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~~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.

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

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

As of ~~July 31, 2018,~~April 29, 2019, there were ~~139,153,798~~140,644,033 shares outstanding of the registrant’s common stock, par value $0.00001.

	June 30,			December 31,
	2018			2017			March 31,			December 31,
	(Unaudited)						2019			2018
Assets
Current assets:
Cash and cash equivalents	$	129,440		$	99,058		$	86,116		$	33,293
Receivables:
Oil and natural gas sales		52,073			45,443			41,308			47,804
Joint interest		19,366			19,754
Joint interest, net								17,620			14,634
Income taxes		65,240			13,006			54,076			54,076
Total receivables		136,679			78,203			113,004			116,514
Prepaid expenses and other assets (Note 1)		20,470			13,419			34,127			76,406
Total current assets		286,589			190,680			233,247			226,213

Oil and natural gas properties and other, net - at cost: (Note 1)		576,073			579,016
Oil and natural gas properties and other, net - at cost (Note 1)								514,765			515,421
Restricted deposits for asset retirement obligations		26,072			25,394			15,498			15,685
Income taxes receivable		—			52,097
Other assets (Note 1)		69,418			60,393			79,005			91,547
Total assets	$	958,152		$	907,580		$	842,515		$	848,866
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	46,464		$	83,665		$	71,359		$	82,067
Undistributed oil and natural gas proceeds		22,649			20,129			22,014			28,995
Advances from joint interest partners								65,271			20,627
Asset retirement obligations		27,923			23,613			24,799			24,994
Current maturities of long-term debt: (Note 2)
Principal		189,829			—
Carrying value adjustments		34,917			22,925
Current maturities of long-term debt - carrying value		224,746			22,925
Accrued liabilities (Note 1)		20,505			17,930			35,197			29,611
Total current liabilities		342,287			168,262			218,640			186,294
Long-term debt: (Note 2)
Principal		713,365			889,790
Carrying value adjustments		47,605			79,337
Long term debt, less current portion - carrying value		760,970			969,127

Long-term debt (Note 2)								634,005			633,535
Asset retirement obligations, less current portion		289,297			276,833			289,363			285,143
Other liabilities (Note 1)		73,007			66,866			73,142			68,690
Commitments and contingencies (Note 11)		—			—
Commitments and contingencies (Note 10)								—			—
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at June 30, 2018 and December 31, 2017		—			—
Common stock, $0.00001 par value; 200,000,000 shares authorized; 142,022,971 issued and 139,153,798 outstanding at June 30, 2018 and 141,960,462 issued and 139,091,289 outstanding December 31, 2017		1			1
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued for both dates presented								—			—
Common stock, $0.00001 par value; 200,000 shares authorized; 143,513 issued and 140,644 outstanding for both dates presented								1			1
Additional paid-in capital		548,196			545,820			545,627			545,705
Retained earnings (deficit)		(1,031,439	)		(1,095,162	)
Treasury stock, at cost; 2,869,173 shares at June 30, 2018 and December 31, 2017		(24,167	)		(24,167	)
Retained deficit								(894,096	)		(846,335	)
Treasury stock, at cost; 2,869 shares for both dates presented								(24,167	)		(24,167	)
Total shareholders’ deficit		(507,409	)		(573,508	)		(372,635	)		(324,796	)
Total liabilities and shareholders’ deficit	$	958,152		$	907,580		$	842,515		$	848,866

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2018		2017			2018			2017			Three Months Ended
	(In thousands except per share data)											March 31,
	(Unaudited)											2019			2018
Revenues:
Oil	$	116,618	$	85,622		$	213,924		$	170,593		$	86,703		$	97,306
NGLs		8,734		7,054			18,394			15,796			6,448			9,660
Natural gas		22,977		29,258			48,844			59,016			21,838			25,867
Other		1,283		1,389			2,663			2,311			1,091			1,380
Total revenues		149,612		123,323			283,825			247,716			116,080			134,213
Operating costs and expenses:
Lease operating expenses		35,582		31,519			72,425			71,683			43,456			36,843
Production taxes		439		449			894			964			416			455
Gathering and transportation		4,928		5,318			9,985			11,527			6,423			5,057
Depreciation, depletion, amortization and accretion		39,757		40,364			77,838			80,354			33,766			38,081
General and administrative expenses		14,220		16,474			29,258			29,748			14,109			15,038
Derivative (gain) loss		6,219		(3,689	)		6,219			(7,644	)
Derivative loss													48,886			—
Total costs and expenses		101,145		90,435			196,619			186,632			147,056			95,474
Operating income		48,467		32,888			87,206			61,084
Interest expense		12,147		11,436			23,470			22,730
Gain on exchange of debt		—		8,056			—			7,811
Other (income) expense, net		125		5,168			(208	)		5,114
Income before income tax expense (benefit)		36,195		24,340			63,944			41,051
Income tax expense (benefit)		112		(8,975	)		221			(16,563	)
Net income	$	36,083	$	33,315		$	63,723		$	57,614
Basic and diluted earnings per common share	$	0.25	$	0.23		$	0.44		$	0.40
Operating (loss) income													(30,976	)		38,739
Interest expense, net													16,282			10,962
Other expense, net													331			28
(Loss) income before income tax expense													(47,589	)		27,749
Income tax expense													172			109
Net (loss) income												$	(47,761	)	$	27,640
Basic and diluted (loss) earnings per common share												$	(0.34	)	$	0.19

CONDENSED CONSOLIDATED ~~STATEMENT~~STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

Common Stock
Outstanding

Additional
Paid-In

Retained
Earnings

Treasury Stock

Total
Shareholders’

Shares

Value

Capital

(Deficit)

Shares

Value

Deficit

(In thousands)

(Unaudited)

Balances at December 31, 2017

139,091

$
1

$
545,820

$
(1,095,162
)

2,869

$
(24,167
)

$
(573,508
)
Share-based compensation

—

—

2,434

—

—

—

2,434

Stock Issued

63

—

—

—

—

—

—

RSUs surrendered
for payroll taxes

—

—

(58
)

—

—

—

(58
)
Net income

—

—

—

63,723

—

—

63,723

Balances at June 30, 2018

139,154

$
1

$
548,196

$
(1,031,439
)

2,869

$
(24,167
)

$
(507,409
)

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

	Six Months Ended
	June 30,
	2018			2017			Three Months Ended
	(In thousands)						March 31,
	(Unaudited)						2019			2018
Operating activities:
Net income	$	63,723		$	57,614
Adjustments to reconcile net income to net cash provided by operating activities:
Net (loss) income							$	(47,761	)	$	27,640
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		77,838			80,354			33,766			38,081
Gain on exchange of debt		—			(7,811	)
Amortization of debt items and other items		1,126			836			1,152			466
Share-based compensation		2,434			3,466			(78	)		1,219
Derivative (gain) loss		6,219			(7,644	)
Cash receipts (payments) on derivative settlements, net		(1,149	)		2,208
Derivative loss								48,886			—
Cash receipts on derivative settlements, net								11,948			—
Deferred income taxes		221			212			172			109
Changes in operating assets and liabilities:
Oil and natural gas receivables		(6,630	)		3,675			6,496			501
Joint interest receivables		251			1,965			(2,986	)		1,919
Insurance reimbursements		—			30,100
Income taxes		(138	)		(16,960	)
Prepaid expenses and other assets		(14,323	)		(3,575	)		(4,269	)		(6,391	)
Escrow deposit - Apache lawsuit		—			(49,500	)
Asset retirement obligation settlements		(12,124	)		(36,021	)		(254	)		(7,022	)
Cash advances from JV partners								44,644			19,147
Accounts payable, accrued liabilities and other		(2,256	)		6,666			(6,871	)		(688	)
Net cash provided by operating activities		115,192			65,585			84,845			74,981
Investing activities:
Investment in oil and natural gas properties and equipment		(31,803	)		(43,800	)		(31,581	)		(38,271	)
Changes in operating assets and liabilities associated with investing activities		(29,330	)		(827	)
Acquisition of property interest		(16,617	)		—
Purchases of furniture, fixtures and other		—			(853	)
Deposit for acquisition								—			(3,000	)
Net cash used in investing activities		(77,750	)		(45,480	)		(31,581	)		(41,271	)
Financing activities:
Payment of interest on 1.5 Lien Term Loan		(4,114	)		(4,113	)		—			(2,057	)
Payment of interest on 2nd Lien PIK Toggle Notes		(2,920	)		(7,335	)
Payment of interest on 3rd Lien PIK Toggle Notes		—			(6,201	)
Other		(26	)		(372	)
Debt issuance costs								(441	)		—
Net cash used in financing activities		(7,060	)		(18,021	)		(441	)		(2,057	)
Increase in cash and cash equivalents		30,382			2,084			52,823			31,653
Cash and cash equivalents, beginning of period		99,058			70,236			33,293			99,058
Cash and cash equivalents, end of period	$	129,440		$	72,320		$	86,116		$	130,711

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

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

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

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

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

~~Recent Events.~~ Leases. In February 2016, Accounting Standards Update 2016-02, Leases (Topic 842) (“ASU 2016-02”) was issued requiring an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases. The ~~price we receive~~classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. ASU 2016-02 also requires certain quantitative and qualitative disclosures about leasing arrangements. Leases acquired to explore for ~~our crude~~or extract oil or natural gas ~~liquids (“NGLs”)~~resources, including the right to explore for those natural resources and rights to use the land in which those natural ~~gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate~~resources are contained, are not within the scope of ~~growth. The average realized prices of crude oil and NGLs improved during the six months ended June 30, 2018 compared to the average realized prices~~this standard’s update.

ASU 2016-02 was effective for us in the ~~six months ended June 30, 2017.~~ first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized an ROU asset and a lease liability with no retained earnings impact.

Our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) provides our revolver bank credit facility and matures on November 8, 2018. As of June 30, 2018, we had $9.7 million of letters of credit outstanding and no amounts borrowed on our revolving bank credit facility. Our 8.500% Senior Notes (the “Unsecured Senior Notes”) mature on June 15, 2019. If the Unsecured Senior Notes have not been extended, refunded, defeased, discharged, replaced or refinanced by February 28, 2019, then the 11.00% 1.5 Lien Term Loan, due November 15, 2019 (the “1.5 Lien Term Loan”) and the 8.50%/10.00% Third Lien Payment-In-Kind (“PIK”) Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”) will both accelerate their maturity to February 28, 2019. During the remainder of 2018, we plan to address the issues of the potential maturity acceleration of these two debt instruments and to extend or replace the revolving bank credit facility. We expect to build sufficient cash balances in 2018 to be able to redeem, repurchase or refinance the Unsecured Senior Notes. Certain amendments under the Credit Agreement and the 1.5 Lien Term Loan will likely be required in the event we redeem or repurchase the Unsecured Senior Notes, which we anticipate would be granted if requested. If we are in a position to repay or refinance the 1.5 Lien Term Loan, then we would expect to extend the maturity of our revolving bank credit facility. There can be no assurance that lenders will extend our revolving bank credit facility maturity, but under current market conditions and based on the outlook of our cash position in 2018 and further, we believe our lenders or replacement lenders will be amenable to participating in a refinancing or other corporate financing transaction.

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

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

Based on the results of our implementation process, we identified one operating lease in existence at January 1, 2019 subject to ASU 2016-02, which is our real estate lease for office space in Houston, Texas that terminates in December 2022. We identified no finance leases.

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

As of ~~potential maturity acceleration~~March 31, 2019, we recorded an ROU asset and a lease liability of ~~certain~~$5.0 million using a discount rate of 9.75%. The discount rate (or incremental borrowing rate) was determined using the interest rate of recently issued debt instruments ~~discussed above, we have assessed~~that were issued at par and for a similar term as the term of our obligations, our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate available liquidity to fund our operations through August 2019, the period of assessment to qualify as a going concern. However, we cannot predict the potential changes in commodity prices or future Bureau of Ocean Energy Management (“BOEM”) bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

~~See our Annual Report on Form 10-K~~lease for the ~~year ended December 31, 2017 concerning risks related to~~office space in Houston.

After the adoption of the new standard update, the amounts recorded within our ~~business and events occurring during 2017 and other information and~~Condensed Consolidated Balance Sheet are as follows (in thousands):

~~Accounting Standard Updates Effective January 1, 2018.~~ ~~Accounting Standards Update No. 2016-18, (“ASU 2016-18”),~~ ~~Statement~~new standard did not impact our Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows ~~(Topic 230) – Restricted Cash~~ ~~became effective for us as of January 1, 2018. As we did not have any amounts of restricted cash in the six months ended June 30, 2018 and 2017, ASU 2016-18 did not affect the~~or Condensed Consolidated ~~Statement~~Statements of ~~Cash Flows.~~Changes in Shareholders’ Deficit.

