivative instruments related to interest rates.

Item 4.  Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of June 30, 2017, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended June 30, 2017, 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.  

48

PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

See Part I, Item 1, Financial Statements – Note 9 – Contingencies, 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, 2016, 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 the continued weakness in 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, 2016 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, 2016.

Item 6.  Exhibits

The exhibits to this report are listed in the Exhibit Index.

49

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 4, 2017.

W&T OFFSHORE, INC.
By:	/s/  JOHN D. GIBBONS
	John D. Gibbons
	Senior Vice President and Chief Financial Officer (Principal Financial Officer), duly authorized to sign on behalf of the registrant

50

EXHIBIT INDEX

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 25, 2006)
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))
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.  

51

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:  August 4, 2017	/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, John D. Gibbons, 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:  August 4, 2017	/s/  John D. Gibbons
	John D. Gibbons
	Senior Vice President and Chief Financial 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 June 30, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act 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:  August 4, 2017	/s/  Tracy W. Krohn
	Tracy W. Krohn
	Chairman, Chief Executive Officer and Director
	(Principal Executive Officer)

Date:  August 4, 2017	/s/  John D. Gibbons
	John D. Gibbons
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 01, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
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 Common Stock, Shares Outstanding		137,821,744

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 72,320	$ 70,236
Receivables:
Oil and natural gas sales	39,397	43,073
Joint interest	19,920	21,885
Insurance reimbursement		30,100
Income taxes	12,027	11,943
Total receivables	71,344	107,001
Prepaid expenses and other assets (Note 1)	21,944	14,504
Total current assets	165,608	191,741
Oil and natural gas properties and other, net - at cost: (Note 1)	550,681	547,053
Restricted deposits for asset retirement obligations	28,712	27,371
Income tax receivables	68,974	52,097
Other assets (Note 1)	60,996	11,464
Total assets	874,971	829,726
Current liabilities:
Accounts payable	58,283	81,039
Undistributed oil and natural gas proceeds	21,270	26,254
Asset retirement obligations	52,432	78,264
Long-term debt	11,147	8,272
Accrued liabilities (Note 1)	13,122	9,200
Total current liabilities	156,254	203,029
Long-term debt: (Note 2)
Principal	873,733	873,733
Carrying value adjustments	110,604	138,722
Long term debt, less current portion - carrying value	984,337	1,012,455
Asset retirement obligations, less current portion	265,428	256,174
Other liabilities (Note 1)	66,909	17,105
Commitments and contingencies (Note 9)
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at June 30, 2017 and December 31, 2016
Common stock, $0.00001 par value; 200,000,000 shares authorized; 140,690,917 issued and 137,821,744 outstanding at June 30, 2017 and 140,543,545 issued and 137,674,372 outstanding at December 31, 2016	1	1
Additional paid-in capital	543,439	539,973
Retained earnings (deficit)	(1,117,230)	(1,174,844)
Treasury stock, at cost; 2,869,173 shares at June 30, 2017 and December 31, 2016	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(597,957)	(659,037)
Total liabilities and shareholders’ equity (deficit)	$ 874,971	$ 829,726

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Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2017	Dec. 31, 2016
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	140,690,917	140,543,545
Common stock, outstanding	137,821,744	137,674,372
Treasury stock, shares	2,869,173	2,869,173

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Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Statement [Abstract]
Revenues	$ 123,323	$ 99,655	$ 247,716	$ 177,370
Operating costs and expenses:
Lease operating expenses	31,519	36,622	71,683	81,091
Production taxes	449	370	964	896
Gathering and transportation	5,318	6,398	11,527	11,490
Depreciation, depletion, amortization and accretion	40,364	57,493	80,354	121,226
Ceiling test write-down of oil and natural gas properties		104,592		221,151
General and administrative expenses	16,474	16,235	29,748	32,678
Derivative (gain) loss	(3,689)	4,942	(7,644)	2,449
Total costs and expenses	90,435	226,652	186,632	470,981
Operating income (loss)	32,888	(126,997)	61,084	(293,611)
Interest expense:
Incurred	11,436	29,773	22,730	57,587
Capitalized		(102)		(445)
Gain on exchange of debt	8,056		7,811
Other (income) expense, net	5,168	(24)	5,114	1,282
Income (loss) before income tax benefit	24,340	(156,644)	41,051	(352,035)
Income tax benefit	(8,975)	(35,722)	(16,563)	(40,604)
Net income (loss)	$ 33,315	$ (120,922)	$ 57,614	$ (311,431)
Basic and diluted earnings (loss) per common share	$ 0.23	$ (1.58)	$ 0.40	$ (4.07)

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Condensed Consolidated Statement of Changes in Shareholders' Deficit - 6 months ended Jun. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock Outstanding	Additional Paid-In Capital	Retained Earnings (Deficit)	Treasury Stock
Beginning Balances at Dec. 31, 2016	$ (659,037)	$ 1	$ 539,973	$ (1,174,844)	$ (24,167)
Beginning Balances (in shares) at Dec. 31, 2016		137,674			2,869
Share-based compensation	3,466		3,466
Share-based compensation (in shares)		148
Net income	57,614			57,614
Ending Balances at Jun. 30, 2017	$ (597,957)	$ 1	$ 543,439	$ (1,117,230)	$ (24,167)
Ending Balances (in shares) at Jun. 30, 2017		137,822			2,869

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Condensed Consolidated Statements Of Cash Flows $ in Thousands	6 Months Ended
	Jun. 30, 2017 USD ($)
Operating activities:
Net income (loss)	$ 57,614
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	80,354
Gain on exchange of debt	(7,811)
Debt issuance costs write-down/amortization of debt items	836
Share-based compensation	3,466
Derivative (gain) loss	(7,644)
Cash receipts on derivative settlements	2,208
Deferred income taxes	212
Changes in operating assets and liabilities:
Oil and natural gas receivables	3,675
Joint interest receivables	1,965
Insurance reimbursements	30,100
Income taxes	(16,960)
Prepaid expenses and other assets	(3,575)
Escrow deposit - Apache lawsuit	(49,500)
Asset retirement obligation settlements	(36,021)
Accounts payable, accrued liabilities and other	6,666
Net cash provided by (used in) operating activities	65,585
Investing activities:
Investment in oil and natural gas properties and equipment	(43,800)
Changes in operating assets and liabilities associated with investing activities	(827)
Purchases of furniture, fixtures and other	(853)
Net cash used in investing activities	(45,480)
Financing activities:
Other	(372)
Net cash provided by (used in) financing activities	(18,021)
Increase in cash and cash equivalents	2,084
Cash and cash equivalents, beginning of period	70,236
Cash and cash equivalents, end of period	72,320
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Payment of interest	(4,113)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest	(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

6 Months Ended

Jun. 30, 2017

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 interest 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”).  

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, 2016.

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 prices of these commodities improved during the first half of 2017 compared to the average prices in the first half of 2016 and for the full year of 2016.  Operating costs were lower in the first half of 2017 on a barrel oil equivalent (“Boe”) basis compared to the first half of 2016.  In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments in the first half of 2017 compared to the first half of 2016.  In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described below, the maturities of two of the new loans will accelerate if certain events do not transpire.

We continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”).  Our 2017 capital budget is relatively modest by historical standards and we have some flexibility for the balance of the year.  The 2017 capital budget is higher than the capital expenditures incurred during 2016, but it is significantly lower than spending levels incurred during 2015 and 2014.  

During the first half of 2017, the Bureau of Ocean Energy Management (“BOEM”) extended the implementation timeline (without setting a revised implementation date) for Notice to Lessees #2016-N01 (“NTL #2016-N01”) regarding financial assurances to be provided by lessees in connection with Outer Continental Shelf (“OCS”) leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”) for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  Also, in the first quarter of 2017, the BOEM withdrew the orders related to its so called “sole liability” properties it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.

Actions are underway for the BOEM to rescind the previous orders regarding financial assurances issued in the first quarter of 2016 totaling $260.8 million.  See Note 9 and Note 10 for additional information.

During the second quarter of 2017, a final trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us.  As a result, we deposited $49.5 million in an escrow account from cash on hand as a first step to allow us to appeal the decision.  See Note 9 for additional information.  

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices.  We believe we will have adequate liquidity to fund our operations beyond September 2018, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or the future 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, 2016 concerning risks related to our business and events occurring during 2016 and other information and the Notes herein for additional information.  

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

	June 30,		December 31,
	2017		2016
Derivative assets (1)	$	6,365	$	—
Prepaid/accrued insurance		3,802		2,924
Surety bond unamortized premiums		2,855		2,462
Prepaid deposits related to royalties		6,155		6,237
Other		2,767		2,881
Prepaid expenses and other assets	$	21,944	$	14,504

(1) Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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

	June 30,		December 31,
	2017		2016
Oil and natural gas properties and equipment	$	8,007,073	$	7,932,504
Furniture, fixtures and other		21,751		20,898
Total property and equipment		8,028,824		7,953,402
Less accumulated depreciation, depletion and amortization		7,478,143		7,406,349
Oil and natural gas properties and other, net	$	550,681	$	547,053

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

	June 30,		December 31,
	2017		2016
Accrued interest	$	4,196	$	4,189
Accrued salaries/payroll taxes/benefits		4,627		2,777
Other		4,299		2,234
Total accrued liabilities	$	13,122	$	9,200

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

	June 30,		December 31,
	2017		2016
Escrow deposit - Apache lawsuit	$	49,500	$	—
Appeal bond deposits		6,925		6,925
Other		4,571		4,539
Total other assets	$	60,996	$	11,464

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

	June 30,		December 31,
	2017		2016
Apache lawsuit	$	49,500	$	—
Uncertain tax positions including interest/penalties		10,796		10,584
Other		6,613		6,521
Total other liabilities (long-term)	$	66,909	$	17,105

Recent Accounting Developments.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application (modified retrospective approach).  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is that the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  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 finance or operating lease.  However, unlike current GAAP, which requires only capital 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.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space in Houston, Texas and New Orleans, Louisiana, 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.  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.  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, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  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 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the statement of cash flows (financing vs. investing) and the amount of such change would not have been material; therefore, we do not anticipate the new standard will have a material effect on our financial statements.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

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Long-Term Debt

6 Months Ended

Jun. 30, 2017

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):

	June 30, 2017								December 31, 2016
			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		—		19,709			19,709			—		23,823			23,823
Subtotal		75,000		19,709			94,709			75,000		23,823			98,823
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		163,007		—			163,007			163,007		—			163,007
Future payments-in-kind		—		14,506			14,506			—		24,048			24,048
Future interest payments		—		34,873			34,873			—		36,850			36,850
Subtotal		163,007		49,379			212,386			163,007		60,898			223,905
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		145,897		—			145,897			145,897		—			145,897
Future payments-in-kind		—		18,618			18,618			—		26,844			26,844
Future interest payments		—		38,682			38,682			—		40,705			40,705
Subtotal		145,897		57,300			203,197			145,897		67,549			213,446
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(4,637	)		(4,637	)		—		(5,276	)		(5,276	)
Total long-term debt		873,733		121,751			995,484			873,733		146,994			1,020,727
Current maturities of long-term debt (2)		—		11,147			11,147			—		8,272			8,272
Long term debt, less current    maturities	$	873,733	$	110,604		$	984,337		$	873,733	$	138,722		$	1,012,455

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

(2) Future interest payments on the 1.5 Lien Term Loan and Second Lien PIK Toggle Notes due within twelve months.

Exchange Transaction

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes, due June 15, 2019 (the “Unsecured Senior Notes”) for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 15, 2019, (the “1.5 Lien Term Loan”) with the largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”).  We accounted for the Exchange Transaction 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 newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Condensed Consolidated Statements of Operations during the six months ended June 30, 2017.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.    

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

During the second quarter of 2017, interest on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes was paid in cash rather than in kind.  As a result of the cash interest payment, an $8.2 million net reduction was recorded to long-term debt on the Condensed Consolidated Balance Sheet and the offset to Gain on exchange of debt in the Condensed Consolidated Statement of Operations.  We anticipate the remaining eligible interest payments will be made in kind versus paid in cash.  For the six months ended June 30, 2017, $0.4 million of additional expense was recorded to Gain on exchange of debt for differences between actual and estimated transaction expenses.