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

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

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

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

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current presentation as follows: In the Condensed Consolidated Statements of Operations, interest income was reclassified from Other expense, net to Interest expense, net, which did not change Net (loss) income before income tax expense. In the Condensed Consolidated Statements of Cash Flows, adjustments were made to certain line items within the Net Cash Used in Investing Activities of which did not change the total amount previous reported. The adjustments did not affect the Condensed Consolidated Balance Sheets.

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

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

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

	June 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Oil and natural gas properties and equipment	$	8,167,664	$	8,102,044	$	8,198,394	$	8,169,871
Furniture, fixtures and other		21,831		21,831		20,228		20,228
Total property and equipment		8,189,495		8,123,875		8,218,622		8,190,099
Less accumulated depreciation, depletion and amortization		7,613,422		7,544,859		7,703,857		7,674,678
Oil and natural gas properties and other, net	$	576,073	$	579,016	$	514,765	$	515,421

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

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

	June 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Escrow deposit - Apache lawsuit	$	49,500	$	49,500	$	49,500	$	49,500
Derivative assets						4,169		21,275
Appeal bond deposits		6,925		6,925		6,925		6,925
Unamortized debt issuance costs						4,511		4,773
Investment in White Cap, LLC		2,648		2,511		2,546		2,586
Deposit related to the Credit Agreement		4,702		—
Unamortized brokerage fee for Monza		2,182		—		3,746		2,277
Proportional consolidation of Monza's other assets (Note 4)		2,301		—		3,299		3,275
Other		1,160		1,457		4,309		936
Total other assets	$	69,418	$	60,393
Total other assets (long-term)					$	79,005	$	91,547

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

	June 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Accrued interest	$	4,199	$	4,200	$	27,624	$	12,385
Accrued salaries/payroll taxes/benefits		2,996		2,454		2,425		2,320
Incentive compensation plans		3,987		7,366		—		10,817
Litigation accruals		3,604		3,480		3,673		3,673
Derivative contracts		5,281		—
Other		438		430		1,475		416
Total accrued liabilities	$	20,505	$	17,930	$	35,197	$	29,611

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

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

	June 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Apache lawsuit	$	49,500	$	49,500	$	49,500	$	49,500
Uncertain tax positions including interest/penalties		11,236		11,015		11,694		11,523
Dispute related to royalty deductions		4,687		—		4,687		4,687
Dispute related to royalty-in-kind		2,083		914		2,164		2,135
Other		5,501		5,437		5,097		845
Total other liabilities (long-term)	$	73,007	$	66,866	$	73,142	$	68,690

In ~~February~~June 2016, the ~~FASB~~Financial Accounting Standards Board (“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 financing or operating lease. However, unlike current GAAP, which requires only capital or financing leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet. ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements. ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach. Our current operating leases that will be impacted by ASU 2016-02 are leases for office space, which is primarily in Houston, Texas, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease. We currently do not have any leases classified as financing leases nor do we have any leases recorded on the Condensed Consolidated Balance Sheets. We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

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

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

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

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

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

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

June 30, 2018

December 31, 2017

Adjustments to

Adjustments to

Carrying

Carrying

Carrying

Carrying

Principal

Value ⁽¹⁾

Value

Principal

Value ⁽¹⁾

Value

11.00% 1.5 Lien Term Loan,
     due November 2019:

Principal
$
75,000

$
—

$
75,000

$
75,000

$
—

$
75,000

Future interest payments

—

11,482

11,482

—

15,596

15,596

Subtotal

75,000

11,482

86,482

75,000

15,596

90,596

9.00 % Second Lien Term Loan,
    due May 2020:

300,000

—

300,000

300,000

—

300,000

9.00%/10.75% Second Lien
    PIK Toggle Notes, due May 2020:

Principal

177,513

—

177,513

171,769

—

171,769

Future payments-in-kind

—

—

—

—

5,745

5,745

Future interest payments

—

31,952

31,952

—

34,872

34,872

Subtotal

177,513

31,952

209,465

171,769

40,617

212,386

8.50%/10.00% Third Lien
  PIK Toggle Notes, due June 2021:

Principal

160,852

—

160,852

153,192

—

153,192

Future payments-in-kind

—

3,664

3,664

—

11,323

11,323

Future interest payments

—

38,682

38,682

—

38,682

38,682

Subtotal

160,852

42,346

203,198

153,192

50,005

203,197

8.50% Unsecured Senior Notes,
    due June 2019

189,829

—

189,829

189,829

—

189,829

Debt premium, discount,
     issuance costs, net of amortization

—

(3,258
)

(3,258
)

—

(3,956
)

(3,956
)
Total long-term debt

903,194

82,522

985,716

889,790

102,262

992,052

Current maturities of long-term debt ⁽²⁾

189,829

34,917

224,746

—

22,925

22,925

Long term debt, less current
   maturities
$
713,365

$
47,605

$
760,970

$
889,790

$
79,337

$
969,127

	March 31,			December 31,
	2019			2018
Credit Agreement ⁽¹⁾ borrowings	$	21,000		$	21,000

Senior Second Lien Notes: ⁽¹⁾
Principal		625,000			625,000
Unamortized debt issuance costs		(11,995	)		(12,465	)
Total Senior Second Lien Notes ⁽¹⁾		613,005			612,535

Total long-term debt	$	634,005		$	633,535

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

~~We accounted for a transaction executed~~On October 18, 2018, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), which matures on ~~September 7, 2016 as a Troubled Debt Restructuring pursuant to the guidance under Accounting Standard Codification 470-60,~~ ~~Troubled Debt Restructuring~~ (“ASC 470-60”). Under ASC 470-60, the carrying value of the 9.00/ 10.75% Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); the Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) are measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the New Debt in the Condensed Consolidated Statements of Operations for the periods presented. 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.

October 18, 2022. The primary terms ~~of our long-term debt are described below:~~

~~Credit Agreement.~~ ~~The Credit Agreement provides a revolving bank credit facility~~ and ~~expires by its term on November 8, 2018. The primary items of~~covenants associated with the Credit Agreement are as follows, with ~~certain~~capitalized terms defined under the Credit Agreement:

~~Availability under our revolving bank credit facility~~ is subject to a semi-annual ~~redetermination~~redeterminations of our borrowing base ~~that occurs in the spring~~to occur on or before May 15 and ~~fall of~~November 14 each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company. The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. ~~The 2018 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 Credit Agreement. The ~~revolving bank credit facility is secured and~~Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas ~~properties.~~properties and certain personal property. The interest rate on borrowings outstanding for the three months ended March 31, 2019 was 5.1%, which excludes debt issuance costs, commitment fees and other fees.

~~The Credit Agreement contains various customary covenants for certain financial tests, as defined in the Credit Agreement~~9.75% Senior Second Lien Notes Due 2023

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum and mature on November 1, 2023, and are 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 borrowingsgoverned 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.

As of June 30, 2018 and December 31, 2017, we did not have any borrowings outstanding on the revolving bank credit facility and had $9.7 million and $0.3 million of letters of credit outstanding, respectively. Available credit as of June 30, 2018 was $140.3 million. As of June 30, 2018, we have deposited $4.7 million with the lead bank in compliance with the terms of the ~~Credit Agreement as letters~~Indenture of ~~credit are considered borrowings and our unrestricted cash balance exceeded $35.0 million.~~

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

~~1.5 Lien Term Loan.~~ ~~In September 2016, we entered into~~ the ~~1.5 Lien Term Loan with a maturity date of November 15, 2019. 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 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. The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase the Unsecured Senior Notes at a price greater than 65% of par and limited to a basket of $35 million; (iii) repurchase our common stock; (iv) sell our assets; (v) make certain loans or investments; (vi) merge or consolidate; (vii) enter into certain liens; (viii) create liens that secure debt; and (ix) enter into transactions with affiliates.

~~Second Lien Term Loan.~~ ~~In May 2015, we entered into the 9.00% Term Loan~~ (the ~~“Second Lien Term Loan”~~“Indenture”)~~, 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 Senior Second Lien ~~Term Loan~~Notes is ~~9.6%~~10.3%, which includes amortization of debt issuance ~~costs and discounts. The~~costs. Interest on the Senior Second Lien ~~Term Loan~~Notes is payable in arrears on May 1 and November 1 of each year, beginning on May 1, 2019.

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. The Senior Second Lien ~~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 limit or prohibit 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 to us; (v) create liens that secure debt; (vi) enter into transactions with affiliates; and (vii) merge or consolidate with another company.

~~Second Lien PIK Toggle Notes.~~ In September 2016, we issued Second Lien PIK Toggle Notes with a maturity date of May 15, 2020. Interest is payable on May 15 and November 15 of each year. For the interest period from November 15, 2017 up to and including March 6, 2018, we had the option to pay all or a portion of interest in-kind at the rate of 10.75% per annum, which if so exercised, is added to the principal amount. After March 6, 2018, interest is payable in cash at the rate of 9.00% per annum. 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 and are effectively ~~pari passu~~ with the Second Lien Term Loan. The Second Lien PIK Toggle Notes and related Support Agreement contain covenants that limit or prohibit 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 to us; (v) create liens that secure debt; (vi) enter into transactions with affiliates; and (vii) merge or consolidate with another company.

~~Third Lien PIK Toggle Notes.~~ In September 2016, we issued Third Lien PIK Toggle Notes 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. Interest is payable on June 15 and December 15 of each year. For the interest periods up to and including September 6, 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. If so elected, such in-kind will be added to the principal amount. After September 6, 2018, interest is payable in cash at the rate of 8.50% per annum. 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. The Third Lien PIK Toggle Notes and related Support Agreement contain covenants that limit or prohibit 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 to us; (v) create liens that secure debt; (vi) enter into transactions with affiliates; and (vii) merge or consolidate with another company.

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 8.4%, which includes amortization of premiums and debt issuance costs. The Unsecured Senior Notes contain covenants that limit or prohibit our ability and the ability of certain of our subsidiaries to: (i) make investments; (ii) incur additional ~~debt; (ii) make payments~~indebtedness or ~~distributions on account~~issue certain types of ~~our or our restricted subsidiaries’ capital~~preferred stock; (iii) create certain liens; (iv) sell assets; ~~(iv)~~(v) enter into agreements that restrict dividends or other payments ~~of our restricted~~from the Company’s subsidiaries to ~~us; (v) create liens that secure debt;~~the Company; (vi) ~~enter into~~consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and ~~(vii) merge or consolidate~~(ix) create subsidiaries that would not be restricted by the covenants of the Indenture entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”). These covenants are subject to exceptions and qualifications set forth in the Indenture. In addition, most of the above described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Senior Second Lien Notes an investment grade rating and no default exists with ~~another company.~~ respect to the Senior Second Lien Notes.

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

As of March 31, 2019, we were in compliance with all applicable covenants ~~for all~~ of ~~our debt instruments as of June 30, 2018.~~the Credit Agreement and Senior Second Lien Notes indenture.

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

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

The following table presents the fair value of ~~the 1.5 Lien Term Loan was estimated using~~our open derivative financial instruments (in thousands):

We believe the carrying value of our debt under the ~~principal as only one entity has been~~Credit Agreement approximates fair value because the ~~holder~~interest rates are variable and reflective of ~~the 1.5 Lien Term Loan.~~current market rates. The fair ~~values~~value of our Senior Second Lien ~~Term Loan, Second Lien PIK Toggle~~ Notes ~~Third Lien PIK Toggle Notes and Unsecured Senior Notes were~~was measured based onusing quoted prices, although the market is not a very active ~~market; therefore, the fair value is classified within Level 2.~~

market. The ~~following table presents the~~ fair value of our long-term debt ~~all of which are~~was classified as Level 2 within the valuation ~~hierarchy~~hierarchy. See Note 2, Long-Term Debt for additional information on our long-term debt.

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

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

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

On March 12, 2018, W&T and two other initial members formed and initially funded ~~a limited liability company,~~ Monza, ~~Energy LLC, a Delaware limited liability company (“Monza”), that will~~which jointly ~~participate~~participates with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of ~~Mexico over~~Mexico. The projects are expected to be completed during the ~~next three years.~~years 2018 through 2020, but some projects may possibly extend into years beyond 2020. W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Monza board has approved the substitution of one of these identified undeveloped drilling projects, the Viosca Knoll 823 (“VK 823”) A-14 well, with the VK 823 A-13 well, which is in the process of being contributedSubsequent to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well. The interest in the VK823 A-14 well will be reconveyed to W&T. Since the initial closing, additional investors ~~have~~ joined as members of Monza during 2018 and ~~as of June 30, 2018,~~ total commitments by all members, including W&T, are $361.4 million. ~~Monza has closed off funding from additional investors.~~ The JV Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed upon rates. Any exceptions are approved by the Monza board. W&T is or will be the operator of each well in the JV Drilling Program unless there is ~~already~~ a designated third-party operator.

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

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

~~At the inception~~ As of March 31, 2019, members of Monza ~~W&T~~made partner capital contribution payments to Monza totaling $184.9 million, of which $70.2 million was contributed during the three months ended March 31, 2019. Our net contribution to Monza, reduced by distributions received, ~~a net reimbursement~~as of ~~approximately $20 million for the capital expenditures incurred prior to the close date for projects in the JV Drilling Program.~~March 31, 2019 was $58.9 million. W&T may be obligated to fund certain cost overruns, subject to certain exceptions, onfor the JV Drilling Program wells above budgeted and contingency ~~amounts. As~~amounts, of ~~June 30, 2018, members of Monza made partner capital contribution payments to Monza totaling $89.4 million.~~which the total exposure cannot be estimated at this time.

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

~~Accounting Methodology~~Consolidation and Carrying Amounts. Our interest in Monza is considered to be a variable interest ~~entity~~ that we account for using proportional consolidation. We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our ~~interest~~interests in the Monza properties. As of ~~June 30,~~March 31, 2019, in the Condensed Consolidated Balance Sheet, we recorded $11.0 million, net, in Oil and natural gas properties and other, net, $3.3 million in Other assets and $5.0 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. As of December 31, 2018, in the Condensed Consolidated Balance Sheet, we recorded ~~$6.0~~$8.8 million, net, in ~~oil~~Oil and natural gas properties ~~$2.3~~and other, net, $3.3 million in ~~other~~Other assets and ~~$1.7~~$0.7 million, net, ~~reduction~~increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, we recorded ~~$0.5~~$1.6 million in ~~revenue, $0.4~~Total revenues and $0.9 million in ~~operating expense~~Operating costs and ~~$0.2 million in other expense~~expenses in connection with our proportional interest in Monza’s operations. No revenues or expenses were recorded in the three months ended March 31, 2018 in connection with our proportional interest in Monza’s operations.

~~Maximum Exposure.~~Additionally, during the three-months ended March 31, 2019, we received cash calls from Monza of $66.3 million, of which $65.2 million is included in the Condensed Consolidated Balance Sheet in ~~Our contribution to Monza~~ Advances from joint interest partners as of June 30, 2018 was $48.8 million, which consisted of cash and the conveyance of the Company’s working interest in the 14 projects. We may also take responsibility for certain drilling and completion cost overruns, subject to certain limitations and certain exceptions, of which the total exposure cannot be estimated at this time.March 31, 2019.

On April 5, 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and 904. The gross purchase price was $31.1 million which was adjusted for certain closing items and an effective date of January 1, 2018. Cash flows generated by the acquired interest between the effective date and the closing date reduced the net purchase price to $16.6 million on the closing date. We determined that the assets acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition. In connection with this transaction, we were required to furnish a letter of credit of $9.4 million to a pipeline company as consignee. We recognized ARO of $3.6 million as a component of the transaction. In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.

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

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

Balance, December 31, 2017	$	300,446
Balance, December 31, 2018				$	310,137
Liabilities settled		(12,124	)		(254	)
Accretion of discount		9,273			4,588
Liabilities assumed through purchase		3,597
Liabilities incurred					44
Revisions of estimated liabilities ⁽¹⁾		16,028			(353	)
Balance, June 30, 2018		317,220
Balance, March 31, 2019					314,162
Less current portion		27,923			24,799
Long-term	$	289,297		$	289,363

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

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

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

During ~~the second quarter of~~ 2018, we entered into commodity contracts for crude oil ~~derivative contracts~~and natural gas which ~~relate~~related to a portion of our expected ~~crude oil production from May 2018 to December 2018.~~future production. The crude oil contracts ~~are~~were based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”). ~~During the first quarter of 2017, we entered into commodity contracts for crude oil and~~The natural gas ~~all of which had expired~~contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. The open contracts as of ~~December~~March 31, ~~2017.~~2019 are presented in the following tables:

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

Crude Oil:  Swap, Priced off WTI (NYMEX)

Notional

Notional

Quantity

Quantity

Strike

Termination Period

(Bbls/day) ⁽¹⁾

(Bbls) ⁽¹⁾

Price

2018
December

2,000

368,000

$
63.80

Crude Oil:  Puts,  Priced off WTI (NYMEX)

Notional

Notional

Quantity

Quantity

Put

Termination Period

(Bbls/day) ⁽¹⁾

(Bbls) ⁽¹⁾

Price

2018
December

5,000

920,000

$
60.00

Crude Oil:  Two-way collars, Priced off WTI (NYMEX)

Notional

Notional

Contract Prices

Quantity

Quantity

Put Option

Call Option

Termination Period

(Bbls/day) ⁽¹⁾

(Bbls) ⁽¹⁾

(Bought)

(Sold)

2018
December

2,000

368,000

$
60.00

$
69.50

2018
December

2,000

368,000

$
55.00

$
72.75

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

The ~~swap and two-way collars~~following amounts were ~~“cost-less” contracts, in that no premiums were paid or received. For the put option contract, the $2.1 million premium is being amortized over the life of the contract and~~ recorded in ~~Prepaid~~the Condensed Consolidated Balance Sheets in the categories presented and ~~other assets~~include the fair value of open contracts, and closed contracts which had not yet settled (in thousands):

The amounts recorded on the Condensed Consolidated Balance ~~Sheet. See Note 1.~~

~~Our open and closed (not settled) commodity derivative contracts~~Sheets are on a gross basis. If these were recorded ~~within the line~~ ~~Accrued liabilities~~on ~~the Condensed Consolidated Balance Sheet summarized~~a net settlement basis, it would not have resulted in ~~the following table (in thousands):~~

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

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

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

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

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 some of our derivative instruments. If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts. Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability. As of June 30, 2018, there would have been no difference in the presentation of our commodity derivatives on a gross or net basis.

Awards to Employees. In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan ~~(the~~(as amended from time to time, the “Plan”) was approved by our ~~shareholders,~~shareholders. During 2018 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 2017 and 2016,~~ the Company granted restricted stock units (“RSUs”) under the Plan to certain of its employees. RSUs are a long-term compensation component, ~~of the Plan, which are granted to certain employees,~~ and are subject to satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period based on the results ~~of certain predetermined criteria.~~achieved. In addition to share-based ~~compensation,~~awards, the Company may grant to its employees cash-based incentive awards under the Plan, which ~~are~~were used as a short-term and long-term compensation component of the ~~Plan~~2018 awards, and ~~are typically based on the Company and the employee achieving~~were subject to satisfaction of certain ~~pre-defined~~predetermined performance criteria.

As of ~~June 30, 2018,~~March 31, 2019, there were ~~13,342,827~~11,852,592 shares of common stock available for issuance in satisfaction of awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, which shares of common stock were issued net of withholding ~~tax.~~tax through the withholding of shares. The Company has the option atfollowing vesting to settle RSUs in stock or cash, or a combination of stock and cash. The Company ~~plans~~expects to settle RSUs that vest in the future using shares of common stock.

RSUs currently outstanding ~~related~~relate to the 2018 and 2017 ~~and 2016~~ grants, ~~have been adjusted for~~which were subject to predetermined performance ~~achieved~~criteria applied against ~~predetermined criteria for~~ the applicable performance ~~year.~~period. These RSUs continue to be subject to employment-based criteria and vesting generally occurs in December of the second year after the grant. See the table below for ~~potential~~anticipated vesting by year.

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. The fair values for the RSUs granted during ~~2017~~2018 and ~~2016~~2017 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 three months ended March 31, 2019 is as follows:

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, 2018 is as follows:~~

For the outstanding RSUs issued to the eligible employees as of ~~June 30, 2018,~~March 31, 2019, vesting is expected to occur as ~~follows:~~ follows (subject to forfeitures):

	Restricted Stock Units		Restricted Stock Units
2018		3,698,748
2019		1,992,983		1,579,140
2020				920,059
Total		5,691,731		2,499,199

Awards to Non-Employee Directors. Under the ~~Director~~W&T Offshore, Inc. 2004 Directors Compensation Plan (as amended from time to time, the “Director Compensation Plan”), shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors. Grants to non-employee directors were made during 2018, 2017 and 2016. As of ~~June 30, 2018,~~March 31, 2019, there were 128,980 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available are reduced on a one-to-one basis when Restricted Shares are granted.

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

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

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

For the outstanding Restricted Shares issued to the non-employee directors as of ~~June 30, 2018,~~March 31, 2019, vesting is expected to occur as ~~follows:~~follows (subject to any forfeitures):

Share-Based Compensation. Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations. ~~Share-based~~The tax benefit related to compensation expense recognized under share-based payment arrangements was ~~lower~~not meaningful and was minimal due to adjustments in the ~~three and six months ended June 30, 2018 compared to the prior year period as no RSU awards have been granted yet as of June 30, 2018.~~valuation allowance. 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				Three Months Ended
	June 30,				June 30,				March 31,
	2018		2017		2018		2017		2019			2018
Share-based compensation expense from:
Restricted stock units(1)	$	1,145	$	2,342	$	2,294	$	4,200	$	(148	)	$	1,149
Restricted Shares		70		70		140		140		70			70
Total	$	1,215	$	2,412	$	2,434	$	4,340	$	(78	)	$	1,219
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	255	$	844	$	511	$	1,519

~~Unrecognized Share-Based Compensation.~~ As of June 30, 2018, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $3.9 million and $0.5 million, respectively. Unrecognized share-based compensation expense will be recognized through November 2019 for RSUs and April 2021 for Restricted Shares.

~~Cash-Based Incentive Compensation.~~ In addition to share-based compensation, cash-based awards were granted under the Plan to substantially all eligible employees in 2017 and 2016. The cash-based awards, which are a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each such criterion. In addition, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred (as defined in the awards) for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award. Expense is recognized over the service period once the business criteria, individual performance criteria and financial condition are met.

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

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

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

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				Three Months Ended
	June 30,				June 30,				March 31,
	2018		2017		2018		2017		2019			2018
Share-based compensation included in:
General and administrative expenses	$	1,215	$	2,412	$	2,434	$	4,340	$	(78	)	$	1,219
Cash-based incentive compensation included in:
Lease operating expense(1)		543		394		1,403		394		(123	)		860
General and administrative expenses(1)		1,391		1,004		4,063		1,004		2,095			2,672
Total charged to operating income	$	3,149	$	3,810	$	7,900	$	5,738	$	1,894		$	4,751

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

Our income tax expense for the three ~~and six~~ months ended ~~June 30,~~March 31, 2019 and 2018 was ~~$0.1~~$0.2 million and ~~$0.2 million, respectively. Our income tax benefit for the three and six months ended June 30, 2017 was $9.0 million and $16.6~~$0.1 million, respectively. Our effective tax rate was not meaningful for the periods ~~presented. Our current full-year forecast for 2018 has~~presented as we continue to record a full valuation allowance on net ~~operating loss for~~deferred tax purposes; therefore, no current tax expense was recorded related to the full-year forecast. In addition, no deferred income tax expense was recorded due to dollar-for-dollar offsets by our valuation allowance. The income tax benefit forassets.

During the three months ended ~~June 30, 2017 relates to net operating loss carryback claims made pursuant to~~ ~~Internal Revenue Code (“IRC”)~~ ~~Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment~~March 31, 2019 and ~~site clearance costs to be carried back 10 years.~~

~~During the six months ended June 30,~~ 2018, ~~and 2017,~~ we did not receive any income tax refunds ~~and made no~~or make any income tax payments of significance.

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

~~As of June 30, 2018~~2019 and December 31, ~~2017,~~2018, our valuation allowance was ~~$158.1~~$127.8 million and ~~$171.5~~$117.8 million, respectively, related to net federal and state deferred tax assets. Net deferred tax assets were recorded related to ~~NOLs~~net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. ~~Although~~

As of March 31, 2019 and December 31, 2018, we had current income taxes receivable of $54.1 million, which primarily relates to our net ~~deferred tax assets~~operating loss carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years. These carryback claims were made pursuant to IRC Section 172(f) (related to rules regarding “specified liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims require a review by the ~~related valuation allowance reflect the provisions of the Tax Cuts and Jobs Act (“TCJA”), due~~Congressional Joint Committee on Taxation which we expect to ~~the timing and the complexity of the provisions of the TCJA, further adjustments may be required during 2018~~receive in ~~determination of the final effect in our financial statements.~~ 2019.

The tax years 2013 through ~~2017~~2018 remain open to examination by the tax jurisdictions to which we are subject.