The primary terms of our long-term debt following the Exchange Transaction are described below.    

Credit Agreement

The Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), provides a revolving bank credit facility.  The primary items of the Credit Agreement are as follows, with certain terms defined under the Credit Agreement:

• The borrowing base is $150.0 million.

• Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.      

• The First Lien Leverage Ratio limits are 2.50 to 1.00 through June 30, 2017, and 2.00 to 1.00 thereafter.

• The Current Ratio must be greater than 1.00 to 1.00.

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

• We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

• Borrowings primarily are executed as Eurodollar Loans, and the applicable margins range from 3.00% to 4.00%.

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

• The Credit Agreement terminates on November 8, 2018.

Availability under our revolving bank credit facility 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 2017 spring redetermination reaffirmed the borrowing base amount of $150.0 million.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  The revolving bank credit facility is secured and is collateralized by a first priority lien on substantially all of our oil and natural gas properties.  

The Credit Agreement contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other long-term debt agreements, and such agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2017.

  As of June 30, 2017 and December 31, 2016, we did not have any borrowings outstanding and had $0.3 million and $0.5 million, respectively, of letters of credit outstanding under the revolving bank credit facility.  Availability as of June 30, 2017 was $149.7 million.

1.5 Lien Term Loan

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the 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 have been included in the carrying value under ASC 470-60.  Current maturities of long-term debt include the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; (vii) create liens that secure debt; and (viii) enter into transactions with affiliates.  We were in compliance with all applicable covenants as of June 30, 2017.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%.  The Second Lien Term Loan was issued at a 1.0% discount to par, matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.6%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  The Second Lien Term Loan contains covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016 with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period.  For the initial interest period ending November 15, 2016, interest could only be paid-in-kind at the annual rate of 10.75%.  For interest periods through March 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.75% per annum.  For the six month interest period ending May 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and are effectively pari passu with the Second Lien Term Loan (discussed above).  For purposes of determining the carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid in kind versus paid in cash.  When the PIK option is utilized, the principal amount of the notes increases.  Current maturities of long-term debt include the cash interest payable for the Second Lien PIK Toggle Notes for the stub period of March 7, 2018 to May 15, 2018.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.    

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016 with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain interest provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period.  For the initial interest period ending December 15, 2016, interest could only be paid in kind at the annual rate of 10.00%.  For interest periods through September 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.00% per annum.  For the six month interest period ending June 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid in kind versus paid in cash.  When the PIK option is utilized, the principal amount of the notes increases.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.

Unsecured Senior Notes

Our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.3%, which includes amortization of premiums and debt issuance costs.  The Unsecured Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with all applicable covenants as of June 30, 2017.  

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

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Fair Value Measurements

6 Months Ended

Jun. 30, 2017

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 inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads, credit risk and published commodity futures prices.  The fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as no market has developed and the holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  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 an active market; therefore, the fair value is classified within Level 2.  

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

	June 30, 2017				December 31, 2016
	Assets		Liabilities		Assets		Liabilities
Derivatives - open contracts	$	5,436	$	—	$	—	$	—
11.00% 1.5 Term Loan, due November 2019 (1)		—		75,000		—		75,000
9.00% Second Lien Term Loan, due May 2020 (1)		—		249,000		—		255,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 (1)		—		133,666		—		122,255
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 (1)		—		99,210		—		80,243
8.50% Unsecured Senior Notes, due June 2019  (1)		—		131,931		—		123,389

(1) The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2.  

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

4.  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, 2016	$	334,438
Liabilities settled		(36,021	)
Accretion of discount		8,560
Revisions of estimated liabilities (1)		10,883
Balance, June 30, 2017		317,860
Less current portion		52,432
Long-term	$	265,428

(1) Revisions were primarily related to changes from sustained casing pressure at four fields.  Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project.  

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Derivative Financial Instruments

6 Months Ended

Jun. 30, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

5.  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 oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  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.

For information about fair value measurements, refer to Note 3.

Commodity Derivatives

As of June 30, 2017, we had open crude oil and natural gas derivative contracts for a portion of our anticipated future production for the remainder of 2017.  These contracts were entered into during the first quarter of 2017.  For crude oil, we entered into two types of contracts.  The first type is a swap contract, where we either receive or pay depending on whether the crude oil price is below or above the contract price.   The second type is known as “two-way collar” consisting of a purchased put option and a sold call option.  These two-way collars provide price risk protection if commodity prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  For natural gas, we entered into “two-way collar” contracts.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. The strike prices of both the oil and natural gas two-way collar contracts were set so that the contracts were premium neutral (“costless”), which means no net premiums were paid to or received from a counterparty.  Settlement occurs monthly using the per day notional quantity.  As of December 31, 2016, we did not have any open derivative contracts.    

As of June 30, 2017, our open commodity derivative contracts were as follows:

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)
		Quantity		Quantity		Strike
Termination Period		(Bbls/day)		(Bbls)		Price
2017	4th Quarter		1,000		184,000	$	55.25
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day)		(Bbls)		(Bought)		(Sold)
2017	4th Quarter		4,000		736,000	$	50.00	$	60.15
Natural Gas:  Two-way collars, Priced off Henry Hub (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(MMBtu's/day)		(MMBtu's)		(Bought)		(Sold)
2017	4th Quarter (2)		30,000		4,590,000	$	3.07	$	3.96

(1) Volume Measurements:   Bbls – barrelsMMBtu’s – million British Thermal Units.

(2) The natural gas derivative contracts are priced and closed in the last week prior to the related production month.  Natural gas derivative contracts related to July 2017 production were priced and closed in June 2017 and are not included in the above table as these were not open derivative contracts as of June 30, 2017.

Our open and closed (not settled) commodity derivative contracts were recorded within the line Prepaid expenses and other assets on the Condensed Consolidated Balance Sheets summarized in the following table (in thousands):

	June 30,		December 31,
	2017		2016
Open contracts	$	5,436	$	—
Closed contracts - not settled		929		—
Total contracts	$	6,365	$	—

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017			2016		2017			2016
Derivative (gain) loss	$	(3,689	)	$	4,942	$	(7,644	)	$	2,449

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

	Six Months Ended
	June 30,
	2017		2016
Cash receipts on derivative settlements, net	$	2,208	$	4,746

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 revolving bank credit facility, that event may also trigger an acceleration of settlement 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.  

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Share-Based Compensation and Cash-Based Incentive Compensation

6 Months Ended

Jun. 30, 2017

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Share-Based Compensation and Cash-Based Incentive Compensation

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

Awards to Employees.  In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders, and amendments to the Plan were approved by our shareholders in May 2013, May 2016 and May 2017.  The May 2017 amendment increased the number of shares available in the Plan by 7,700,000 shares.  As allowed by the Plan, during the six months ended June 30, 2017 and the years 2016 and 2015, the Company granted restricted stock units (“RSUs”) to certain of its employees.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the results of certain predetermined criteria.  In addition to share-based compensation, the Company may grant to its employees cash-based incentive awards, which are a short-term component of the Plan and are typically based on the Company and the employee achieving certain pre-defined performance criteria.

As of June 30, 2017, there were 14,633,337 shares of common stock available for issuance in satisfaction of awards under the Plan.  The shares available for issuance are reduced when RSUs are settled in shares of common stock, net of withholding tax.  The Company has the option at vesting to settle RSUs in stock or cash, or a combination of stock and cash.  Prior to 2017, only shares of common stock were used to settle vested RSUs.  For the six months ended June 30, 2017, cash was used to settle vested RSUs related to the retirement of an executive officer.  The Company plans to settle RSUs that vest in the future using shares of common stock.  

RSUs currently outstanding related to the 2016 and 2015 grants have been adjusted for performance achieved against predetermined criteria for the applicable performance year.  These RSUs continue to be subject to employment-based criteria and vesting occurs in December of the second year after the grant.  The RSUs related to the 2017 grants are subject to performance-based criteria and employment-based criteria.  See the second table below for potential 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 2017, 2016 and 2015 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 six months ended June 30, 2017 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2016		6,107,248		$	2.73
Granted		2,080,181			2.77
Vested		(323,870	)		2.73
Forfeited		(268,173	)		2.77
Nonvested, June 30, 2017		7,595,386			2.74

For the outstanding RSUs issued to the eligible employees as of June 30, 2017, vesting is expected to occur as follows:  

	Restricted Stock Units
2017		2,108,397
2018		3,477,267
2019		2,009,722
Total		7,595,386

The fair value of RSUs granted during the six months ended June 30, 2017 was $5.8 million based on the closing price of the Company’s common stock on the date of grant.

Awards to Non-Employee Directors.  Under the Director Compensation Plan, shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during the six months ended June 30, 2017, and the years 2016 and 2015.  As of June 30, 2017, there were 170,524 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced 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 during the six months ended June 30, 2017 is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2016		161,296		$	3.47
Granted		147,372			1.90
Vested		(62,140	)		4.51
Nonvested, June 30, 2017		246,528			2.27

For the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2017, vesting is expected to occur as follows:

	Restricted Shares
2018		106,240
2019		91,164
2020		49,124
Total		246,528

The fair value of Restricted Shares granted during the six months ended June 30, 2017 was $0.3 million based on the closing price of the Company’s common stock on the date of grant.

  Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation expense from:
Restricted stock units	$	2,342	$	2,439	$	4,200	$	4,888
Restricted Shares		70		146		140		233
Total	$	2,412	$	2,585	$	4,340	$	5,121
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	844	$	904	$	1,519	$	1,792

Unrecognized Share-Based Compensation.As of June 30, 2017, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $9.7 million and $0.5 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2019 for RSUs and April 2019 for Restricted Shares.

Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees and are typically payable in cash.  These awards are performance-based awards consisting of one or more business or individual performance criteria and a targeted level or levels of performance with respect to each such criterion.  Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.  

During the six months ended June 30, 2017, and the years 2016 and 2015, the Company issued cash-based incentive awards.  In addition to being performance-based awards related to respective 2017, 2016 and 2015 criteria, the payment of such awards is contingent on the Company achieving the following financial condition on or before December 31, 2019, December 31, 2018 and December 31, 2017, respectively:  Adjusted EBITDA less Interest Expense, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $200.0 million for the 2017 awards and exceeds $300.0 million for the 2016 and 2015 awards.  As the Company did not achieve the financial condition for the 2016 and 2015 awards up through June 30, 2017, and we do not estimate the Company will achieve the financial condition within the respective measurement period, no amounts have been recognized to date related to the 2015 and 2016 awards.  For the 2017 awards, amounts were recognized as reported in the table below as it is anticipated the Company will achieve some of the performance-based criteria and will achieve the financial condition within the respective measurement period.     

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation included in:
General and administrative expenses	$	2,412	$	2,585	$	4,340	$	5,121
Cash-based incentive compensation included in:
Lease operating expense		394		—		394		364
General and administrative expenses		1,004		—		1,004		(233	)
Total charged to operating income	$	3,810	$	2,585	$	5,738	$	5,252

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Income Taxes

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

7.  Income Taxes

Our income tax benefit for the three and six months ended June 30, 2017 was $9.0 million and $16.6 million, respectively.  Our income tax benefit for the three and six months ended June 30, 2016 was $35.7 million and $40.6 million, respectively.  Our annualized effective tax rate was not meaningful for any period presented.  The income tax benefit for all periods presented relates to net operating loss (“NOL”) 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 six months ended June 30, 2017, we did not pay any income tax or receive any income tax refunds of significance.  During the six months ended June 30, 2016, we made payments of $0.3 million and received $2.3 million of refunds.         

As of June 30, 2017, we recorded current income tax receivables of $12.0 million and non-current income tax receivables of $69.0 million.  As of December 31, 2016, we recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million (in July 2017, we received income tax refunds of $11.9 million).  The current income tax receivables primarily relates to our NOL claim for 2016 carried back to 2006.  The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years and to an estimated NOL claim for 2017 that is expected to be filed subsequent to December 31, 2017.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims related to the years 2012, 2013 and 2014 will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current as these refund claims are expected to be received in the latter part of 2018.