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

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

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

Apache Lawsuit. On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon ~~(“MC”)~~ area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, ~~attorney's~~attorney’s fees and costs assessed in the judgment. We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth ~~Circuit.~~Circuit and provided oral arguments in December 2018. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017. Oral arguments occurred on December 4, 2018, but as the filing date of this Form 10-Q, a decision had not been rendered by the U.S. Court of Appeals for the Fifth Circuit.

The deposit of $49.5 million with the registry of the court is recorded in Other assets (long-term) on the Condensed Consolidated Balance Sheets as of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017.~~2018. Although we are appealing the decision, based solely on the decision rendered, we have recorded $49.5 million in Other liabilities (long-term) on the Condensed Consolidated Balance Sheets as of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017.~~2018.

Appeal with the Office of Natural Resources Revenue (“ONRR”). In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the Department of the Interior. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017. Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana. We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision. On December 4, 2018, the IBLA denied our motion for reconsideration. On February 4, 2019, we filed our first amended complaint.

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

Royalties-In-Kind (“RIK”). Under a program ~~with~~of the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessor to the ONRR), royalties ~~could~~must be paid “in-kind” rather than in value from ~~oil and gas companies operating under~~ federal ~~leases. We participated~~leases in the program. The MMS added to the RIK program our lease at ~~our~~the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed. The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to become fixed for accounting purposes. The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed. We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor. We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ~~ruling.~~ruling on May 29, 2018. We filed an appeal on July 24, 2018. Part of the ruling was in favor of our position and part was in favor of MMS’ position. Based solely on the ~~magistrate’s~~District Court’s ruling, we ~~increased~~recorded a liability reserve ~~by $1.2~~of $2.2 million ~~from a previously recorded amount~~and $2.1 million as of ~~$0.9 million recorded in 2012.~~March 31, 2019 and December 31, 2018, respectively. We ~~are appealing~~have appealed the ruling to the U.S. Fifth Circuit Court of ~~Appeals.~~Appeals and the government filed a cross-appeal. Briefing and oral arguments, if held, are expected to be completed in 2019.

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

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~~three months ended ~~June 30,~~March 31, 2019 and 2018, ~~and 2017,~~ we paid ~~additional royalty payments of $0.3~~$0.1 million and ~~$1.1~~$0.1 million, ~~respectively.~~respectively, of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment. During the ~~six~~three months ended ~~June 30,~~March 31, 2019 and 2018, ~~and 2017,~~ we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) at various offshore locations. We currently have ~~five~~nine open civil penalties issued by the BSEE from INCs, which have not been settled as of the filing date of this Form 10-Q. The INCs underlying ~~the~~these open civil penalties ~~relate to~~cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations ~~with occurrence~~on various dates ranging from July 2012 to ~~June 2014.~~January 2018. The proposed civil penalties for these INCs total ~~$7.8~~$7.7 million. WeAs of March 31, 2019 and December 31, 2018, we have accrued approximately $3.4 million, ~~as of June 30, 2018,~~ which is our best estimate of the final settlements once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

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

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.

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

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:

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

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

Consolidated

Parent

Guarantor

Non-Guarantor

W&T

Company

Subsidiaries

Adjustments

Eliminations

Offshore, Inc.

(In thousands)

Assets

Current assets:

Cash and cash equivalents
$
129,440

$
—

$
—

$
—

$
129,440

Receivables:

Oil and natural gas sales

8,109

44,161

(197
)

—

52,073

Joint interest

19,366

—

—

—

19,366

Income taxes

193,594

—

—

(128,354
)

65,240

Total receivables

221,069

44,161

(197
)

(128,354
)

136,679

Prepaid expenses and other assets

16,739

3,700

31

—

20,470

Total current assets

367,248

47,861

(166
)

(128,354
)

286,589

Oil and natural gas properties and other, net

416,539

121,075

48,003

(9,544
)

576,073

Restricted deposits for asset retirement obligations

26,072

—

—

—

26,072

Other assets

607,463

544,029

(46,464
)

(1,035,610
)

69,418

Total assets
$
1,417,322

$
712,965

$
1,373

$
(1,173,508
)

$
958,152

Liabilities and Shareholders’ Equity (Deficit)

Current liabilities:

Accounts payable
$
38,445

$
6,457

$
1,562

$
—

$
46,464

Undistributed oil and natural gas proceeds

21,390

1,259

—

—

22,649

Asset retirement obligations

21,663

6,260

—

—

27,923

Current maturities of long-term debt:

Principal

189,829

—

—

—

189,829

Carrying value adjustments

34,917

—

—

—

34,917

Current maturities of long-term debt  -
   carrying value

224,746

—

—

—

224,746

Accrued liabilities

20,523

128,336

—

(128,354
)

20,505

Total current liabilities

326,767

142,312

1,562

(128,354
)

342,287

Long-term debt:

Principal

713,365

—

—

—

713,365

Carrying value adjustments

47,605

—

—

—

47,605

Long term debt, less current portion -
  carrying value

760,970

—

—

—

760,970

Asset retirement obligations, less current portion

164,010

125,275

12

—

289,297

Other liabilities

663,239

—

—

(590,232
)

73,007

Shareholders’ deficit:

Common stock

1

—

—

—

1

Additional paid-in capital

548,196

704,885

—

(704,885
)

548,196

Retained earnings (deficit)

(1,021,694
)

(259,507
)

(201
)

249,963

(1,031,439
)
Treasury stock, at cost

(24,167
)

—

—

—

(24,167
)
Total shareholders’ equity (deficit)

(497,664
)

445,378

(201
)

(454,922
)

(507,409
)
Total liabilities and shareholders’ equity (deficit)
$
1,417,322

$
712,965

$
1,373

$
(1,173,508
)

$
958,152

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

Consolidated

Parent

Guarantor

W&T

Company

Subsidiaries

Eliminations

Offshore, Inc.

(In thousands)

Assets

Current assets:

Cash and cash equivalents
$
99,058

$
—

$
—

$
99,058

Receivables:

Oil and natural gas sales

5,665

39,778

—

45,443

Joint interest

19,754

—

—

19,754

Income taxes

128,835

—

(115,829
)

13,006

Total receivables

154,254

39,778

(115,829
)

78,203

Prepaid expenses and other assets

11,154

2,265

—

13,419

Total current assets

264,466

42,043

(115,829
)

190,680

Oil and natural gas properties and other, net

430,354

152,464

(3,802
)

579,016

Restricted deposits for asset retirement obligations

25,394

—

—

25,394

Income taxes receivable

52,097

—

—

52,097

Other assets

505,304

453,306

(898,217
)

60,393

Total assets
$
1,277,615

$
647,813

$
(1,017,848
)

$
907,580

Liabilities and Shareholders’ Deficit

Current liabilities:

Accounts payable
$
76,703

$
6,962

$
—

$
83,665

Undistributed oil and natural gas proceeds

18,762

1,367

—

20,129

Asset retirement obligations

22,488

1,125

—

23,613

Current maturities of long-term debt - carrying value

22,925

—

—

22,925

Accrued liabilities

18,058

115,701

(115,829
)

17,930

Total current liabilities

158,936

125,155

(115,829
)

168,262

Long-term debt:

Principal

889,790

—

—

889,790

Carrying value adjustments

79,337

—

—

79,337

Long term debt, less current portion - carrying value

969,127

—

—

969,127

Asset retirement obligations, less current portion

152,883

123,950

—

276,833

Other liabilities

566,375

—

(499,509
)

66,866

Shareholders’ deficit:

Common stock

1

—

—

1

Additional paid-in capital

545,820

704,885

(704,885
)

545,820

Retained earnings (deficit)

(1,091,360
)

(306,177
)

302,375

(1,095,162
)
Treasury stock, at cost

(24,167
)

—

—

(24,167
)
Total shareholders’ deficit

(569,706
)

398,708

(402,510
)

(573,508
)
Total liabilities and shareholders’ deficit
$
1,277,615

$
647,813

$
(1,017,848
)

$
907,580

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, 2018~~

Consolidated

Parent

Guarantor

Non-Guarantor

W&T

Company

Subsidiaries

Adjustments

Eliminations

Offshore, Inc.

(In thousands)

Revenues
$
77,270

$
71,873

$
469

$
—

$
149,612

Operating costs and expenses:

Lease operating expenses

21,617

13,929

36

—

35,582

Production taxes

439

—

—

—

439

Gathering and transportation

2,834

2,084

10

—

4,928

Depreciation, depletion, amortization
and accretion

19,954

16,743

164

2,896

39,757

General and administrative expenses

6,854

7,166

200

—

14,220

Derivative gain

6,219

—

—

—

6,219

Total costs and expenses

57,917

39,922

410

2,896

101,145

Operating income

19,353

31,951

59

(2,896
)

48,467

Earnings of affiliates

24,502

—

—

(24,502
)

—

Interest expense

12,147

—

—

—

12,147

Other (income) expense, net

(121
)

—

246

—

125

Income before income tax
expense (benefit)

31,829

31,951

(187
)

(27,398
)

36,195

Income tax expense (benefit)

(7,337
)

7,449

—

—

112

Net income
$
39,166

$
24,502

$
(187
)

$
(27,398
)

$
36,083

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, 2018~~

Consolidated

Parent

Guarantor

Non-Guarantor

W&T

Company

Subsidiaries

Adjustments

Eliminations

Offshore, Inc.

(In thousands)

Revenues
$
141,056

$
142,300

$
469

$
—

$
283,825

Operating costs and expenses:

Lease operating expenses

41,377

31,012

36

—

72,425

Production taxes

894

—

—

—

894

Gathering and transportation

5,537

4,438

10

—

9,985

Depreciation, depletion, amortization and accretion

39,374

32,557

164

5,743

77,838

General and administrative expenses

14,057

14,990

211

—

29,258

Derivative gain

6,219

—

—

—

6,219

Total costs and expenses

107,458

82,997

421

5,743

196,619

Operating income

33,598

59,303

48

(5,743
)

87,206

Earnings of affiliates

46,669

—

—

(46,669
)

—

Interest expense

23,470

—

—

—

23,470

Other (income) expense, net

(457
)

—

249

—

(208
)
Income before income tax expense (benefit)

57,254

59,303

(201
)

(52,412
)

63,944

Income tax expense (benefit)

(12,413
)

12,634

—

—

221

Net income
$
69,667

$
46,669

$
(201
)

$
(52,412
)

$
63,723

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

11,436

—

—

11,436

Gain on exchange of debt

8,056

—

—

8,056

Other expense, net

5,168

—

—

5,168

Income before income tax expense (benefit)

22,052

22,017

(19,729
)

24,340

Income tax expense (benefit)

(12,051
)

3,076

—

(8,975
)
Net income
$
34,103

$
18,941

$
(19,729
)

$
33,315

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

22,730

—

—

22,730

Gain on exchange of debt

7,811

—

—

7,811

Other expense, net

5,114

—

—

5,114

Income before income tax expense (benefit)

34,043

44,995

(37,987
)

41,051

Income tax expense (benefit)

(25,090
)

8,527

—

(16,563
)
Net loss
$
59,133

$
36,468

$
(37,987
)

$
57,614

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, 2018~~

Consolidated

W&T

Parent

Guarantor

Non-Guarantor

Offshore,

Company

Subsidiaries

Adjustments

Eliminations

Inc.

(In thousands)

Operating activities:

Net income
$
69,667

$
46,669

$
(201
)

$
(52,412
)

$
63,723

Adjustments to reconcile net income to net cash
provided by operating activities:

Depreciation, depletion, amortization and accretion

39,374

32,557

164

5,743

77,838

Amortization of debt items and other items

1,126

—

—

—

1,126

Share-based compensation

2,434

—

—

—

2,434

Derivative loss

6,219

—

—

—

6,219

Cash receipts on derivative settlements, net

(1,149
)

—

—

—

(1,149
)
Deferred income taxes

221

—

—

—

221

Earnings of affiliates

(46,669
)

—

—

46,669

—

Changes in operating assets and liabilities:

—

Oil and natural gas receivables

(2,444
)

(4,383
)

197

—

(6,630
)
Joint interest receivables

251

—

—

—

251

Income taxes

(12,772
)

12,634

—

—

(138
)
Prepaid expenses and other assets

(37,025
)

(72,465
)

4,445

90,722

(14,323
)
Asset retirement obligation settlements

(7,725
)

(4,399
)

—

—

(12,124
)
Accounts payable, accrued liabilities and other

80,147

8,055

264

(90,722
)

(2,256
)
Net cash provided by operating activities

91,655

18,668

4,869

—

115,192

Investing activities:

Investment in oil and natural gas properties and equipment

(15,638
)

(9,999
)

(6,166
)

—

(31,803
)
Changes in operating assets and liabilities associated with
investing activities

(21,958
)

(8,669
)

1,297

—

(29,330
)
Acquisition of property interest

(16,617
)

—

—

—

(16,617
)
Net cash used in investing activities

(54,213
)

(18,668
)

(4,869
)

—

(77,750
)
Financing activities:

Payment of interest on 1.5 Lien Term Loan

(4,114
)

—

—

—

(4,114
)
Payment of interest on 2nd Lien PIK Toggle Notes

(2,920
)

—

—

—

(2,920
)
Other

(26
)

—

—

—

(26
)
Net cash used in financing activities

(7,060
)

—

—

—

(7,060
)
Increase in cash and cash equivalents

30,382

—

—

—

30,382

Cash and cash equivalents, beginning of period

99,058

—

—

—

99,058

Cash and cash equivalents, end of period
$
129,440

$
—

$
—

$
—

$
129,440

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

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 obligations

(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 used in financing activities

(18,021
)

—

—

(18,021
)
Increase in cash, cash equivalents and restricted cash

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

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

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 and may be discussed or updated from time to time in subsequent reports filed with the ~~SEC.~~Securities and Exchange Commission. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated ~~subsidiaries and references to “Parent Company” are solely to W&T Offshore, Inc.~~subsidiaries.