 As of June 30, 2017 and December 31, 2016, our valuation allowance was $270.4 million and $290.2 million, respectively, related to Federal, Louisiana and Alabama NOLs and other deferred 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 NOLs are deductible.  In addition, the realization depends on the ability to carryback certain items to prior years for refunds of taxes previously paid.  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.  

We recognize interest and penalties related to unrecognized tax benefits in income tax expense.  During the six months ended June 30, 2017 and 2016, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

The tax years 2013 through 2016 remain open to examination by the tax jurisdictions to which we are subject.   

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Earnings/ (Loss) Per Share

6 Months Ended

Jun. 30, 2017

Earnings Per Share [Abstract]

Earnings/ (Loss) Per Share

8.  Earnings/ (Loss) Per Share

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
Net income (loss)	$	33,315	$	(120,922	)	$	57,614	$	(311,431	)
Less portion allocated to nonvested shares		1,374		—			2,442		—
Net income (loss) allocated to common shares	$	31,941	$	(120,922	)	$	55,172	$	(311,431	)
Weighted average common shares outstanding		137,552		76,457			137,533		76,443
Basic and diluted earnings (loss) per common share	$	0.23	$	(1.58	)	$	0.40	$	(4.07	)
Shares excluded due to being anti-dilutive (weighted-average)		—		3,531			—		3,529

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Contingencies

6 Months Ended

Jun. 30, 2017

Commitments And Contingencies Disclosure [Abstract]

Contingencies

9.  Contingencies  

Supplemental Bonding Requirements by the BOEM.  The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM issued NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.

• In the first quarter of 2016, we received several orders from the BOEM pursuant to NTL #2008-N07 demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the Interior Board of Land Appeals (the “IBLA”) concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to August 31, 2017.      

• On June 20, 2017, we notified the BOEM that we had satisfied our financial assurance obligations for our sole liability properties as designated by BOEM.  Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  

• Based on our satisfaction of the BOEM demand for our sole liability properties, on June 28, 2017, the BOEM commenced the process necessary to rescind the prior orders issued in 2016 ordering us to provide $260.8 million in financial assurance obligations.

• Since these BOEM orders are the subject of appeals by us before the IBLA, the Office of the Solicitor for the Department of the Interior, on behalf of BOEM, filed motions to remand the four IBLA appeals back to the BOEM.  This will allow the BOEM to rescind the orders.

• As described in Note 10, the motions to remand were granted by the IBLA on July 31, 2017.  

• We are currently in compliance with our financial assurance obligations to the BOEM and, upon rescission of the 2016 orders, we will be under no outstanding BOEM orders related to financial assurance obligations. 

W&T and other offshore Gulf of Mexico producers may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurances.  

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 six months ended June 30, 2017.

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.  The dispute relates to Apache's use of drilling rigs instead of a previously contracted intervention vessel for the plugging and abandonment work.  We contended that the costs to use the drilling rigs were unnecessary and unreasonable, and that Apache chose to use the rigs without W&T's consent because they otherwise would have been idle at Apache's expense.  We believe the use of the rigs was in bad faith, as found by the jury, and that such conduct caused W&T not to comply with the applicable joint operating agreement, particularly since another vessel had been contracted by Apache for the abandonment a year in advance.  We had previously paid $24.9 million to Apache as an undisputed amount for the plug and abandonment work.

On October 28, 2016, the jury made the following findings:

1. W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells.

2. The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million.

3. The $43.2 million referred to in #2 should be offset by $17.0 million.

4. Apache acted in bad faith thereby causing W&T to not comply with the contract.

A final 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 intend to appeal the trial court judgment in this lawsuit.  In June 2017, in order to stay execution of the judgment, and pending the disposition of post judgment motions, we deposited with the court $49.5 million in escrow.  This amount in escrow is recorded in Other assets (long-term) with a corresponding reduction to Cash and cash equivalents on the Condensed Consolidated Balance Sheet.  Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) and $43.2 million as capitalized ARO included in Oil and natural gas properties and other, net on the Condensed Consolidated Balance Sheet and have recognized $6.3 million of expense included in Other income/expense on the Condensed Statement of Operations.    

Notification by ONRR of Fine for Non-compliance.  In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to approximately $1.1 million) relative to such underpayment.  We filed for a hearing on the matter and a decision was issued by an Administrative Law Judge in June 2017 cancelling the civil penalty in its entirety under the applicable provisions of the Federal Oil and Gas Royalty Management Act.  

Appeal with 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 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.  After discussing with counsel, we have decided to seek judicial review of the IBLA decision in federal court in New Orleans.

Royalties – “Unbundling” Initiative.  The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas.  In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant.  We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases.  We have submitted revised calculations covering certain plants and time periods to the ONRR.  As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods.  For the six months ended June 30, 2017, we have made additional royalty payments of $1.1 million.  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.  As of June 30, 2017, we had five open civil penalties issued by the Bureau of Safety and Environmental Enforcement (“BSEE”) arising from Incidents of Noncompliance (“INCs”), which have not been settled as of the filing date of this Form 10-Q.  The INC’s underlying the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to March 2016.  The proposed civil penalties for these INCs total $7.5 million and we are appealing these proposed assessments.  During the six months ended June 30, 2017, we made $0.1 million of payments related to civil penalties.  During the six months ended June 30, 2017, we increased the estimated liability by $1.8 million and have accrued approximately $3.3 million as of June 30, 2017, which is our best estimate of the final settlement 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.     

Iberville School Board Lawsuit.In August 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against us (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities.  The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  All parties have reached a settlement in principle for this matter.  A motion has been filed with the court seeking approval of the settlement.  The effect of the settlement on the financial statements was immaterial from the previously recorded liability.  

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 Event

6 Months Ended

Jun. 30, 2017

Subsequent Events [Abstract]

Subsequent Event

10.  Subsequent Event

On July 31, 2017, the motions to remand were granted by the IBLA concerning the four appeals filed by us related to the four orders issued by the BOEM instructing us to provide $260.8 million in financial assurance obligations.  This will allow the BOEM to rescind the orders, which we anticipate in the ordinary course over the next few weeks.  

XML

Supplemental Guarantor Information

6 Months Ended

Jun. 30, 2017

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

11.  Supplemental Guarantor Information

Our payment obligations under the 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 (see Note 2) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Guarantees will 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 applicable indenture);

(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 indenture 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 certain debt documents;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the applicable indenture) or upon satisfaction and discharge of the certain debt documents;

(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 certain debt documents, 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 to the ceiling test write-down recorded in 2016, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company.  Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately.  

Condensed Consolidating Balance Sheet as of June 30, 2017

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	72,320		$	—		$	—		$	72,320
Receivables:
Oil and natural gas sales		3,268			36,129			—			39,397
Joint interest		19,920			—			—			19,920
Income taxes		119,732			—			(107,705	)		12,027
Total receivables		142,920			36,129			(107,705	)		71,344
Prepaid expenses and other assets		19,480			2,464			—			21,944
Total current assets		234,720			38,593			(107,705	)		165,608
Oil and natural gas properties and other, net		392,445			160,708			(2,472	)		550,681
Restricted deposits for asset retirement obligations		28,712			—			—			28,712
Income tax receivables		68,974			—			—			68,974
Other assets		481,201			418,924			(839,129	)		60,996
Total assets	$	1,206,052		$	618,225		$	(949,306	)	$	874,971
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	51,932		$	6,351		$	—		$	58,283
Undistributed oil and natural gas proceeds		19,626			1,644			—			21,270
Asset retirement obligations		44,776			7,656			—			52,432
Long-term debt		11,147			—			—			11,147
Accrued liabilities		13,122			107,705			(107,705	)		13,122
Total current liabilities		140,603			123,356			(107,705	)		156,254
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		110,604			—			—			110,604
Long term debt, less current portion - carrying value		984,337			—			—			984,337
Asset retirement obligations, less current portion		144,292			121,136			—			265,428
Other liabilities		532,305			—			(465,396	)		66,909
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		543,439			704,885			(704,885	)		543,439
Retained earnings (deficit)		(1,114,758	)		(331,152	)		328,680			(1,117,230	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(595,485	)		373,733			(376,205	)		(597,957	)
Total liabilities and shareholders’ equity (deficit)	$	1,206,052		$	618,225		$	(949,306	)	$	874,971

Condensed Consolidating Balance Sheet as of December 31, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	70,236		$	—		$	—		$	70,236
Receivables:
Oil and natural gas sales		2,173			40,900			—			43,073
Joint interest		21,885			—			—			21,885
Insurance reimbursement		30,100			—			—			30,100
Income taxes		111,215			—			(99,272	)		11,943
Total receivables		165,373			40,900			(99,272	)		107,001
Prepaid expenses and other assets		12,448			2,056			—			14,504
Total current assets		248,057			42,956			(99,272	)		191,741
Oil and natural gas properties and other, net		360,966			187,040			(953	)		547,053
Restricted deposits for asset retirement obligations		27,371			—			—			27,371
Income tax receivables		52,097			—			—			52,097
Other assets		394,931			344,742			(728,209	)		11,464
Total assets	$	1,083,422		$	574,738		$	(828,434	)	$	829,726
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	74,306		$	6,733		$	—		$	81,039
Undistributed oil and natural gas proceeds		24,493			1,761			—			26,254
Asset retirement obligations		62,261			16,003			—			78,264
Long-term debt		8,272			—			—			8,272
Accrued liabilities		9,293			99,179			(99,272	)		9,200
Total current liabilities		178,625			123,676			(99,272	)		203,029
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		138,722			—			—			138,722
Long term debt, less current portion - carrying value		1,012,455			—			—			1,012,455
Asset retirement obligations, less current portion		142,376			113,798			—			256,174
Other liabilities		408,050			—			(390,945	)		17,105
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		539,973			704,885			(704,885	)		539,973
Retained earnings (deficit)		(1,173,891	)		(367,621	)		366,668			(1,174,844	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ deficit		(658,084	)		337,264			(338,217	)		(659,037	)
Total liabilities and shareholders’ deficit	$	1,083,422		$	574,738		$	(828,434	)	$	829,726

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

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	57,417		$	65,906	$	—		$	123,323
Operating costs and expenses:
Lease operating expenses		17,325			14,194		—			31,519
Production taxes		449			—		—			449
Gathering and transportation		2,578			2,740		—			5,318
Depreciation, depletion, amortization and accretion		21,433			18,143		788			40,364
General and administrative expenses		7,662			8,812		—			16,474
Derivative gain		(3,689	)		—		—			(3,689	)
Total costs and expenses		45,758			43,889		788			90,435
Operating income		11,659			22,017		(788	)		32,888
Earnings of affiliates		18,941			—		(18,941	)		—
Interest expense incurred		11,436			—		—			11,436
Gain on exchange of debt		8,056			—		—			8,056
Other expense, net		5,168			—		—			5,168
Income before income tax benefit		22,052			22,017		(19,729	)		24,340
Income tax benefit		(12,051	)		3,076		—			(8,975	)
Net income	$	34,103		$	18,941	$	(19,729	)	$	33,315

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	111,124		$	136,592	$	—		$	247,716
Operating costs and expenses:
Lease operating expenses		41,027			30,656		—			71,683
Production taxes		964			—		—			964
Gathering and transportation		5,144			6,383		—			11,527
Depreciation, depletion, amortization and accretion		40,587			38,248		1,519			80,354
General and administrative expenses		13,438			16,310		—			29,748
Derivative gain		(7,644	)		—		—			(7,644	)
Total costs and expenses		93,516			91,597		1,519			186,632
Operating income		17,608			44,995		(1,519	)		61,084
Earnings of affiliates		36,468			—		(36,468	)		—
Interest expense incurred		22,730			—		—			22,730
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,114			—		—			5,114
Income before income tax benefit		34,043			44,995		(37,987	)		41,051
Income tax benefit		(25,090	)		8,527		—			(16,563	)
Net income	$	59,133		$	36,468	$	(37,987	)	$	57,614

Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	43,914		$	55,741		$	—		$	99,655
Operating costs and expenses:
Lease operating expenses		19,254			17,368			—			36,622
Production taxes		370			—			—			370
Gathering and transportation		2,469			3,929			—			6,398
Depreciation, depletion, amortization and accretion		22,648			31,934			2,911			57,493
Ceiling test write-down of oil and natural gas    properties		—			35,008			69,584			104,592
General and administrative expenses		7,360			8,875			—			16,235
Derivative loss		4,942			—			—			4,942
Total costs and expenses		57,043			97,114			72,495			226,652
Operating loss		(13,129	)		(41,373	)		(72,495	)		(126,997	)
Loss of affiliates		(40,765	)		—			40,765			—
Interest expense:
Incurred		29,735			38			—			29,773
Capitalized		(64	)		(38	)		—			(102	)
Other expense, net		(24	)		—			—			(24	)
Loss before income tax benefit		(83,541	)		(41,373	)		(31,730	)		(156,644	)
Income tax benefit		(35,114	)		(608	)		—			(35,722	)
Net loss	$	(48,427	)	$	(40,765	)	$	(31,730	)	$	(120,922	)

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	74,426		$	102,944		$	—		$	177,370
Operating costs and expenses:
Lease operating expenses		44,199			36,892			—			81,091
Production taxes		896			—			—			896
Gathering and transportation		4,022			7,468			—			11,490
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas    properties		—			85,392			135,759			221,151
General and administrative expenses		13,973			18,705			—			32,678
Derivative loss		2,449			—			—			2,449
Total costs and expenses		108,810			218,552			143,619			470,981
Operating loss		(34,384	)		(115,608	)		(143,619	)		(293,611	)
Loss of affiliates		(113,794	)		—			113,794			—
Interest expense:
Incurred		57,430			157			—			57,587
Capitalized		(288	)		(157	)		—			(445	)
Other expense, net		1,282			—			—			1,282
Loss before income tax benefit		(206,602	)		(115,608	)		(29,825	)		(352,035	)
Income tax benefit		(38,790	)		(1,814	)		—			(40,604	)
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2017

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net income	$	59,133		$	36,468		$	(37,987	)	$	57,614
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		40,587			38,248			1,519			80,354
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		836			—			—			836
Share-based compensation		3,466			—			—			3,466
Derivative gain		(7,644	)		—			—			(7,644	)
Cash receipts on derivative settlements, net		2,208			—			—			2,208
Deferred income taxes		212			—			—			212
Earnings of affiliates		(36,468	)		—			36,468			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(1,095	)		4,770			—			3,675
Joint interest receivables		1,965			—			—			1,965
Insurance reimbursements		30,100			—			—			30,100
Income taxes		(25,487	)		8,527			—			(16,960	)
Prepaid expenses and other assets		(3,165	)		(74,591	)		74,181			(3,575	)
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligation settlements		(25,044	)		(10,977	)		—			(36,021	)
Accounts payable, accrued liabilities and other		81,785			(938	)		(74,181	)		6,666
Net cash provided by operating activities		64,078			1,507			—			65,585
Investing activities:
Investment in oil and natural gas properties and equipment		(41,854	)		(1,946	)		—			(43,800	)
Changes in operating assets and liabilities associated with    investing activities		(1,266	)		439			—			(827	)
Purchases of furniture, fixtures and other		(853	)		—			—			(853	)
Net cash used in investing activities		(43,973	)		(1,507	)		—			(45,480	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(4,113	)		—			—			(4,113	)
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 provided by financing activities		(18,021	)		—			—			(18,021	)
Increase in cash and cash equivalents		2,084			—			—			2,084
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	72,320		$	—		$	—		$	72,320

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2016

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas properties		—			85,392			135,759			221,151
Debt issuance costs write-off/ amortization of debt items		1,880			—			—			1,880
Share-based compensation		5,121			—			—			5,121
Derivative gain		2,449			—			—			2,449
Cash receipts on derivative settlements		4,746			—			—			4,746
Deferred income taxes		21,099			(1,814	)		—			19,285
Loss of affiliates		113,794			—			(113,794	)		—
Changes in operating assets and liabilities:
Oil and natural gas receivables		1,177			49			—			1,226
Joint interest receivables		1,763			—			—			1,763
Income taxes		(57,931	)		—			—			(57,931	)
Prepaid expenses and other assets		(9,405	)		(17,424	)		16,464			(10,365	)
Asset retirement obligations		(12,702	)		(12,454	)		—			(25,156	)
Accounts payable, accrued liabilities and other		(783	)		32,014			(16,464	)		14,767
Net cash provided by operating activities		(53,333	)		42,064			—			(11,269	)
Investing activities:
Investment in oil and natural gas properties and equipment		(8,600	)		(9,112	)		—			(17,712	)
Changes in operating assets and liabilities associated with    investing activities		(670	)		(33,452	)		—			(34,122	)
Proceeds from sales of assets		1,000			500			—			1,500
Purchases of furniture, fixtures and other		(70	)		—			—			(70	)
Net cash used in investing activities		(8,340	)		(42,064	)		—			(50,404	)
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		340,000			—			—			340,000
Repayments of long-term debt – revolving bank credit facility		(192,000	)		—			—			(192,000	)
Other		83			—			—			83
Net cash provided by financing activities		148,083			—			—			148,083
Increase in cash and cash equivalents		86,410			—			—			86,410
Cash and cash equivalents, beginning of period		85,414			—			—			85,414
Cash and cash equivalents, end of period	$	171,824		$	—		$	—		$	171,824

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2017

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 interest 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”).

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, 2016.

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 prices of these commodities improved during the first half of 2017 compared to the average prices in the first half of 2016 and for the full year of 2016.  Operating costs were lower in the first half of 2017 on a barrel oil equivalent (“Boe”) basis compared to the first half of 2016.  In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments in the first half of 2017 compared to the first half of 2016.  In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described below, the maturities of two of the new loans will accelerate if certain events do not transpire.

We continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”).  Our 2017 capital budget is relatively modest by historical standards and we have some flexibility for the balance of the year.  The 2017 capital budget is higher than the capital expenditures incurred during 2016, but it is significantly lower than spending levels incurred during 2015 and 2014.  

During the first half of 2017, the Bureau of Ocean Energy Management (“BOEM”) extended the implementation timeline (without setting a revised implementation date) for Notice to Lessees #2016-N01 (“NTL #2016-N01”) regarding financial assurances to be provided by lessees in connection with Outer Continental Shelf (“OCS”) leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”) for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  Also, in the first quarter of 2017, the BOEM withdrew the orders related to its so called “sole liability” properties it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.

Actions are underway for the BOEM to rescind the previous orders regarding financial assurances issued in the first quarter of 2016 totaling $260.8 million.  See Note 9 and Note 10 for additional information.

During the second quarter of 2017, a final trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us.  As a result, we deposited $49.5 million in an escrow account from cash on hand as a first step to allow us to appeal the decision.  See Note 9 for additional information.  

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices.  We believe we will have adequate liquidity to fund our operations beyond September 2018, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or the future 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, 2016 concerning risks related to our business and events occurring during 2016 and other information and the Notes herein for additional information.  

Prepaid Expenses And Other Assets

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

	June 30,		December 31,
	2017		2016
Derivative assets (1)	$	6,365	$	—
Prepaid/accrued insurance		3,802		2,924
Surety bond unamortized premiums		2,855		2,462
Prepaid deposits related to royalties		6,155		6,237
Other		2,767		2,881
Prepaid expenses and other assets	$	21,944	$	14,504

(1) Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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):

	June 30,		December 31,
	2017		2016
Oil and natural gas properties and equipment	$	8,007,073	$	7,932,504
Furniture, fixtures and other		21,751		20,898
Total property and equipment		8,028,824		7,953,402
Less accumulated depreciation, depletion and amortization		7,478,143		7,406,349
Oil and natural gas properties and other, net	$	550,681	$	547,053

Accrued Liabilities

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

	June 30,		December 31,
	2017		2016
Accrued interest	$	4,196	$	4,189
Accrued salaries/payroll taxes/benefits		4,627		2,777
Other		4,299		2,234
Total accrued liabilities	$	13,122	$	9,200

Other Assets (Long-term)

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

	June 30,		December 31,
	2017		2016
Escrow deposit - Apache lawsuit	$	49,500	$	—
Appeal bond deposits		6,925		6,925
Other		4,571		4,539
Total other assets	$	60,996	$	11,464

Other Liabilities (Long-term)

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

	June 30,		December 31,
	2017		2016
Apache lawsuit	$	49,500	$	—
Uncertain tax positions including interest/penalties		10,796		10,584
Other		6,613		6,521
Total other liabilities (long-term)	$	66,909	$	17,105

Recent Accounting Developments

Recent Accounting Developments.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application (modified retrospective approach).  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is that the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  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 finance or operating lease.  However, unlike current GAAP, which requires only capital 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.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space in Houston, Texas and New Orleans, Louisiana, 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.  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.  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, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  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 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the statement of cash flows (financing vs. investing) and the amount of such change would not have been material; therefore, we do not anticipate the new standard will have a material effect on our financial statements.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

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Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

Schedule of Amounts Recorded in Prepaid Expenses and Other Assets

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

	June 30,		December 31,
	2017		2016
Derivative assets (1)	$	6,365	$	—
Prepaid/accrued insurance		3,802		2,924
Surety bond unamortized premiums		2,855		2,462
Prepaid deposits related to royalties		6,155		6,237
Other		2,767		2,881
Prepaid expenses and other assets	$	21,944	$	14,504

(1) Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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):

	June 30,		December 31,
	2017		2016
Oil and natural gas properties and equipment	$	8,007,073	$	7,932,504
Furniture, fixtures and other		21,751		20,898
Total property and equipment		8,028,824		7,953,402
Less accumulated depreciation, depletion and amortization		7,478,143		7,406,349
Oil and natural gas properties and other, net	$	550,681	$	547,053

Schedule of Accrued Liabilities

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

	June 30,		December 31,
	2017		2016
Accrued interest	$	4,196	$	4,189
Accrued salaries/payroll taxes/benefits		4,627		2,777
Other		4,299		2,234
Total accrued liabilities	$	13,122	$	9,200

Schedule of Other Assets (Long-term)

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

	June 30,		December 31,
	2017		2016
Escrow deposit - Apache lawsuit	$	49,500	$	—
Appeal bond deposits		6,925		6,925
Other		4,571		4,539
Total other assets	$	60,996	$	11,464

Schedule of Other Liabilities (Long-term)

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

	June 30,		December 31,
	2017		2016
Apache lawsuit	$	49,500	$	—
Uncertain tax positions including interest/penalties		10,796		10,584
Other		6,613		6,521
Total other liabilities (long-term)	$	66,909	$	17,105

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Long-Term Debt

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

	June 30, 2017								December 31, 2016
			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		—		19,709			19,709			—		23,823			23,823
Subtotal		75,000		19,709			94,709			75,000		23,823			98,823
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		163,007		—			163,007			163,007		—			163,007
Future payments-in-kind		—		14,506			14,506			—		24,048			24,048
Future interest payments		—		34,873			34,873			—		36,850			36,850
Subtotal		163,007		49,379			212,386			163,007		60,898			223,905
8.50%/10.00% Third Lien   PIK Toggle Notes, due June 2021:
Principal		145,897		—			145,897			145,897		—			145,897
Future payments-in-kind		—		18,618			18,618			—		26,844			26,844
Future interest payments		—		38,682			38,682			—		40,705			40,705
Subtotal		145,897		57,300			203,197			145,897		67,549			213,446
8.50% Unsecured Senior Notes,     due June 2019		189,829		—			189,829			189,829		—			189,829
Debt premium, discount,      issuance costs, net of amortization		—		(4,637	)		(4,637	)		—		(5,276	)		(5,276	)
Total long-term debt		873,733		121,751			995,484			873,733		146,994			1,020,727
Current maturities of long-term debt (2)		—		11,147			11,147			—		8,272			8,272
Long term debt, less current    maturities	$	873,733	$	110,604		$	984,337		$	873,733	$	138,722		$	1,012,455

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

(2) Future interest payments on the 1.5 Lien Term Loan and Second Lien PIK Toggle Notes due within twelve months.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt

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

	June 30, 2017				December 31, 2016
	Assets		Liabilities		Assets		Liabilities
Derivatives - open contracts	$	5,436	$	—	$	—	$	—
11.00% 1.5 Term Loan, due November 2019 (1)		—		75,000		—		75,000
9.00% Second Lien Term Loan, due May 2020 (1)		—		249,000		—		255,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 (1)		—		133,666		—		122,255
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 (1)		—		99,210		—		80,243
8.50% Unsecured Senior Notes, due June 2019  (1)		—		131,931		—		123,389

(1) The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2.  