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. We have grown through acquisitions, exploration and development and ~~currently~~ hold working interests in ~~approximately~~ 48 offshore ~~producing~~ fields in federal and state waters ~~(45~~(47 producing and ~~three fields~~one field capable of producing). We currently have under lease approximately ~~650,000~~720,000 gross acres (390,000 net acres) spanning across the Outer Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately ~~440,000~~515,000 gross acres on the conventional shelf and approximately ~~210,000~~205,000 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, a Delaware limited liability company and bythrough our proportionately consolidated interests in Monza, ~~Energy LLC (“Monza”), which we proportionately consolidate~~as described in ~~our condensed consolidated financial statements.~~more detail in Financial Statements– Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019 were comprised of ~~48.8%~~49.2% crude oil and condensate, ~~9.9%~~10.3% NGLs and ~~41.3%~~40.5% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel ~~(“Bbl”)~~ of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one ~~barrel of equivalent (“Boe”)~~Boe for crude oil, NGLs and natural gas has differed significantly in the past. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, revenues from the sale of crude oil and NGLs made up ~~81.9%~~80.2% of our total revenues compared to ~~75.2%~~79.7% for the ~~six~~three months ended ~~June 30, 2017.~~March 31, 2018. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, our combined total production expressed in equivalent volumes was ~~13.1%~~9.8% lower than for the ~~six~~three months ended ~~June 30, 2017,~~March 31, 2018, with natural gas having the largest decline. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, our total revenues were ~~14.6% higher~~13.5% lower than the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 primarily due to ~~significantly higher~~lower production and lower realized prices for crude oil and NGLs. See Results of Operations – ~~Six~~Three Months Ended ~~June 30, 2018~~March 31, 2019 Compared to the ~~Six~~Three Months Ended ~~June 30, 2017~~March 31, 2018 in this Item 2 for additional information.

On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects in the Gulf of Mexico over the next three years. We refer to these projects herein as the JV Drilling Program. W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Monza board has approved the substitution of one of these identified undeveloped drilling projects, the VK823 A-14 well, with the VK823 A-13 well, which is in the process of being contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well. The interest in the VK823 A-14 well will be reconveyed to W&T. Since the initial closing, additional investors have joined as members of Monza and as of June 30, 2018, total commitments by all members, including W&T, are $361.4 million. Monza has closed off funding from additional investors. The JV Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed upon rates. See ~~Financial Statements – Note 4 – JV Drilling Program~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

Our operating results are strongly influenced by the price of the commodities that we produce and sell. The price of those commodities is affected by both domestic and international factors, including domestic production. During the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, our average realized crude oil price was ~~$64.93~~$58.66 per barrel. This is ~~an increase over~~a decrease from our average realized crude oil price of ~~$45.76~~$62.52 per barrel for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~an increase over~~a decrease from our average realized crude oil price of ~~$48.13~~$65.62 per barrel for the year ~~2017. In addition,~~2018. For the month of March 2019, the average realized price for crude oil increased from the amounts realized in January 2019 and February 2019 to $64.23 per barrel, which was above the average realized crude oil price for the three months ended March 31, 2018. Our average realized prices of NGLs and natural gas for the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019 were ~~higher~~lower than the average realized prices for the ~~six months ended June 30, 2017 and the year 2017.~~

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

As reported by the U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in July 2018 (“STEO”), the overall crude oil and other petroleum liquids market for the three months ended June 30, 2018 had an inventory build, which reversed the trend of inventory draws during each of the quarters during 2017 and the first quarter of 2018. But, the inventory build did not appear to negatively affect crude oil prices, as both WTI and Brent average crude oil prices increased during the second quarter as compared to the first quarter of 2018. EIA forecasts inventories to be drawn down slightly in the third quarter of 2018, then having inventory builds in the fourth quarter of 2018 and each of the quarters of 2019.

~~The EIA reported worldwide total crude oil and petroleum liquids inventories increased in the second quarter of~~March 31, 2018 by ~~0.6 million barrels per day. For the countries grouped by EIA in the category of Organization for Economic Cooperation~~24.2% and ~~Development (“OECD”)~~1.0%, second quarter 2018 crude oil inventories were 4% above the five-year average, but on a days-of-supply basis, OECD crude oil inventories for the second quarter of 2018 were below the 5-year average by 1%. EIA forecasts OECD crude oil inventories to remain fairly constant through the end of 2018 as compared to 2017 level, but rising by 5% during 2019 as compared to 2018. Increased production is the driving factor for the forecasted inventory build.

The EIA forecasts an increase in worldwide production for the second half of 2018 compared to the first half of 2018 by 1.5% due primarily to increases in production in the U.S., Canada and Brazil. For the year 2018, the EIA estimates worldwide crude oil and petroleum liquids production to be 100.15 million barrels per day, an increase of 2.2% over 2017. Consumption for 2018 is estimated to be 100.20 million barrels per day, an increase of 1.7% over 2017, with China and other Asian countries being the primary contributors to the increase in consumption.

According to EIA’s STEO, 2018 U.S. crude oil production (excluding other petroleum liquids) is expected to increase by 15% over 2017 and increase by 9% in 2019 over 2018 levels. If EIA’s forecast is achieved in each year, crude oil production in the U.S will be at the highest level in recorded history, surpassing the current record set in 1970. In addition, if these production levels are achieved, this would make the U.S. the largest producer in the world for these years. These production levels have pushed pipeline capacities to the maximum levels in the Permian Basin, which may limit short-term growth until pipeline capacity can be increased. Net imports of crude oil in the U.S. are expected to decrease by 12% in 2018 compared to 2017 and further decrease by 13% in 2019 compared to 2018. As noted below, the number of onshore rigs drilling for oil has increased from 2017 levels.respectively.

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

During the six months ended June 30, 2018, our average realized crude oil sales price was $64.93 per barrel, up from $45.76 per barrel (41.9% higher) for the six months ended June 30, 2017. The two primary benchmarks are the prices for WTI and Brent crude oil. As reported by the EIA, WTI crude oil prices averaged $65.55 per barrel for the six months ended June 30, 2018, up from $49.85 per barrel (31.5% higher) for the six months ended June 30, 2017. Brent crude oil prices averaged $70.67 per barrel for the six months ended June 30, 2018, up from $51.57 per barrel (37.0% higher) for the six months ended June 30, 2017. The rising U.S. crude oil production put upward price pressure on the Brent-to-WTI premium, which increased 211% to an average of $5.19 per barrel for the six months ended June 30, 2018 compared to an average of $1.67 per barrel for the six months ended June 30, 2017.

~~For the six months ended June 30, 2018, our average realized crude oil sales price was $64.93 per barrel compared to a WTI benchmark price of $65.55 per barrel.~~ Our average realized crude oil sales price differs from the WTI benchmark average crude ~~prices~~price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary significantly by field. For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Ship Shoal 349 field (“Mahogany”) normally receives a negative quality adjustment. All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of WTI versus Poseidon, LLS and HLS for the ~~six~~three months ended ~~June 30,~~March 31, 2019 compared to the three months ended March 31, 2018 improved by approximately ~~$2.00~~$3.00 per barrel ~~compared to the six months ended June 30, 2017~~ for these types of crude oils.

Despite the projection by the EIA that crude oil inventories will remain fairly level on an end-of-year comparison for 2018 to 2017, the EIA projects average crude oil prices for both WTI and Brent to increase by approximately $15.00 to $17.00 per barrel, respectively, for the year 2018 compared to 2017. EIA’s forecast of crude oil prices for both WTI and Brent are expected to decrease by approximately $3.00 per barrel for the year 2019 compared to 2018. Per the EIA, economic and political instability in Venezuela continues to negatively affect its crude oil production. Uncertainty remains regarding the effect of U.S. sanctions on Iran and the degree to which the sanctions will take crude oil off the market. These factors may have impacted crude oil prices, but other unidentified factors may also be affecting the market as these alone do not seem to account for the increase in 2018 given that supply is expected to be approximately equal to consumption.

~~During the six months ended June 30, 2018, our average realized NGLs sales price increased by 26.5% compared to the six months ended June 30, 2017.~~ Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. During in the ~~six~~three months ended ~~June 30,~~March 31, 2019 compared to the three months ended March 31, 2018, average prices for domestic ethane increased by ~~10%~~6% and average domestic propane prices ~~increased~~decreased by ~~28% from the six months ended June 30, 2017. Average~~21% as measured using a price ~~changes~~index for Mount Belvieu. The average price for other domestic NGLs ~~were an increase~~components ranged from decreases of ~~11%~~15% to ~~36% between~~18% for the ~~two periods.~~three months ended March 31, 2019 year-over-year. We believe the ~~increase~~change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and propane usage during the recent winter season. Per EIA, production of ethane is expected to increase by 23% in 2018 compared to 2017 and increase by 12% in 2019 compared to 2018. Propane production is expected to increase by 13% in 2018 compared to 2017 and by 9% in 2019 compared to 2018. Ethane inventories decreased 7% as of June 2018 compared to June 2017. Ethane usage is not impacted by weather, but primarily by demand from petrochemical plants. Additional ethane steam crackers coming on line is impacting the usage of ethane, which is believed to positively impact the price. Propane usage is affected by weather as it is used for house heating fuel in certain areas and for crop drying, along with other uses. Propane inventory levels are 2%

~~higher at the end of the second quarter of 2018 compared to the same period last year. Heating degree days were 16% higher in the first half of 2018 compared to the same period last year.~~demand.

~~During the six months ended June 30, 2018, our average realized natural gas sales price decreased 1.7% compared to the six months ended June 30, 2017.~~ According to data from EIA’s web site, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 4.9% lower in the six months ended June 30, 2018 compared to the six months ended June 30, 2017. Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation. Natural gas inventories at the end of the second quarter of 2018 were 25% lower than the prior year period and were 17% below the five-year average for the previous five years.

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

EIA projects natural gas prices to be flat in 2018 compared to 2017 and to increase 2% in 2019 compared to 2018. U.S. supply is projected to be slightly higher than consumption in 2018 and 2019, resulting in minor inventory builds. EIA’s forecast of fuel used for electrical power generation has natural gas consumption increasing in 2018 to 34% from 32% in 2017. Electrical power generation from coal is forecast to decrease to 28% in 2018 from 30% in 2017. Electrical power from renewable sources such as hydropower and wind is expected to be 17% in both 2018 and 2017.

~~As of June 30, 2018,~~Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as of the end of March 2019 was ~~higher than~~approximately the same level as year ago levels for land based rigs ~~(109~~(an increase of four rigs, or ~~12%~~less than 1%), ~~but lower~~and higher in ~~offshore waters (two~~the Gulf of Mexico (an increase of 11 rigs or ~~10%~~92%). ~~According to Baker Hughes, the~~The oil rig count ~~at the end~~as of ~~June~~March 2019 and March 2018 ~~December 2017~~was 816 and ~~June 2017 was 858, 747 and 756,~~797, respectively. The U.S. natural gas rig count ~~at the end~~as of ~~June~~March 2019 and March 2018 ~~December 2017~~was 190 and ~~June 2017 was 187, 182 and 184,~~194, respectively. In the Gulf of Mexico, the number of working rigs was ~~18 rigs (15 oil and three natural gas) at the end of June 2018; 18 rigs (14 oil and four natural gas) at the end of December 2017; and 21~~23 rigs (18 oil rigs and five natural gas rigs) as of March 2019 and 12 rigs (all oil rigs) as of March 2018. During the three ~~natural gas) at~~months ended March 31, 2019, we had four rigs running, which represents approximately 20% of the ~~end~~active rigs in the Gulf of ~~June 2017.~~Mexico.

Our current ~~2018~~ capital expenditure forecast for ~~2018~~2019 is approximately ~~$95~~$120.0 million ~~which excludes the Heidelberg field transaction~~composed of select shelf and ~~excludes other potential acquisitions.~~deepwater projects that, assuming success, would be placed on production within a few months after completion. The forecast also incorporates our capital spending relating to the JV Drilling ~~Program.~~Program (net to our interest). Our ~~2018~~2019 plans also include spending $24.0 million for ARO. Based upon current price and production expectations for 2019, we believe that our cash flows from operating activities and cash on hand will be sufficient to fund our operations through year-end 2019 and build available cash balances; however, future cash flows are subject to a number of variables and additional capital ~~expenditure program includes participation in 10 wells, seven of~~expenditures may be required to more fully develop our properties. We are also currently evaluating various acquisition opportunities, which, ~~are included in the 2018 JV Drilling Program.~~

~~We expect to be able to address the upcoming maturities of our debt instruments, have adequate cash balances and have no draws on our revolving bank credit facility during 2018. See the~~ ~~Liquidity and Capital Resources~~ ~~section of this Item 2 for a discussion of our financing plans. We strive to maintain flexibility in our capital expenditure projects and~~ if ~~prices improve, we~~successful, may increase our ~~investments.~~

~~Our short term focus is on liquidity, cost reductions, fulfilling our obligations~~capital requirements in 2019 and ~~making investments with short payback time frames.~~beyond. We continue to closely monitor current and forecasted commodity prices to assess what changes, if ~~changes are needed~~any, should be made to our 2019 plans. See our Annual Report on Form 10-K for the year ended December 31, ~~2017, Item 1A,~~ ~~Risk Factors,~~2018, for additional information.

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												Three Months Ended
	June 30,											June 30,												March 31,
	2018		2017			Change			%			2018			2017			Change			%			2019			2018		Change			%
	(In thousands, except percentages and per share data)																							(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	116,618	$	85,622		$	30,996			36.2	%	$	213,924		$	170,593		$	43,331			25.4	%	$	86,703		$	97,306	$	(10,603	)		(10.9	)%
NGLs		8,734		7,054			1,680			23.8	%		18,394			15,796			2,598			16.4	%		6,448			9,660		(3,212	)		(33.3	)%
Natural gas		22,977		29,258			(6,281	)		(21.5	)%		48,844			59,016			(10,172	)		(17.2	)%		21,838			25,867		(4,029	)		(15.6	)%
Other		1,283		1,389			(106	)		(7.6	)%		2,663			2,311			352			15.2	%		1,091			1,380		(289	)		(20.9	)%
Total revenues		149,612		123,323			26,289			21.3	%		283,825			247,716			36,109			14.6	%		116,080			134,213		(18,133	)		(13.5	)%
Operating costs and expenses:
Lease operating expenses		35,582		31,519			4,063			12.9	%		72,425			71,683			742			1.0	%		43,456			36,843		6,613			17.9	%
Production taxes		439		449			(10	)		(2.2	)%		894			964			(70	)		(7.3	)%		416			455		(39	)		(8.6	)%
Gathering and transportation		4,928		5,318			(390	)		(7.3	)%		9,985			11,527			(1,542	)		(13.4	)%		6,423			5,057		1,366			27.0	%
Depreciation, depletion, amortization and accretion		39,757		40,364			(607	)		(1.5	)%		77,838			80,354			(2,516	)		(3.1	)%		33,766			38,081		(4,315	)		(11.3	)%
General and administrative expenses		14,220		16,474			(2,254	)		(13.7	)%		29,258			29,748			(490	)		(1.6	)%		14,109			15,038		(929	)		(6.2	)%
Derivative (gain) loss		6,219		(3,689	)		9,908		NM				6,219			(7,644	)		13,863		NM
Derivative loss																									48,886			—		48,886		NM
Total costs and expenses		101,145		90,435			10,710			11.8	%		196,619			186,632			9,987			5.4	%		147,056			95,474		51,582			54.0	%
Operating income		48,467		32,888			15,579			47.4	%		87,206			61,084			26,122			42.8	%
Interest expense		12,147		11,436			711			6.2	%		23,470			22,730			740			3.3	%
Gain on exchange of debt		—		8,056			(8,056	)	NM				—			7,811			(7,811	)	NM
Other (income) expense, net		125		5,168			(5,043	)	NM				(208	)		5,114			(5,322	)	NM
Income before income tax expense (benefit)		36,195		24,340			11,855			48.7	%		63,944			41,051			22,893			55.8	%
Income tax expense (benefit)		112		(8,975	)		9,087		NM				221			(16,563	)		16,784		NM
Net income	$	36,083	$	33,315		$	2,768			8.3	%	$	63,723		$	57,614		$	6,109			10.6	%
Basic and diluted earnings per common share	$	0.25	$	0.23		$	0.02			8.7	%	$	0.44		$	0.40		$	0.04			10.0	%
Operating (loss) income																									(30,976	)		38,739		(69,715	)	NM
Interest expense, net																									16,282			10,962		5,320			48.5	%
Other expense, net																									331			28		303		NM
(Loss) income before income tax expense																									(47,589	)		27,749		(75,338	)	NM
Income tax expense																									172			109		63			57.8	%
Net (loss) income																								$	(47,761	)	$	27,640	$	(75,401	)	NM
Basic and diluted (loss) earnings per common share																								$	(0.34	)	$	0.19	$	(0.53	)	NM

	Three Months Ended										Six Months Ended										Three Months Ended
	June 30,										June 30,										March 31,
	2018		2017		Change			% ⁽²⁾			2018		2017		Change			% ⁽²⁾			2019		2018		Change			% ⁽²⁾
Operating: ⁽¹⁾
Net sales:
Oil (MBbls)		1,738		1,923		(185	)		(9.6	)%		3,295		3,728		(433	)		(11.6	)%		1,478		1,557		(79	)		(5.1	)%
NGLs (MBbls)		316		351		(35	)		(10.0	)%		667		725		(58	)		(8.0	)%		309		351		(42	)		(12.0	)%
Natural gas (MMcf)		8,186		9,890		(1,704	)		(17.2	)%		16,709		19,875		(3,166	)		(15.9	)%		7,288		8,523		(1,235	)		(14.5	)%
Total oil equivalent (MBoe)		3,419		3,921		(502	)		(12.8	)%		6,747		7,765		(1,018	)		(13.1	)%		3,001		3,328		(327	)		(9.8	)%
Total nat. gas equiv. (MMcfe)		20,514		23,524		(3,010	)		(12.8	)%		40,481		46,589		(6,108	)		(13.1	)%
Avg. daily equivalent sales (Boe/day)		37,571		43,084		(5,513	)		(12.8	)%		37,275		42,899		(5,624	)		(13.1	)%
Avg. daily equiv. sales (Mcfe/day)		225,427		258,503		(33,076	)		(12.8	)%		223,650		257,395		(33,745	)		(13.1	)%

Average daily equivalent sales (Boe/day)																						33,349		36,976		(3,627	)		(9.8	)%
Average realized sales prices:
Oil ($/Bbl)	$	67.09	$	44.54	$	22.55			50.6	%	$	64.93	$	45.76	$	19.17			41.9	%	$	58.66	$	62.52	$	(3.86	)		(6.2	)%
NGLs ($/Bbl)		27.61		20.15		7.46			37.0	%		27.57		21.80		5.77			26.5	%		20.88		27.54		(6.66	)		(24.2	)%
Natural gas ($/Mcf)		2.81		2.96		(0.15	)		(5.1	)%		2.92		2.97		(0.05	)		(1.7	)%		3.00		3.03		(0.03	)		(1.0	)%
Oil equivalent ($/Boe)		43.38		31.10		12.28			39.5	%		41.67		31.61		10.06			31.9	%		38.31		39.92		(1.61	)		(4.0	)%
Natural gas equivalent ($/Mcfe)		7.23		5.18		2.05			39.6	%		6.95		5.27		1.68			31.8	%

Average per Boe ($/Boe):
Lease operating expenses	$	10.41	$	8.04	$	2.37			29.5	%	$	10.73	$	9.23	$	1.50			16.3	%	$	14.48	$	11.07	$	3.41			30.8	%
Gathering and transportation		1.44		1.36		0.08			5.9	%		1.48		1.48		—			—			2.14		1.52		0.62			40.8	%
Production costs		11.85		9.40		2.45			26.1	%		12.21		10.71		1.50			14.0	%		16.62		12.59		4.03			32.0	%
Production taxes		0.13		0.11		0.02			18.2	%		0.13		0.12		0.01			8.3	%		0.14		0.14		—			—
DD&A		11.63		10.29		1.34			13.0	%		11.54		10.35		1.19			11.5	%		11.25		11.44		(0.19	)		(1.7	)%
G&A expenses		4.16		4.20		(0.04	)		(1.0	)%		4.34		3.83		0.51			13.3	%		4.70		4.52		0.18			4.0	%
	$	27.77	$	24.00	$	3.77			15.7	%	$	28.22	$	25.01	$	3.21			12.8	%	$	32.71	$	28.69	$	4.02			14.0	%
Average per Mcfe ($/Mcfe):
Lease operating expenses	$	1.73	$	1.34	$	0.39			29.1	%	$	1.79	$	1.54	$	0.25			16.2	%
Gathering and transportation		0.24		0.23		0.01			4.3	%		0.25		0.25		—			—
Production costs		1.97		1.57		0.40			25.5	%		2.04		1.79		0.25			14.0	%
Production taxes		0.02		0.02		—			—			0.02		0.02		—			—
DD&A		1.94		1.72		0.22			12.8	%		1.92		1.72		0.20			11.6	%
G&A expenses		0.69		0.70		(0.01	)		(1.4	)%		0.72		0.64		0.08			12.5	%
	$	4.62	$	4.01	$	0.61			15.2	%	$	4.70	$	4.17	$	0.53			12.7	%

Three Months Ended ~~June 30, 2018~~March 31, 2019 Compared to the Three Months Ended ~~June 30, 2017~~March 31, 2018

Revenues. Total revenues ~~increased $26.3~~decreased $18.1 million, or ~~21.3%~~13.5%, to ~~$149.6~~$116.1 million for the three months ended ~~June 30, 2018~~March 31, 2019 as compared to the three months ended ~~June 30, 2017.~~March 31, 2018. Oil revenues ~~increased $31.0~~decreased $10.6 million, or ~~36.2%~~10.9%, NGLs revenues ~~increased $1.7~~decreased $3.2 million, or ~~23.8%~~33.3%, natural gas revenues decreased ~~$6.3~~$4.0 million, or ~~21.5%~~15.6%, and other revenues decreased ~~$0.1~~$0.3 million. The ~~increase~~decrease in oil revenues was attributable to a ~~50.6% increase~~6.2% decrease in the average realized sales price to ~~$67.09~~$58.66 per barrel for the three months ended ~~June 30, 2018~~March 31, 2019 from ~~$44.54~~$62.52 per barrel for the three months ended ~~June 30, 2017, partially offset by a decrease in~~March 31, 2018 and sales volumes ~~of 9.6%~~decreased 5.1%. The ~~increase~~decrease in NGLs revenues was attributable to a ~~37.0% increase~~24.2% decrease in the average realized sales price to ~~$27.61~~$20.88 per barrel for the three months ended ~~June 30, 2018~~March 31, 2019 from ~~$20.15~~$27.54 per barrel for the three months ended ~~June 30, 2017, partially offset by a decrease in~~March 31, 2018 and sales volumes ~~of 10.0%~~decreased 12.0%. The decrease in natural gas revenues was attributable to a decrease in sales volumes of ~~1.7~~1.2 billion cubic feet (“Bcf”), or ~~17.2%~~14.5% and a ~~5.1%~~1.0% decrease in the average realized price to ~~$2.81~~$3.00 per Mcf for the three months ended ~~June 30, 2018~~March 31, 2019 from ~~$2.96~~$3.03 per Mcf for the three months ended ~~June 30, 2017.~~March 31, 2018. Overall, production volumes decreased ~~12.8%~~9.8% on a Boe basis. The largest production increases for the three months ended ~~June 30, 2018~~March 31, 2019 compared to the three months ended ~~June 30, 2017~~March 31, 2018 were from our ~~newly acquired~~ interest in the Heidelberg field, which was acquired in April 2018, and increases in production at our Ship Shoal ~~300 field.~~349 field (Mahogany). Offsetting were production decreases primarily ~~due~~from increases in downtime, with the largest amounts related to ~~natural~~planned maintenance, well servicing and rig movements at certain platforms and pipelines. Our estimate of deferred production ~~declines. Production~~ for the three months ended ~~June 30, 2018~~March 31, 2019 was ~~also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,600~~approximately 7,200 Boe per ~~day. During~~day as compared to 4,200 Boe per day for the three months ended ~~June 30, 2017, deferred~~March 31, 2018, which comprises 83% of the production volume variance between the two periods. In April 2019, a majority of the pipeline and facility maintenance was ~~3,400 Boe per~~ completed and improved well performance and continued ramp up of new wells enabled the mid-April production rate to increase to over 37,000 Boe/day.