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2017

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, 2016	$	334,438
Liabilities settled		(36,021	)
Accretion of discount		8,560
Revisions of estimated liabilities (1)		10,883
Balance, June 30, 2017		317,860
Less current portion		52,432
Long-term	$	265,428

(1) Revisions were primarily related to changes from sustained casing pressure at four fields.  Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project.  

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Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Open Commodity Derivatives

As of June 30, 2017, our open commodity derivative contracts were as follows:

Crude Oil:  Swap, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)
		Quantity		Quantity		Strike
Termination Period		(Bbls/day)		(Bbls)		Price
2017	4th Quarter		1,000		184,000	$	55.25
Crude Oil:  Two-way collars, Priced off WTI (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(Bbls/day)		(Bbls)		(Bought)		(Sold)
2017	4th Quarter		4,000		736,000	$	50.00	$	60.15
Natural Gas:  Two-way collars, Priced off Henry Hub (NYMEX)
		Notional (1)		Notional (1)		Weighted Average Contract Price
		Quantity		Quantity		Put Option		Call Option
Termination Period		(MMBtu's/day)		(MMBtu's)		(Bought)		(Sold)
2017	4th Quarter (2)		30,000		4,590,000	$	3.07	$	3.96

(1) Volume Measurements:   Bbls – barrelsMMBtu’s – million British Thermal Units.

(2) The natural gas derivative contracts are priced and closed in the last week prior to the related production month.  Natural gas derivative contracts related to July 2017 production were priced and closed in June 2017 and are not included in the above table as these were not open derivative contracts as of June 30, 2017.

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

Our open and closed (not settled) commodity derivative contracts were recorded within the line Prepaid expenses and other assets on the Condensed Consolidated Balance Sheets summarized in the following table (in thousands):

	June 30,		December 31,
	2017		2016
Open contracts	$	5,436	$	—
Closed contracts - not settled		929		—
Total contracts	$	6,365	$	—

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					Six Months Ended
	June 30,					June 30,
	2017			2016		2017			2016
Derivative (gain) loss	$	(3,689	)	$	4,942	$	(7,644	)	$	2,449

Cash Receipts on Derivative Settlements, Net Included within Net Cash Provided by (Used in) Operating Activities

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

	Six Months Ended
	June 30,
	2017		2016
Cash receipts on derivative settlements, net	$	2,208	$	4,746

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

6 Months Ended

Jun. 30, 2017

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 six months ended June 30, 2017 is as follows:

	Restricted Stock Units
				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Nonvested, December 31, 2016		6,107,248		$	2.73
Granted		2,080,181			2.77
Vested		(323,870	)		2.73
Forfeited		(268,173	)		2.77
Nonvested, June 30, 2017		7,595,386			2.74

Schedule of Outstanding Restricted Stock Units Issued to Eligible Employees

For the outstanding RSUs issued to the eligible employees as of June 30, 2017, vesting is expected to occur as follows:  

	Restricted Stock Units
2017		2,108,397
2018		3,477,267
2019		2,009,722
Total		7,595,386

Schedule of Restricted Stock Activity

A summary of activity related to Restricted Shares during the six months ended June 30, 2017 is as follows:

	Restricted Shares
				Weighted Average
				Grant Date Fair
	Shares			Value Per Share
Nonvested, December 31, 2016		161,296		$	3.47
Granted		147,372			1.90
Vested		(62,140	)		4.51
Nonvested, June 30, 2017		246,528			2.27

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

For the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2017, vesting is expected to occur as follows:

	Restricted Shares
2018		106,240
2019		91,164
2020		49,124
Total		246,528

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				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation expense from:
Restricted stock units	$	2,342	$	2,439	$	4,200	$	4,888
Restricted Shares		70		146		140		233
Total	$	2,412	$	2,585	$	4,340	$	5,121
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	844	$	904	$	1,519	$	1,792

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				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Share-based compensation included in:
General and administrative expenses	$	2,412	$	2,585	$	4,340	$	5,121
Cash-based incentive compensation included in:
Lease operating expense		394		—		394		364
General and administrative expenses		1,004		—		1,004		(233	)
Total charged to operating income	$	3,810	$	2,585	$	5,738	$	5,252

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Earnings/ (Loss) Per Share (Tables)

6 Months Ended

Jun. 30, 2017

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 (loss) per common share (in thousands, except per share amounts):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
Net income (loss)	$	33,315	$	(120,922	)	$	57,614	$	(311,431	)
Less portion allocated to nonvested shares		1,374		—			2,442		—
Net income (loss) allocated to common shares	$	31,941	$	(120,922	)	$	55,172	$	(311,431	)
Weighted average common shares outstanding		137,552		76,457			137,533		76,443
Basic and diluted earnings (loss) per common share	$	0.23	$	(1.58	)	$	0.40	$	(4.07	)
Shares excluded due to being anti-dilutive (weighted-average)		—		3,531			—		3,529

XML

Supplemental Guarantor Information (Tables)

6 Months Ended

Jun. 30, 2017

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 to the ceiling test write-down recorded in 2016, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company.  Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately.  

Condensed Consolidating Balance Sheet as of June 30, 2017

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	72,320		$	—		$	—		$	72,320
Receivables:
Oil and natural gas sales		3,268			36,129			—			39,397
Joint interest		19,920			—			—			19,920
Income taxes		119,732			—			(107,705	)		12,027
Total receivables		142,920			36,129			(107,705	)		71,344
Prepaid expenses and other assets		19,480			2,464			—			21,944
Total current assets		234,720			38,593			(107,705	)		165,608
Oil and natural gas properties and other, net		392,445			160,708			(2,472	)		550,681
Restricted deposits for asset retirement obligations		28,712			—			—			28,712
Income tax receivables		68,974			—			—			68,974
Other assets		481,201			418,924			(839,129	)		60,996
Total assets	$	1,206,052		$	618,225		$	(949,306	)	$	874,971
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	51,932		$	6,351		$	—		$	58,283
Undistributed oil and natural gas proceeds		19,626			1,644			—			21,270
Asset retirement obligations		44,776			7,656			—			52,432
Long-term debt		11,147			—			—			11,147
Accrued liabilities		13,122			107,705			(107,705	)		13,122
Total current liabilities		140,603			123,356			(107,705	)		156,254
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		110,604			—			—			110,604
Long term debt, less current portion - carrying value		984,337			—			—			984,337
Asset retirement obligations, less current portion		144,292			121,136			—			265,428
Other liabilities		532,305			—			(465,396	)		66,909
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		543,439			704,885			(704,885	)		543,439
Retained earnings (deficit)		(1,114,758	)		(331,152	)		328,680			(1,117,230	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(595,485	)		373,733			(376,205	)		(597,957	)
Total liabilities and shareholders’ equity (deficit)	$	1,206,052		$	618,225		$	(949,306	)	$	874,971

Condensed Consolidating Balance Sheet as of December 31, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	70,236		$	—		$	—		$	70,236
Receivables:
Oil and natural gas sales		2,173			40,900			—			43,073
Joint interest		21,885			—			—			21,885
Insurance reimbursement		30,100			—			—			30,100
Income taxes		111,215			—			(99,272	)		11,943
Total receivables		165,373			40,900			(99,272	)		107,001
Prepaid expenses and other assets		12,448			2,056			—			14,504
Total current assets		248,057			42,956			(99,272	)		191,741
Oil and natural gas properties and other, net		360,966			187,040			(953	)		547,053
Restricted deposits for asset retirement obligations		27,371			—			—			27,371
Income tax receivables		52,097			—			—			52,097
Other assets		394,931			344,742			(728,209	)		11,464
Total assets	$	1,083,422		$	574,738		$	(828,434	)	$	829,726
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	74,306		$	6,733		$	—		$	81,039
Undistributed oil and natural gas proceeds		24,493			1,761			—			26,254
Asset retirement obligations		62,261			16,003			—			78,264
Long-term debt		8,272			—			—			8,272
Accrued liabilities		9,293			99,179			(99,272	)		9,200
Total current liabilities		178,625			123,676			(99,272	)		203,029
Long-term debt:
Principal		873,733			—			—			873,733
Carrying value adjustments		138,722			—			—			138,722
Long term debt, less current portion - carrying value		1,012,455			—			—			1,012,455
Asset retirement obligations, less current portion		142,376			113,798			—			256,174
Other liabilities		408,050			—			(390,945	)		17,105
Shareholders’ deficit:
Common stock		1			—			—			1
Additional paid-in capital		539,973			704,885			(704,885	)		539,973
Retained earnings (deficit)		(1,173,891	)		(367,621	)		366,668			(1,174,844	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ deficit		(658,084	)		337,264			(338,217	)		(659,037	)
Total liabilities and shareholders’ deficit	$	1,083,422		$	574,738		$	(828,434	)	$	829,726

Condensed Consolidating Statement of Operations

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

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	57,417		$	65,906	$	—		$	123,323
Operating costs and expenses:
Lease operating expenses		17,325			14,194		—			31,519
Production taxes		449			—		—			449
Gathering and transportation		2,578			2,740		—			5,318
Depreciation, depletion, amortization and accretion		21,433			18,143		788			40,364
General and administrative expenses		7,662			8,812		—			16,474
Derivative gain		(3,689	)		—		—			(3,689	)
Total costs and expenses		45,758			43,889		788			90,435
Operating income		11,659			22,017		(788	)		32,888
Earnings of affiliates		18,941			—		(18,941	)		—
Interest expense incurred		11,436			—		—			11,436
Gain on exchange of debt		8,056			—		—			8,056
Other expense, net		5,168			—		—			5,168
Income before income tax benefit		22,052			22,017		(19,729	)		24,340
Income tax benefit		(12,051	)		3,076		—			(8,975	)
Net income	$	34,103		$	18,941	$	(19,729	)	$	33,315

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2017

									Consolidated
	Parent			Guarantor					W&T
	Company			Subsidiaries		Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	111,124		$	136,592	$	—		$	247,716
Operating costs and expenses:
Lease operating expenses		41,027			30,656		—			71,683
Production taxes		964			—		—			964
Gathering and transportation		5,144			6,383		—			11,527
Depreciation, depletion, amortization and accretion		40,587			38,248		1,519			80,354
General and administrative expenses		13,438			16,310		—			29,748
Derivative gain		(7,644	)		—		—			(7,644	)
Total costs and expenses		93,516			91,597		1,519			186,632
Operating income		17,608			44,995		(1,519	)		61,084
Earnings of affiliates		36,468			—		(36,468	)		—
Interest expense incurred		22,730			—		—			22,730
Gain on exchange of debt		7,811			—		—			7,811
Other expense, net		5,114			—		—			5,114
Income before income tax benefit		34,043			44,995		(37,987	)		41,051
Income tax benefit		(25,090	)		8,527		—			(16,563	)
Net income	$	59,133		$	36,468	$	(37,987	)	$	57,614

Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	43,914		$	55,741		$	—		$	99,655
Operating costs and expenses:
Lease operating expenses		19,254			17,368			—			36,622
Production taxes		370			—			—			370
Gathering and transportation		2,469			3,929			—			6,398
Depreciation, depletion, amortization and accretion		22,648			31,934			2,911			57,493
Ceiling test write-down of oil and natural gas    properties		—			35,008			69,584			104,592
General and administrative expenses		7,360			8,875			—			16,235
Derivative loss		4,942			—			—			4,942
Total costs and expenses		57,043			97,114			72,495			226,652
Operating loss		(13,129	)		(41,373	)		(72,495	)		(126,997	)
Loss of affiliates		(40,765	)		—			40,765			—
Interest expense:
Incurred		29,735			38			—			29,773
Capitalized		(64	)		(38	)		—			(102	)
Other expense, net		(24	)		—			—			(24	)
Loss before income tax benefit		(83,541	)		(41,373	)		(31,730	)		(156,644	)
Income tax benefit		(35,114	)		(608	)		—			(35,722	)
Net loss	$	(48,427	)	$	(40,765	)	$	(31,730	)	$	(120,922	)

Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.
	(In thousands)
Revenues	$	74,426		$	102,944		$	—		$	177,370
Operating costs and expenses:
Lease operating expenses		44,199			36,892			—			81,091
Production taxes		896			—			—			896
Gathering and transportation		4,022			7,468			—			11,490
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas    properties		—			85,392			135,759			221,151
General and administrative expenses		13,973			18,705			—			32,678
Derivative loss		2,449			—			—			2,449
Total costs and expenses		108,810			218,552			143,619			470,981
Operating loss		(34,384	)		(115,608	)		(143,619	)		(293,611	)
Loss of affiliates		(113,794	)		—			113,794			—
Interest expense:
Incurred		57,430			157			—			57,587
Capitalized		(288	)		(157	)		—			(445	)
Other expense, net		1,282			—			—			1,282
Loss before income tax benefit		(206,602	)		(115,608	)		(29,825	)		(352,035	)
Income tax benefit		(38,790	)		(1,814	)		—			(40,604	)
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2017

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net income	$	59,133		$	36,468		$	(37,987	)	$	57,614
Adjustments to reconcile net income to net cash   provided by  operating activities:
Depreciation, depletion, amortization and accretion		40,587			38,248			1,519			80,354
Gain on exchange of debt		(7,811	)		—			—			(7,811	)
Amortization of debt items		836			—			—			836
Share-based compensation		3,466			—			—			3,466
Derivative gain		(7,644	)		—			—			(7,644	)
Cash receipts on derivative settlements, net		2,208			—			—			2,208
Deferred income taxes		212			—			—			212
Earnings of affiliates		(36,468	)		—			36,468			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(1,095	)		4,770			—			3,675
Joint interest receivables		1,965			—			—			1,965
Insurance reimbursements		30,100			—			—			30,100
Income taxes		(25,487	)		8,527			—			(16,960	)
Prepaid expenses and other assets		(3,165	)		(74,591	)		74,181			(3,575	)
Escrow deposit - Apache lawsuit		(49,500	)		—			—			(49,500	)
Asset retirement obligation settlements		(25,044	)		(10,977	)		—			(36,021	)
Accounts payable, accrued liabilities and other		81,785			(938	)		(74,181	)		6,666
Net cash provided by operating activities		64,078			1,507			—			65,585
Investing activities:
Investment in oil and natural gas properties and equipment		(41,854	)		(1,946	)		—			(43,800	)
Changes in operating assets and liabilities associated with    investing activities		(1,266	)		439			—			(827	)
Purchases of furniture, fixtures and other		(853	)		—			—			(853	)
Net cash used in investing activities		(43,973	)		(1,507	)		—			(45,480	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(4,113	)		—			—			(4,113	)
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 provided by financing activities		(18,021	)		—			—			(18,021	)
Increase in cash and cash equivalents		2,084			—			—			2,084
Cash and cash equivalents, beginning of period		70,236			—			—			70,236
Cash and cash equivalents, end of period	$	72,320		$	—		$	—		$	72,320

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2016

										Consolidated
										W&T
	Parent			Guarantor						Offshore,
	Company			Subsidiaries			Eliminations			Inc.
	(In thousands)
Operating activities:
Net loss	$	(167,812	)	$	(113,794	)	$	(29,825	)	$	(311,431	)
Adjustments to reconcile net loss to net cash    provided by operating activities:
Depreciation, depletion, amortization and accretion		43,271			70,095			7,860			121,226
Ceiling test write-down of oil and natural gas properties		—			85,392			135,759			221,151
Debt issuance costs write-off/ amortization of debt items		1,880			—			—			1,880
Share-based compensation		5,121			—			—			5,121
Derivative gain		2,449			—			—			2,449
Cash receipts on derivative settlements		4,746			—			—			4,746
Deferred income taxes		21,099			(1,814	)		—			19,285
Loss of affiliates		113,794			—			(113,794	)		—
Changes in operating assets and liabilities:
Oil and natural gas receivables		1,177			49			—			1,226
Joint interest receivables		1,763			—			—			1,763
Income taxes		(57,931	)		—			—			(57,931	)
Prepaid expenses and other assets		(9,405	)		(17,424	)		16,464			(10,365	)
Asset retirement obligations		(12,702	)		(12,454	)		—			(25,156	)
Accounts payable, accrued liabilities and other		(783	)		32,014			(16,464	)		14,767
Net cash provided by operating activities		(53,333	)		42,064			—			(11,269	)
Investing activities:
Investment in oil and natural gas properties and equipment		(8,600	)		(9,112	)		—			(17,712	)
Changes in operating assets and liabilities associated with    investing activities		(670	)		(33,452	)		—			(34,122	)
Proceeds from sales of assets		1,000			500			—			1,500
Purchases of furniture, fixtures and other		(70	)		—			—			(70	)
Net cash used in investing activities		(8,340	)		(42,064	)		—			(50,404	)
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		340,000			—			—			340,000
Repayments of long-term debt – revolving bank credit facility		(192,000	)		—			—			(192,000	)
Other		83			—			—			83
Net cash provided by financing activities		148,083			—			—			148,083
Increase in cash and cash equivalents		86,410			—			—			86,410
Cash and cash equivalents, beginning of period		85,414			—			—			85,414
Cash and cash equivalents, end of period	$	171,824		$	—		$	—		$	171,824

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Basis of Presentation - Additional Information (Details)	Jun. 30, 2017 USD ($) Loan	Dec. 31, 2016 USD ($)	Mar. 31, 2016 USD ($)
Basis Of Presentation [Line Items]
Number of loans for which maturities will be accelerated | Loan	2
Obligation to secure financial assurances			$ 260,800,000
Escrow deposit	$ 49,500,000
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization	0	$ 0
Apache Corporation
Basis Of Presentation [Line Items]
Escrow deposit	$ 49,500,000

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Basis of Presentation - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016
Prepaid Expense And Other Assets Current [Abstract]
Derivative assets	[1]	$ 6,365
Prepaid/accrued insurance		3,802	$ 2,924
Surety bond unamortized premiums		2,855	2,462
Prepaid deposits related to royalties		6,155	6,237
Other		2,767	2,881
Prepaid expenses and other assets		$ 21,944	$ 14,504

[1] Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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Basis of Presentation - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Property Plant And Equipment Net [Abstract]
Oil and natural gas properties and equipment	$ 8,007,073	$ 7,932,504
Furniture, fixtures and other	21,751	20,898
Total property and equipment	8,028,824	7,953,402
Less accumulated depreciation, depletion and amortization	7,478,143	7,406,349
Oil and natural gas properties and other, net	$ 550,681	$ 547,053

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Basis of Presentation - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Accrued interest	$ 4,196	$ 4,189
Accrued salaries/payroll taxes/benefits	4,627	2,777
Other	4,299	2,234
Total accrued liabilities	$ 13,122	$ 9,200

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Basis of Presentation - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Other Assets [Abstract]
Escrow deposit	$ 49,500
Appeal bond deposits	6,925	$ 6,925
Other	4,571	4,539
Total other assets	$ 60,996	$ 11,464

XML

Basis of Presentation - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Apache lawsuit	$ 49,500
Uncertain tax positions including interest/penalties	10,796	$ 10,584
Other	6,613	6,521
Total other liabilities (long-term)	$ 66,909	$ 17,105

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Long-Term Debt - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Principal	$ 873,733	$ 873,733
Adjustments to carrying value, Debt premium, discount, issuance costs, net of amortization	(4,637)	(5,276)
Adjustments to carrying value, Total	121,751	146,994
Adjustments to carrying value, Current maturities	11,147	8,272
Adjustments to carrying value, less current maturities	110,604	138,722
Debt premium, discount, issuance costs, net of amortization	(4,637)	(5,276)
Total long-term debt	995,484	1,020,727
Long-term debt	11,147	8,272
Long term debt, less current maturities	984,337	1,012,455
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	19,709	23,823
Adjustments to carrying value, Subtotal	19,709	23,823
Carrying Value	94,709	98,823
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	163,007	163,007
Adjustments to carrying value, Future payments-in-kind	14,506	24,048
Adjustments to carrying value, Future interest payments	34,873	36,850
Adjustments to carrying value, Subtotal	49,379	60,898
Carrying Value	212,386	223,905
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Principal	145,897	145,897
Adjustments to carrying value, Future payments-in-kind	18,618	26,844
Adjustments to carrying value, Future interest payments	38,682	40,705
Adjustments to carrying value, Subtotal	57,300	67,549
Carrying Value	$ 203,197	$ 213,446

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Long-Term Debt - Components of Long-Term Debt (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	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%
Debt instrument maturity date	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%
Debt instrument maturity date	May 15, 2020
Debt instrument paid in kind interest rate	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%
Debt instrument maturity date	Jun. 15, 2021
Debt instrument paid in kind interest rate	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 ($) shares in Millions			1 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Sep. 07, 2016	May 31, 2015	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 873,733,000			$ 873,733,000	$ 873,733,000
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 189,829,000			$ 189,829,000	$ 189,829,000
Debt instrument maturity date				Jun. 15, 2019	Jun. 15, 2019
Debt instrument interest rate	8.50%			8.50%	8.50%
Debt instrument payment terms				semi-annually in arrears on June 15 and December 15
Annual effective interest rate	8.30%			8.30%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 163,007,000			$ 163,007,000	$ 163,007,000
Debt instrument maturity date				May 15, 2020
Debt instrument interest rate	9.00%	9.00%		9.00%
Debt instrument paid in kind interest rate	10.75%			10.75%
Debt instrument payment terms				Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year. The Second Lien PIK Toggle Notes contain provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period. For the initial interest period ending November 15, 2016, interest could only be paid-in-kind at the annual rate of 10.75%. For interest periods through March 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.75% per annum.
Debt instrument stated interest rate percentage for payment-in-kind		10.75%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Minimum
Debt Instrument [Line Items]
Cash interest payable stub period				Mar. 07, 2018
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Maximum
Debt Instrument [Line Items]
Cash interest payable stub period				May 15, 2018
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 145,897,000			$ 145,897,000	145,897,000
Debt instrument maturity date				Jun. 15, 2021
Debt instrument interest rate	8.50%	8.50%		8.50%
Debt instrument paid in kind interest rate	10.00%			10.00%
Debt instrument payment terms				The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year. The Third Lien PIK Toggle Notes contain interest provisions whereby certain semi-annual interest is added to the principal amount through payment-in-kind instead of being paid in cash in the then current semi-annual period. For the initial interest period ending December 15, 2016, interest could only be paid in kind at the annual rate of 10.00%. For interest periods through September 7, 2018, if we so elect, we have the option to pay all or a portion of interest in kind at a rate of 10.00% per annum.
Debt instrument stated interest rate percentage for payment-in-kind		10.00%
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 75,000,000			$ 75,000,000	75,000,000
Debt instrument maturity date				Nov. 15, 2019
Debt instrument interest rate	11.00%			11.00%
Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes
Debt Instrument [Line Items]
Net reduction to long term debt	$ 8,200,000			$ 8,200,000
Revolving Bank Credit Facility Due November 2018
Debt Instrument [Line Items]
Revolving bank credit facility borrowing base	150,000,000			150,000,000
Revolving bank credit facility maximum lender commitment	$ 150,000,000			$ 150,000,000
First lien leverage ratio, through June 30, 2017				250.00%
First lien leverage ratio, after June 30, 2017	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	300,000			300,000	500,000
Remaining availability	149,700,000			149,700,000
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]
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 maturity date		Nov. 15, 2019
Debt instrument interest rate		11.00%
Debt instrument payment terms				Interest accrues 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 on September 7, 2016 with a maturity date of November 15, 2019. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 300,000,000			$ 300,000,000	$ 300,000,000
Debt instrument maturity date				May 15, 2020	May 15, 2020
Debt instrument interest rate	9.00%		9.00%	9.00%	9.00%
Debt instrument payment terms				Interest on the Second Lien Term Loan is 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%
Exchange Transaction
Debt Instrument [Line Items]
Additional expense charged to gain on exchange of debt				$ 400,000
Exchange Transaction | 8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument aggregate principal amount		$ 710,200,000
Percentage of unsecured senior notes exchanged		79.00%
Debt instrument maturity date				Jun. 15, 2019
Exchange Transaction | 8.50% Unsecured Senior Notes, Due June 2019 | Common Stock
Debt Instrument [Line Items]
Debt conversion, common stock shares issued		60.4
Exchange Transaction | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principal amount		$ 159,800,000
Debt instrument maturity date				May 15, 2020
Exchange Transaction | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate		9.00%
Exchange Transaction | 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%
Exchange Transaction | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument aggregate principal amount		$ 142,000,000
Debt instrument maturity date				Jun. 15, 2021
Exchange Transaction | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate		8.50%
Exchange Transaction | 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%
Exchange Transaction | 11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument aggregate principal amount		$ 75,000,000
Debt instrument maturity date				Nov. 15, 2019
Debt instrument interest rate		11.00%
Exchange Transaction | 1.5 Lien Term Loan
Debt Instrument [Line Items]
Interest expense recorded for new debt				$ 0

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Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt (Details) - Fair Value, Inputs, Level 2 - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of commodity derivative contracts		$ 5,436
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	[1]	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	[1]	249,000	255,000
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	[1]	133,666	122,255
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	[1]	99,210	80,243
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	[1]	$ 131,931	$ 123,389

[1] The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 2.

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Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	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%
Debt instrument maturity date	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%
Debt instrument maturity date	May 15, 2020
Debt instrument paid in kind interest rate	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%
Debt instrument maturity date	Jun. 15, 2021
Debt instrument paid in kind interest rate	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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Asset Retirement Obligations - Summary of Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period		$ 334,438
Asset retirement obligation settlements		(36,021)	$ (25,156)
Accretion of discount		8,560
Revisions of estimated liabilities	[1]	10,883
Asset retirement obligations, end of period		317,860
Less current portion		52,432		$ 78,264
Long-term		$ 265,428		$ 256,174

[1] Revisions were primarily related to changes from sustained casing pressure at four fields. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project.

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Derivative Financial Instruments - Open Commodity Derivatives (Details)	6 Months Ended
	Jun. 30, 2017 MMBTU $ / Derivative bbl
NYMEX Crude Oil - Swap
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter
Notional Quantity (Bbls/day) | bbl	1,000	[1]
Notional Quantity (Bbls) | bbl	184,000	[1]
Strike Price	55.25
NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter
Notional Quantity (Bbls/day) | bbl	4,000	[1]
Notional Quantity (Bbls) | bbl	736,000	[1]
NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	50.00
NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	60.15
NYMEX Natural Gas - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter (2)	[2]
Notional Quantity (MMBtu's/day) | MMBTU	30,000	[1]
Notional Quantity (MMBtu's) | MMBTU	4,590,000	[1]
NYMEX Natural Gas - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.07
NYMEX Natural Gas - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.96

[1] Volume Measurements: Bbls – barrelsMMBtu’s – million British Thermal Units.

[2] The natural gas derivative contracts are priced and closed in the last week prior to the related production month. Natural gas derivative contracts related to July 2017 production were priced and closed in June 2017 and are not included in the above table as these were not open derivative contracts as of June 30, 2017.

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Derivative Financial Instruments - Summary of Open and Closed (Not Settled) Commodity Derivative Contracts (Details) $ in Thousands	Jun. 30, 2017 USD ($)
Derivatives Fair Value [Line Items]
Derivative assets	$ 6,365	[1]
Open Contracts
Derivatives Fair Value [Line Items]
Derivative assets	5,436
Closed Contracts - Not Settled
Derivatives Fair Value [Line Items]
Derivative assets	$ 929

[1] Includes open and closed (and not settled) derivative commodity contracts recorded at fair value.

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Derivative Financial Instruments - Changes in Fair Value and Settlements of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ (3,689)	$ 4,942	$ (7,644)	$ 2,449

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Derivative Financial Instruments - Cash Receipts on Derivative Settlements, Net Included within Net Cash Provided by (Used in) Operating Activities (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts on derivative settlements, net	$ 2,208	$ 4,746

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Share-Based Compensation and Cash-Based Incentive Compensation - Additional Information (Details) - USD ($)	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans	14,633,337
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value	$ 5,800,000
Unrecognized share-based compensation expense	$ 9,700,000
Recognition period for unrecognized compensation expense	2019-11
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value	$ 300,000
Unrecognized share-based compensation expense	$ 500,000
Recognition period for unrecognized compensation expense	2019-04
Cash-Based Incentive Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense	$ 200,000,000	$ 300,000,000	$ 300,000,000
2010 Restated Incentive Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amendment increased the number of shares available in the Plan	7,700,000
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans	170,524

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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)	6 Months Ended
	Jun. 30, 2017 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	6,107,248
Granted | shares	2,080,181
Vested | shares	(323,870)
Forfeited | shares	(268,173)
Nonvested, end of period | shares	7,595,386
Weighted Average Grant Date Value, Beginning of period | $ / shares	$ 2.73
Weighted Average Grant Date Fair Value, Granted | $ / shares	2.77
Weighted Average Grant Date Fair Value, Vested | $ / shares	2.73
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	2.77
Weighted Average Grant Date Value, End of period | $ / shares	$ 2.74

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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	Jun. 30, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	7,595,386	6,107,248
2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	2,108,397
2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	3,477,267
2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	2,009,722

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Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) - Restricted Shares	6 Months Ended
	Jun. 30, 2017 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	161,296
Granted | shares	147,372
Vested | shares	(62,140)
Nonvested, end of period | shares	246,528
Weighted Average Grant Date Value, Beginning of period | $ / shares	$ 3.47
Weighted Average Grant Date Fair Value, Granted | $ / shares	1.90
Weighted Average Grant Date Fair Value, Vested | $ / shares	4.51
Weighted Average Grant Date Value, End of period | $ / shares	$ 2.27

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Share-Based Compensation and Cash-Based Incentive Compensation - Outstanding Restricted Shares Issued to Non-employee Directors (Details) - Restricted Shares - shares	Jun. 30, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	246,528	161,296
2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	106,240
2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	91,164
2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	49,124

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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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 2,412	$ 2,585	$ 4,340	$ 5,121
Tax benefit computed at the statutory rate	844	904	1,519	1,792
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	2,342	2,439	4,200	4,888
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 70	$ 146	$ 140	$ 233

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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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Employee Service Share Based And Cash Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income	$ 2,412	$ 2,585	$ 4,340	$ 5,121
Total charged to operating income	3,810	2,585	5,738	5,252
General And Administrative Expense
Employee Service Share Based And Cash Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income	2,412	$ 2,585	4,340	5,121
Cash-based incentive compensation charged to operating income	1,004		1,004	(233)
Lease Operating Expense
Employee Service Share Based And Cash Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income	$ 394		$ 394	$ 364

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Income Taxes - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 31, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax benefit		$ (8,975,000)	$ (35,722,000)	$ (16,563,000)	$ (40,604,000)
Cash paid for income taxes				0	300,000
Income tax refund received				0	$ 2,300,000
Current income tax receivables		12,027,000		12,027,000		$ 11,943,000
Non-current income tax receivables		68,974,000		68,974,000		52,097,000
Valuation allowance		$ 270,400,000		$ 270,400,000		$ 290,200,000
Minimum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination				2013
Maximum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination				2016
Subsequent Event
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax refund received	$ 11,900,000

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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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ 33,315	$ (120,922)	$ 57,614	$ (311,431)
Less portion allocated to nonvested shares	1,374		2,442
Net income (loss) allocated to common shares	$ 31,941	$ (120,922)	$ 55,172	$ (311,431)
Weighted average common shares outstanding	137,552	76,457	137,533	76,443
Basic and diluted earnings (loss) per common share	$ 0.23	$ (1.58)	$ 0.40	$ (4.07)
Shares excluded due to being anti-dilutive (weighted-average)		3,531		3,529

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Contingencies - Additional Information (Details)				1 Months Ended	3 Months Ended	6 Months Ended
	Jan. 27, 2017 USD ($)	Oct. 28, 2016 USD ($)	Dec. 15, 2014 USD ($) DeepwaterWell	Jan. 31, 2014 USD ($)	Mar. 31, 2014 USD ($)	Jun. 30, 2017 USD ($) claim	Jun. 28, 2017 USD ($)	May 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2010 USD ($)
Loss Contingencies [Line Items]
Obligation to secure financial assurances									$ 260,800,000
Notified rescind of obligation to secure financial assurances							$ 260,800,000
Outstanding obligation to secure financial assurances upon rescindment						$ 0
Number of deepwater wells abandoned | DeepwaterWell			3
Escrow deposit						49,500,000
Loss contingency accrued amount						49,500,000
Underpayment of royalties				$ 30,000
Under payment percentage of total royalty payments				0.0045%
Statutory fine payment relative to underpayment					$ 2,300,000	$ 1,100,000
Notified disallowed amount in reductions taken by ONRR										$ 4,700,000
Payments for royalty	$ 4,700,000
Royalty payment processing revised period						84 months
Additional royalty payment						$ 1,100,000
BSEE
Loss Contingencies [Line Items]
Loss contingency accrued amount						$ 3,300,000
Number of notices | claim						5
Proposed civil penalties related to various incidents of noncompliance, total						$ 7,500,000
Payments for civil penalty						100,000
Increase in estimated liability						1,800,000
Apache Corporation
Loss Contingencies [Line Items]
Escrow deposit						49,500,000
Apache Corporation | Judicial Ruling
Loss Contingencies [Line Items]
Amount awarded for non-compliance fines and lawsuits		$ 43,200,000	$ 24,900,000
Amount offset against litigation compensation amount		$ 17,000,000
Amount owed to Apache under judicial decision								$ 43,200,000
Prejudgment interest, attorney fees and judgment costs						6,300,000
Apache Corporation | Judicial Ruling | Other Income/Expense
Loss Contingencies [Line Items]
Recognized prejudgment interest, attorney fees and judgment costs.						6,300,000
Apache Corporation | Judicial Ruling | Asset Retirement Obligation
Loss Contingencies [Line Items]
Capitalized loss contingency damages payable to other party except attorney fees judgment costs and prejudgment interest						43,200,000
Apache Corporation | Judicial Ruling | Other Noncurrent Assets
Loss Contingencies [Line Items]
Escrow deposit								$ 49,500,000
Apache Corporation | Judicial Ruling | Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Loss contingency accrued amount						$ 49,500,000

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Subsequent Event - Additional Information (Details) $ in Millions	Jul. 31, 2017 USD ($) Order	Mar. 31, 2016 USD ($)
Subsequent Event [Line Items]
Obligation to secure financial assurances		$ 260.8
Subsequent Event
Subsequent Event [Line Items]
Obligation to secure financial assurances	$ 260.8
Number of supplemental bonding order | Order	4

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Supplemental Guarantor Information - Additional Information (Details)	Jun. 30, 2017
Debt Disclosure [Abstract]
Percentage of subsidiaries owned	100.00%