Revenues from oil and NGLs as a percent of our total revenues were ~~83.8%~~80.2% for the three months ended ~~June 30, 2018~~March 31, 2019 compared to ~~75.1%~~79.7% for the three months ended ~~June 30, 2017.~~March 31, 2018. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to ~~41.1%~~35.6% for the three months ended ~~June 30, 2018~~March 31, 2019 compared to ~~45.2%~~44.0% for the three months ended ~~June 30, 2017.~~March 31, 2018.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, ~~insurance,~~ workovers, and facilities maintenance, increased ~~$4.1~~$6.6 million, or ~~12.9%~~17.9%, to ~~$35.6~~$43.5 million in the three months ended ~~June 30, 2018~~March 31, 2019 compared to the three months ended ~~June 30, 2017.~~March 31, 2018. On a component basis, base lease operating expenses increased ~~$3.1~~$1.4 million, workover expenses increased $2.3 million, and facilities maintenance expense increased ~~$0.7, insurance premiums increased $0.5 million and workover expenses decreased $0.2~~$2.9 million. Base lease operating expenses increased primarily due to the addition of the Heidelberg ~~field; lower product handling~~field interest, acquired in April 2018, and had base lease operating ~~charges to an outside party at our Mississippi Canyon 243 field (Matterhorn) and higher charges from non-operated properties. (Compared to~~expenses of $1.7 million for the three months ended March 31, ~~2018, base lease operating~~2019. The increase in workover expense ~~decreased $1.2 million.)~~was primarily due to 2019 projects at our Mahogany field. The facility maintenance expense increase was primarily attributable to a pipeline repair at our East Cameron 321 field. The insurance premium increase is primarily due to our insurance policies related to named windstorms, which had better coverage between the two periods. The decreasework performed in ~~workover expense was primarily due to a 2017 project at the Brazos Area 133 field, partially offset by a 2018 project~~2019 at our Mahogany ~~field.~~

~~Production taxes.~~ Production taxes were basically flat for the three months ended June 30, 2018 compared to the three months ended June 30, 2017. Most of our production is from federal waters where no production taxes are imposed. Our Fairway field ~~which is in state waters, is subject to production taxes.~~combined with multiple other fields.

Gathering and transportation. Gathering and transportation expenses ~~decreased $0.4~~increased $1.4 million to ~~$4.9~~$6.4 million for the three months ended ~~June 30, 2018~~March 31, 2019 compared to the three months ended ~~June 30, 2017~~March 31, 2018 primarily related to the East Cameron 321 field due to ~~lower production volumes~~a change in our customer where transportation costs were separately billed and recorded as such beginning in the second half of ~~all of~~2018, and are offset by higher realized prices recorded for crude oil. In addition, expenses increased due to the ~~commodities we produce.~~Heidelberg field.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, ~~increased~~decreased to ~~$11.63~~$11.25 per Boe for the three months ended ~~June 30, 2018~~March 31, 2019 from ~~$10.29~~$11.44 per Boe for the three months ended ~~June 30, 2017.~~March 31, 2018. On a nominal basis, DD&A decreased to ~~$39.8~~$33.8 million (or ~~1.5%~~11.3%) for the three months ended ~~June 30, 2018~~March 31, 2019 from ~~$40.4~~$38.1 million for the three months ended ~~June 30, 2017.~~March 31, 2018. DD&A on a nominal basis decreased primarily due to lower production. Other factors affecting the DD&A rate are production, capital expenditures, ~~changes in future development costs on remaining reserves~~sales of assets and ~~an increase~~changes in proved reserves volumes.

General and administrative expenses (“G&A”). G&A was ~~$14.2~~$14.1 million for the three months ended ~~June 30, 2018,~~March 31, 2019, decreasing ~~13.7%~~6.2% from ~~$16.5~~$15.0 million for the three months ended ~~June 30, 2017.~~March 31, 2018. The decrease was primarily due to ~~decreases~~a decrease in ~~share-based compensation as there have been no RSU grants in 2018 and in lower legal costs.~~incentive compensation. G&A on a per Boe basis was ~~$4.16~~$4.70 per Boe for the three months ended ~~June 30, 2018~~March 31, 2019 compared to ~~$4.20~~$4.52 per Boe for the three months ended ~~June 30, 2017.~~March 31, 2018.

Derivative ~~(gain)~~ loss. ~~We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production.~~ The three months ended ~~June 30, 2018~~March 31, 2019 reflects a ~~$6.2~~$48.9 million derivative ~~loss. We entered into derivative contracts for~~loss primarily due to increased crude oil ~~and natural gas~~prices during March 2019 as compared to oil prices during December 2018, which decreased the ~~first quarter~~estimated fair value of ~~2017 relating to a portion of our 2017 estimated production. The~~open crude oil contracts between the two measurement dates. For the three months ended ~~June 30, 2017 reflects a $3.7 million derivative gain primarily for our crude oil~~March 31, 2018, we did not have any gains or losses from derivative contracts.

Interest expense, net. Interest expense, net, was ~~$12.1~~$16.3 million and ~~$11.4~~$11.0 million for the three months ended ~~June 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. ~~The increase is primarily due~~During 2018, a portion of our interest was recorded as offsets to ancarrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60, Troubled Debt Restructuring (“ASC 470-60”), which lowered reported interest ~~accrual related to a royalty issue with the ONRR on production that dates back 10 to 15 years.~~ ~~See Financial Statements - Note 2 – Long-Term Debt~~ ~~under Part I, Item 1 of this Form 10-Q~~expense for ~~additional information on our debt.~~

~~Gain on exchange of debt. For~~ the three months ended ~~June 30, 2017, an additional net gain of $8.1 million was recognized primarily as a result of paying interest in cash on~~March 31, 2018 and affects 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 three months ended June 30, 2017, other 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. ~~See Financial Statements - Note 11– Contingencies~~ ~~under Part I, Item 1 of this Form 10-Q for additional information on the Apache lawsuit.~~comparability.

Income tax ~~expense (benefit).~~expense. Our income tax expense for the three months ended ~~June 30,~~March 31, 2019 and 2018 was $0.2 million and $0.1 million, and our income tax benefit for the three months ended June 30, 2017 was $9.0 million. Our current full-year forecast for 2018 has a net operating loss for tax purposes; therefore, no current tax expense was recorded related to the full-year forecast. Norespectively. Immaterial deferred income tax expense was recorded for the three months ended ~~June 30, 2018~~March 31, 2019 due to dollar-for-dollar offsets by our valuation allowance. Our effective tax rate using book pre-tax income was not meaningful for either period. For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets. As of March 31, 2019, our valuation allowance was $127.8 million. We continually evaluate the need to maintain a valuation allowance on our deferred tax assets. Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs.See Financial Statements – Note 98 –Income Taxes ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Six Months Ended June 30, 2018 Compared to the Six Months Ended June 30, 2017~~

~~Revenues~~. Total revenues increased $36.1 million, or 14.6%, to $283.8 million for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. Oil revenues increased $43.3 million, or 25.4%, NGLs revenues increased $2.6 million, or 16.4%, natural gas revenues decreased $10.2 million, or 17.2%, and other revenues increased $0.4 million. The increase in oil revenues was attributable to a 41.9% increase in the average realized sales price to $64.93 per barrel for the six months ended June 30, 2018 from $45.76 per barrel for the six months ended June 30, 2017, partially offset by a decrease in sales volumes of 11.6%. The increase in NGLs revenues was attributable to a 26.5% increase in the average realized sales price to $27.57 per barrel for the six months ended June 30, 2018 from $21.80 per barrel for the six months ended June 30, 2017, partially offset by a decrease in sales volumes of 8.0%. The decrease in natural gas revenues was attributable to a decrease in sales volumes of 3.2 Bcf, or 15.9% and a 1.7% decrease in the average realized price to $2.92 per Mcf for the six months ended June 30, 2018 from $2.97 per Mcf for the six months ended June 30, 2017. Overall, production volumes decreased 13.1% on a Boe basis. The largest production increases for the six months ended June 30, 2018 compared to the three months ended June 30, 2017 were from our newly acquired interest in the Heidelberg field and our Ship Shoal 300 field. Revenue and production was adjusted for royalty relief on two of our deepwater fields related to their 2017 and 2016 production and realized prices which is recognized in the subsequent year. This royalty relief impact to revenues and production during the six months ended June 30, 2018 and 2017 was $1.0 million and $5.0 million, respectively and 286 Boe per day and 967 Boe per day, respectively. Offsetting were production decreases primarily due to natural production declines. Production for the six months ended June 30, 2018 was also negatively impacted by maintenance, well issues and pipeline outages that collectively resulted in deferred production of 4,400 Boe per day. During the six months ended June 30, 2017, deferred production was 2.600 Boe per day.

Revenues from oil and liquids as a percent of our total revenues were 81.9% for the six months ended June 30, 2018 compared to 75.2% for the six months ended June 30, 2017. Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 42.5% for the six months ended June 30, 2018 compared to 47.6% for the six months ended June 30, 2017.

~~Lease operating expenses.~~ Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, increased $0.7 million, or 1.0%, to $72.4 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017. On a component basis, base lease operating expenses increased $1.4 million, insurance premiums increased $1.3 million, workover expenses decreased $1.8 million, and facilities maintenance expense decreased $0.2 million. Base lease operating expenses increased primarily due the addition of the Heidelberg field; lower product handling and operating charges to an outside party at our Matterhorn field and higher incentive compensation expenses. The insurance premium increase is primarily due to our insurance policies related to named windstorms, which had better coverage between the two periods. The decrease in workover expense was primarily due to a project at our Mahogany field that did not re-occur in 2018. The facility maintenance expense decrease is primarily attributable to compressor overhauls and pipeline projects in 2017, which did not re-occur at the same expense level during 2018.

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

~~Gathering and transportation.~~ Gathering and transportation expenses decreased $1.5 million to $10.0 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 primarily due to lower production volumes of all of the commodities we produce.

~~Depreciation, depletion, amortization and accretion.~~ DD&A, which includes accretion for ARO, increased to $11.54 per Boe for the six months ended June 30, 2018 from $10.35 per Boe for the six months ended June 30, 2017. On a nominal basis, DD&A decreased to $77.8 million (3.1%) for the six months ended June 30, 2018 from $80.4 million for the six months ended June 30, 2017. DD&A on a nominal basis decreased primarily due to lower production. Other factors affecting the DD&A rate are capital expenditures, changes in future development costs on remaining reserves and an increase in proved reserves volumes.

~~General and administrative expenses~~. G&A was $29.3 million for the six months ended June 30, 2018, down 1.6% from $29.7 million for the six months ended June 30, 2017. Decreases in legal costs and share-based compensation as there have been no RSU grants in 2018 and were partially offset by increases in cash-based incentive programs. G&A on a per Boe basis was $4.34 per Boe for the six months ended June 30, 2018 compared to $3.83 per Boe for the six months ended June 30, 2017.

~~Derivative (gain) loss.~~ We entered into derivative contracts for crude oil during the second quarter of 2018 relating to a portion of our 2018 estimated production. The six months ended June 30, 2018 reflects a $6.2 million derivative loss. We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production. The six months ended June 30, 2017 reflects a $7.6 million derivative gain primarily for our crude oil derivative contracts.

~~Interest expense~~. Interest expense was $23.5 million and $22.7 million for the six months ended June 30, 2018 and 2017, respectively. The increase is primarily due to an interest accrual related to a royalty issue with the ONRR on production that dates back 10 to 15 years. ~~See Financial Statements - Note 2 – Long-Term Debt~~ ~~under Part I, Item 1 of this Form 10-Q for additional information on our debt.~~

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

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

~~Income tax expense (benefit).~~Our income tax expense for the six months ended June 30, 2018 was $0.2 million and our income tax benefit for the six months ended June 30, 2017 was $16.6 million. Our current full-year forecast for 2018 has a net operating loss for tax purposes; therefore, no current tax expense was recorded related to the full-year forecast. No deferred income tax expense was recorded for the six months ended June 30, 2018 due to dollar-for-dollar offsets by our valuation allowance. Our effective tax rate using book pre-tax income was not meaningful for either period. For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets. See ~~Financial Statements – Note 9 –Income Taxes~~ under Part I, Item 1 of this Form 10-Q for additional information.