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Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 72,320	$ 70,236	$ 171,824	$ 85,414
Receivables:
Oil and natural gas sales	39,397	43,073
Joint interest	19,920	21,885
Insurance reimbursement		30,100
Income taxes	12,027	11,943
Total receivables	71,344	107,001
Prepaid expenses and other assets	21,944	14,504
Total current assets	165,608	191,741
Oil and natural gas properties and other, net	550,681	547,053
Restricted deposits for asset retirement obligations	28,712	27,371
Income tax receivables	68,974	52,097
Other assets	60,996	11,464
Total assets	874,971	829,726
Current liabilities:
Accounts payable	58,283	81,039
Undistributed oil and natural gas proceeds	21,270	26,254
Asset retirement obligations	52,432	78,264
Long-term debt	11,147	8,272
Accrued liabilities	13,122	9,200
Total current liabilities	156,254	203,029
Long-term debt:
Principal	873,733	873,733
Carrying value adjustments	110,604	138,722
Long term debt, less current portion - carrying value	984,337	1,012,455
Asset retirement obligations, less current portion	265,428	256,174
Other liabilities	66,909	17,105
Shareholders’ deficit:
Common stock	1	1
Additional paid-in capital	543,439	539,973
Retained earnings (deficit)	(1,117,230)	(1,174,844)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(597,957)	(659,037)
Total liabilities and shareholders’ equity (deficit)	874,971	829,726
Parent Company
Current assets:
Cash and cash equivalents	72,320	70,236	$ 171,824	$ 85,414
Receivables:
Oil and natural gas sales	3,268	2,173
Joint interest	19,920	21,885
Insurance reimbursement		30,100
Income taxes	119,732	111,215
Total receivables	142,920	165,373
Prepaid expenses and other assets	19,480	12,448
Total current assets	234,720	248,057
Oil and natural gas properties and other, net	392,445	360,966
Restricted deposits for asset retirement obligations	28,712	27,371
Income tax receivables	68,974	52,097
Other assets	481,201	394,931
Total assets	1,206,052	1,083,422
Current liabilities:
Accounts payable	51,932	74,306
Undistributed oil and natural gas proceeds	19,626	24,493
Asset retirement obligations	44,776	62,261
Long-term debt	11,147	8,272
Accrued liabilities	13,122	9,293
Total current liabilities	140,603	178,625
Long-term debt:
Principal	873,733	873,733
Carrying value adjustments	110,604	138,722
Long term debt, less current portion - carrying value	984,337	1,012,455
Asset retirement obligations, less current portion	144,292	142,376
Other liabilities	532,305	408,050
Shareholders’ deficit:
Common stock	1	1
Additional paid-in capital	543,439	539,973
Retained earnings (deficit)	(1,114,758)	(1,173,891)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(595,485)	(658,084)
Total liabilities and shareholders’ equity (deficit)	1,206,052	1,083,422
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	36,129	40,900
Total receivables	36,129	40,900
Prepaid expenses and other assets	2,464	2,056
Total current assets	38,593	42,956
Oil and natural gas properties and other, net	160,708	187,040
Other assets	418,924	344,742
Total assets	618,225	574,738
Current liabilities:
Accounts payable	6,351	6,733
Undistributed oil and natural gas proceeds	1,644	1,761
Asset retirement obligations	7,656	16,003
Accrued liabilities	107,705	99,179
Total current liabilities	123,356	123,676
Long-term debt:
Asset retirement obligations, less current portion	121,136	113,798
Shareholders’ deficit:
Additional paid-in capital	704,885	704,885
Retained earnings (deficit)	(331,152)	(367,621)
Total shareholders’ equity (deficit)	373,733	337,264
Total liabilities and shareholders’ equity (deficit)	618,225	574,738
Eliminations
Receivables:
Income taxes	(107,705)	(99,272)
Total receivables	(107,705)	(99,272)
Total current assets	(107,705)	(99,272)
Oil and natural gas properties and other, net	(2,472)	(953)
Other assets	(839,129)	(728,209)
Total assets	(949,306)	(828,434)
Current liabilities:
Accrued liabilities	(107,705)	(99,272)
Total current liabilities	(107,705)	(99,272)
Long-term debt:
Other liabilities	(465,396)	(390,945)
Shareholders’ deficit:
Additional paid-in capital	(704,885)	(704,885)
Retained earnings (deficit)	328,680	366,668
Total shareholders’ equity (deficit)	(376,205)	(338,217)
Total liabilities and shareholders’ equity (deficit)	$ (949,306)	$ (828,434)

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Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Condensed Income Statements Captions [Line Items]
Revenues	$ 123,323	$ 99,655	$ 247,716	$ 177,370
Operating costs and expenses:
Lease operating expenses	31,519	36,622	71,683	81,091
Production taxes	449	370	964	896
Gathering and transportation	5,318	6,398	11,527	11,490
Depreciation, depletion, amortization and accretion	40,364	57,493	80,354	121,226
Ceiling test write-down of oil and natural gas properties		104,592		221,151
General and administrative expenses	16,474	16,235	29,748	32,678
Derivative (gain) loss	(3,689)	4,942	(7,644)	2,449
Total costs and expenses	90,435	226,652	186,632	470,981
Operating income (loss)	32,888	(126,997)	61,084	(293,611)
Interest expense:
Incurred	11,436	29,773	22,730	57,587
Capitalized		(102)		(445)
Gain on exchange of debt	8,056		7,811
Other expense, net	5,168	(24)	5,114	1,282
Income (loss) before income tax benefit	24,340	(156,644)	41,051	(352,035)
Income tax benefit	(8,975)	(35,722)	(16,563)	(40,604)
Net income (loss)	33,315	(120,922)	57,614	(311,431)
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues	57,417	43,914	111,124	74,426
Operating costs and expenses:
Lease operating expenses	17,325	19,254	41,027	44,199
Production taxes	449	370	964	896
Gathering and transportation	2,578	2,469	5,144	4,022
Depreciation, depletion, amortization and accretion	21,433	22,648	40,587	43,271
General and administrative expenses	7,662	7,360	13,438	13,973
Derivative (gain) loss	(3,689)	4,942	(7,644)	2,449
Total costs and expenses	45,758	57,043	93,516	108,810
Operating income (loss)	11,659	(13,129)	17,608	(34,384)
Earnings (loss) of affiliates	18,941	(40,765)	36,468	(113,794)
Interest expense:
Incurred	11,436	29,735	22,730	57,430
Capitalized		(64)		(288)
Gain on exchange of debt	8,056		7,811
Other expense, net	5,168	(24)	5,114	1,282
Income (loss) before income tax benefit	22,052	(83,541)	34,043	(206,602)
Income tax benefit	(12,051)	(35,114)	(25,090)	(38,790)
Net income (loss)	34,103	(48,427)	59,133	(167,812)
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues	65,906	55,741	136,592	102,944
Operating costs and expenses:
Lease operating expenses	14,194	17,368	30,656	36,892
Gathering and transportation	2,740	3,929	6,383	7,468
Depreciation, depletion, amortization and accretion	18,143	31,934	38,248	70,095
Ceiling test write-down of oil and natural gas properties		35,008		85,392
General and administrative expenses	8,812	8,875	16,310	18,705
Total costs and expenses	43,889	97,114	91,597	218,552
Operating income (loss)	22,017	(41,373)	44,995	(115,608)
Interest expense:
Incurred		38		157
Capitalized		(38)		(157)
Income (loss) before income tax benefit	22,017	(41,373)	44,995	(115,608)
Income tax benefit	3,076	(608)	8,527	(1,814)
Net income (loss)	18,941	(40,765)	36,468	(113,794)
Eliminations
Operating costs and expenses:
Depreciation, depletion, amortization and accretion	788	2,911	1,519	7,860
Ceiling test write-down of oil and natural gas properties		69,584		135,759
Total costs and expenses	788	72,495	1,519	143,619
Operating income (loss)	(788)	(72,495)	(1,519)	(143,619)
Earnings (loss) of affiliates	(18,941)	40,765	(36,468)	113,794
Interest expense:
Income (loss) before income tax benefit	(19,729)	(31,730)	(37,987)	(29,825)
Net income (loss)	$ (19,729)	$ (31,730)	$ (37,987)	$ (29,825)

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Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Operating activities:
Net income (loss)	$ 33,315	$ (120,922)	$ 57,614	$ (311,431)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	40,364	57,493	80,354	121,226
Ceiling test write-down of oil and natural gas properties		104,592		221,151
Gain on exchange of debt	(8,056)		(7,811)
Debt issuance costs write-off/ amortization of debt items			836	1,880
Share-based compensation			3,466	5,121
Derivative (gain) loss	(3,689)	4,942	(7,644)	2,449
Cash receipts on derivative settlements, net			2,208	4,746
Deferred income taxes			212	19,285
Changes in operating assets and liabilities:
Oil and natural gas receivables			3,675	1,226
Joint interest receivables			1,965	1,763
Insurance reimbursements			30,100
Income taxes			(16,960)	(57,931)
Prepaid expenses and other assets			(3,575)	(10,365)
Escrow deposit - Apache lawsuit			(49,500)
Asset retirement obligation settlements			(36,021)	(25,156)
Accounts payable, accrued liabilities and other			6,666	14,767
Net cash provided by (used in) operating activities			65,585	(11,269)
Investing activities:
Investment in oil and natural gas properties and equipment			(43,800)	(17,712)
Changes in operating assets and liabilities associated with investing activities			(827)	(34,122)
Proceeds from sales of assets				1,500
Purchases of furniture, fixtures and other			(853)	(70)
Net cash used in investing activities			(45,480)	(50,404)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility				340,000
Repayments of long-term debt - revolving bank credit facility				(192,000)
Other			(372)	83
Net cash provided by (used in) financing activities			(18,021)	148,083
Increase in cash and cash equivalents			2,084	86,410
Cash and cash equivalents, beginning of period			70,236	85,414
Cash and cash equivalents, end of period	72,320	171,824	72,320	171,824
Parent Company
Operating activities:
Net income (loss)	34,103	(48,427)	59,133	(167,812)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	21,433	22,648	40,587	43,271
Gain on exchange of debt	(8,056)		(7,811)
Debt issuance costs write-off/ amortization of debt items			836	1,880
Share-based compensation			3,466	5,121
Derivative (gain) loss	(3,689)	4,942	(7,644)	2,449
Cash receipts on derivative settlements, net			2,208	4,746
Deferred income taxes			212	21,099
Earnings (loss) of affiliates	(18,941)	40,765	(36,468)	113,794
Changes in operating assets and liabilities:
Oil and natural gas receivables			(1,095)	1,177
Joint interest receivables			1,965	1,763
Insurance reimbursements			30,100
Income taxes			(25,487)	(57,931)
Prepaid expenses and other assets			(3,165)	(9,405)
Escrow deposit - Apache lawsuit			(49,500)
Asset retirement obligation settlements			(25,044)	(12,702)
Accounts payable, accrued liabilities and other			81,785	(783)
Net cash provided by (used in) operating activities			64,078	(53,333)
Investing activities:
Investment in oil and natural gas properties and equipment			(41,854)	(8,600)
Changes in operating assets and liabilities associated with investing activities			(1,266)	(670)
Proceeds from sales of assets				1,000
Purchases of furniture, fixtures and other			(853)	(70)
Net cash used in investing activities			(43,973)	(8,340)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility				340,000
Repayments of long-term debt - revolving bank credit facility				(192,000)
Other			(372)	83
Net cash provided by (used in) financing activities			(18,021)	148,083
Increase in cash and cash equivalents			2,084	86,410
Cash and cash equivalents, beginning of period			70,236	85,414
Cash and cash equivalents, end of period	72,320	171,824	72,320	171,824
Guarantor Subsidiaries
Operating activities:
Net income (loss)	18,941	(40,765)	36,468	(113,794)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	18,143	31,934	38,248	70,095
Ceiling test write-down of oil and natural gas properties		35,008		85,392
Deferred income taxes				(1,814)
Changes in operating assets and liabilities:
Oil and natural gas receivables			4,770	49
Income taxes			8,527
Prepaid expenses and other assets			(74,591)	(17,424)
Asset retirement obligation settlements			(10,977)	(12,454)
Accounts payable, accrued liabilities and other			(938)	32,014
Net cash provided by (used in) operating activities			1,507	42,064
Investing activities:
Investment in oil and natural gas properties and equipment			(1,946)	(9,112)
Changes in operating assets and liabilities associated with investing activities			439	(33,452)
Proceeds from sales of assets				500
Net cash used in investing activities			(1,507)	(42,064)
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Payment of interest			(4,113)
11.00% 1.5 Lien Term Loan, Due November 2019 | Parent Company
Financing activities:
Payment of interest			(4,113)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest			(7,335)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Parent Company
Financing activities:
Payment of interest			(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 (loss)	(19,729)	(31,730)	(37,987)	(29,825)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	788	2,911	1,519	7,860
Ceiling test write-down of oil and natural gas properties		69,584		135,759
Earnings (loss) of affiliates	$ 18,941	$ (40,765)	36,468	(113,794)
Changes in operating assets and liabilities:
Prepaid expenses and other assets			74,181	16,464
Accounts payable, accrued liabilities and other			$ (74,181)	$ (16,464)