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.~~AROs. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank ~~borrowings.~~

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

Credit Agreement. On October 18, 2018, we entered into the ~~interpretation of existing regulations.~~

~~Our~~ Credit Agreement, which matures on ~~November 8, 2018.~~October 18, 2022. As of ~~June 30, 2018,~~March 31, 2019, we had ~~$9.7~~$21.0 million borrowings outstanding under the Credit Agreement and $8.1 million of letters of credit outstanding and no amounts borrowed on our revolving bank credit facility. In April 2018, we consummated a transaction acquiring a 9.375% non-operated working interest in the Heidelberg field, which resulted in the issuance of a letter of credit of $9.4 million and depositing $4.7 million cash with our lead bank under the terms of the Credit Agreement.

Our Unsecured Senior Notes mature on June 15, 2019 and if the Unsecured Senior Notes have not been extended, refunded, defeased, discharged, replaced or refinanced by February 28, 2019, then the 11.00% 1.5 Lien Term Loan, due November 15, 2019, and the 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021, will both accelerate their maturity to February 28, 2019. If the maturity of these two instruments were to be accelerated, approximately $234.8 million would be payable on February 28, 2019. During 2018, we plan to address the potential maturity acceleration of these two debt instruments and to extend or replace the revolving bank credit facility. We expect to build sufficient cash balances in 2018 to be able to redeem, repurchase or refinance the Unsecured Senior Notes. Certain amendmentsissued under the Credit ~~Agreement and~~Agreement. During the ~~1.5 Lien Term Loan will likely be required in~~three months ended March 31, 2019, we did not have any additional borrowings or repayments under the event we redeem or repurchase the Unsecured Senior Notes, which we anticipate would be granted if requested. If we are in a position to repay or refinance the 1.5 Lien Term Loan, then we would expect to extend the maturity of our revolving bank credit facility. There can be no assurance that lenders will extend our revolving bank credit facility maturity, but under current market conditions and based on the outlook of our cash position in 2018 and further, we believe our lenders or replacement lenders will be amenable to participating in a refinancing or corporate financing transaction.

Credit ~~Agreement. Availability on our revolving bank credit facility as of June 30, 2018 was $140.3 million.~~Agreement. Availability under our ~~revolving bank credit facility~~Credit Agreement as of March 31, 2019 was $220.9 million.

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, ~~that occurs in~~with the ~~spring and fall of each year and is calculated~~next redetermination to be completed by ~~our lenders based on their evaluation of our proved reserves and their own internal criteria. The 2018 spring redetermination reaffirmed the borrowing base amount at $150.0 million.~~May 15, 2019. 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.~~Credit Agreement. The ~~revolving bank credit facility~~Credit Agreement is secured and is collateralized by substantially all of our oil and natural gas ~~properties.~~ properties and certain personal property.

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

Senior Second Lien Notes. As of March 31, 2019, we had outstanding $625.0 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements – Note 2 –Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

Debt Covenants.The Credit Agreement ~~contains~~and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit ~~Agreement.~~Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of ~~June 30, 2018.~~March 31, 2019.

~~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. We were in compliance with all applicable covenants of our long-term debt agreements as of June 30, 2018.~~

BOEM Matters. As of the filing date of this Form 10-Q, ~~the Company is~~we are in compliance with ~~its~~our financial assurance obligations to the BOEM and ~~has~~have no outstanding BOEM orders related to financial assurance obligations. During April 2018, we posted an additional $10 million of bonds as requested by BOEM to account for decommissioning obligations that accrued on sole-liability properties during the Company’s period of leasing. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.

Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. No additional demands were made to us by sureties during ~~2018~~2019 as of the filing date of ~~the~~this Form 10-Q.

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

Cash Flow and Working Capital. Net cash provided by operating activities for the ~~six~~three months ended ~~June 30,~~March 31, 2019 and 2018 was ~~$115.2~~$84.8 million ~~compared to $65.6~~and $75.0 million, ~~for the six months ended June 30, 2017. The change between periods is primarily due to higher realized prices for crude oil and NGLs, and lower spending for ARO activities.~~respectively. Our combined average realized sales price per Boe ~~increased 31.9% in~~decreased 4.0% for the ~~six~~three months ended ~~June 30,~~March 31, 2019 compared to the three months ended March 31, 2018, which caused total revenues to ~~increase $66.2 million, partially offset~~decrease $8.0 million. Production volumes decreased by ~~decreases of 13.1%~~9.8% primarily from increases in ~~production volumes~~downtime, which caused revenues to decrease by ~~$30.5~~$9.8 million. In addition, operating expenses impacting operating cash flows increased by $8.3 million primarily for workover and facility projects.

Other items affecting operating cash flows was an increase of $44.6 million for the ~~six~~three months ended ~~June 30, 2018 were~~March 31, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to $19.1 million for the three months ended March 31, 2018. ARO settlements ~~of $12.1~~were $0.3 million for the three months ended March 31, 2019, which decreased from ~~$36.0~~$7.0 million infor the ~~prior period.~~three months ended March 31, 2018. During the ~~six~~three months ended ~~June 30, 2017, we received insurance reimbursements of $30.1~~March 31, 2019, cash derivative receipts, net, were $11.9 million ~~and made a deposit related~~primarily due to ~~the Apache matter of $49.5 million.~~derivative oil contracts. Working capital items accounted for the balance of the change in net cash provided by operating activities.

Net cash used in investing activities ~~during~~for the ~~six~~three months ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~ was ~~$77.8~~$31.6 million and ~~$45.5~~$41.3 million, respectively, which represents our investments in oil and gas properties and equipment. ~~Investments in oil and natural gas properties on an accrual basis~~The majority of our capital expenditures for the three months ended March 31, 2019 were for investments in the ~~six months ended June 30, 2018 were $31.8 million compared to $43.8 million for~~deep waters of the ~~six months ended June 30, 2017. The capital expenditures during the six months ended June 30, 2018 related to investments with the majority in the conventional shelf~~Gulf of Mexico and, to a lesser extent, on the conventional shelf of the Gulf of Mexico. There were no material acquisitions or asset sales in the ~~deep water. Adjustments from working capital changes associated with investing activities was a net cash decrease of $29.3 million in the six~~three months ended ~~June 30, 2018 compared to net cash decrease~~March 31, 2019 and a deposit of ~~$0.8~~$3.0 million inwas made during the ~~six~~three months ended ~~June 30, 2017. These amounts represent timing differences between when the work was performed and the payments are made. In addition,~~March 31, 2018 related to the Heidelberg ~~field net purchase price was $16.6 million during the six months ended June 30, 2018 and there were no similar investments~~acquisition consummated in ~~the prior year period.~~April 2018.

Net cash used by financing activities for the ~~six~~three months ended ~~June 30,~~March 31, 2019 and 2018, ~~and 2017~~respectively was ~~$7.1~~$0.4 million and ~~$18.0,~~$2.1 million, respectively. The net cash used for the ~~six~~three months ended ~~June 30,~~March 31, 2018 ~~and 2017~~ was ~~primarily attributable to the~~for interest payments on ~~the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes, which are~~certain debt reported as financing activities under ASC 470-60.

Derivative Financial Instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural ~~gas and interest rate risk from floating interest rates on our revolving bank credit facility.~~gas. During ~~the six months ended June 30,~~ 2018, we entered into derivative contracts for crude oil ~~which relate to volumes~~and natural gas for a portion of ~~11,000 barrels per day through December 2018.~~our future production. See Financial Statements – Note 76 – 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 $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention ~~(deductible)~~ of $30.0 million. Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention. The operational and named windstorm coverages are effective for one year beginning June 1, 2018. Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, ~~2018~~2019 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

Although we were able to renew our general and excess liability policies effective on May 1, ~~2018,~~2019, and we expect to renew our Energy Package effective on June 1, ~~2018,~~2019, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims. We do not carry business interruption insurance.

Capital Expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities. During the ~~six~~three months ended ~~June 30,~~March 31, 2018, we received reimbursement of capital expenditures from Monza for projects in the JV Drilling Program, some of which had incurred costs during 2017. These reimbursements related to 2017 are reported in a separate line in the table below. The following table presents our capital expenditures ~~on an accrual basis~~ for exploration, development and other leasehold ~~costs:~~ costs (in thousands):

	Six Months Ended
	June 30,						Three Months Ended
	2018			2017			March 31,
	(In thousands)						2019		2018
Exploration ⁽¹⁾	$	4,322		$	(401	)	$	4,251	$	2,718
Development ⁽¹⁾		33,003			42,440			17,269		30,907
Heidelberg field		16,617			—
Reimbursement from Monza for 2017 expenditures		(14,075	)		—			—		(14,075	)
Seismic, JV Drilling Program and other		8,553			1,761
Seismic and other								9,113		1,567
Investments in oil and gas property/equipment	$	48,420		$	43,800		$	30,633	$	21,117

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

	Six Months Ended
	June 30,				Three Months Ended
	2018		2017		March 31,
	(In thousands)				2019		2018
Conventional shelf	$	28,128	$	41,032	$	6,079	$	24,284
Deepwater		9,197		1,007		15,441		9,341
Exploration and development capital expenditures	$	37,325	$	42,039	$	21,520	$	33,625

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

Our capital expenditures for the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019 were financed by cash flow from operations and cash on hand.

During the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, we completed one of two target zones for the ~~A-17~~Virgo A-13 well, ~~at Mahogany,~~ which began producing during March ~~2018 and we~~2019. The other target zone for the Virgo A-13 well was completed ~~the Viosca Knoll 823 (“Virgo”) A-10 ST well, which began production during~~in April ~~2018.~~2019. The Virgo ~~A-10 ST~~A-13 well is in the JV Drilling Program. During the ~~six~~three months ended ~~June 30, 2017,~~March 31, 2018, we completed ~~three~~two wells. We did not drill any dry holes in either ~~period.~~period presented.

Exploration/Development Activities. As of ~~July 31, 2018,~~April 15, 2019, we were drilling on the ~~Virgo A-12 well~~South Timbalier 320 A-3 and the South Timbalier 311 A-2 well. During July 2018, we completed the Mahogany A-5 well and it began producing in July 2018. The Main Pass 286 #1 well has been cased and is waiting for development sanction. EachMississippi Canyon 800 SS2 wells, both of ~~these four wells is in the JV Drilling Program. In addition, we have moved the rig at Mahogany to drill the A-19 well,~~ which ~~is not~~are in the JV Drilling Program.

Offshore Lease Awards. WeDuring the three months ended March 31, 2019, we were ~~successful in obtaining nine new leases~~the apparent high bidder on 15 blocks (eight deepwater and seven shallow water) in the ~~Central and Eastern~~ Gulf of ~~Mexico. The new leases are primarily located near or offsetting our existing properties~~Mexico Lease Sale 252 held by the BOEM on March 20, 2019. These 15 blocks cover approximately 73,500 acres and, ~~were acquired in total~~if awarded, we will pay approximately $3.5 million for ~~less than $1.0 million, net to our interest.~~

~~Divestitures.~~ ~~Periodically, we sell properties as part~~all of the ~~management~~awarded leases combined, which reflects a 100% working interest in the acreage. As of ~~our property portfolio. During~~ the ~~six months ended June 30, 2018,~~filing date of this Form 10-Q, we ~~did not~~ have ~~any property sales~~received official notice of ~~significance.~~being awarded one of the leases and we expect to receive official notice related to the other leases within 90 days of the lease sale date.

Capital Expenditure ~~Budget and Expected Production for 2018.~~Budget. Our current ~~2018~~2019 capital expenditure forecast is approximately ~~$95~~$120 million, which excludes ~~the Heidelberg field transaction and excludes other~~ potential acquisitions. The forecast ~~also~~ incorporates the ~~JV Drilling Program. Our 2018 capital expenditure program includes participation~~shared investments in 10certain wells ~~seven of which are~~ included in the ~~2018~~ JV Drilling Program. We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.

Income Taxes. As of ~~June 30, 2018,~~March 31, 2019, we ~~have~~had current income ~~tax receivables~~taxes receivable of ~~$65.2~~$54.1 million. The current income tax receivables include an estimated net operating loss claim for 2017 of $13.1 million, which is expected to be received during 2018. The other component of current income tax receivables relates to our net operating loss claims totaling $52.1 million for the years 2012, 2013 and 2014 that were carried back to prior years and are expected to be received in 2018. These receivables relate to claims under rules ~~for “specified liability losses”~~ ~~made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.~~ For ~~2018,~~2019, we do not expect to make any significant income tax payments. See Financial Statements – Note 98 –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, 2018~~March 31, 2019 and December 31, ~~2017~~2018 were ~~$317.2~~$314.2 million and ~~$300.4~~$310.1 million, respectively. Our plans include spending ~~$37.6~~$24.0 million in ~~2018~~2019 for ARO compared to ~~$72.4~~$28.6 million spent on ARO in ~~2017.~~2018. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 for additional information.

Contractual Obligations. Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt and Note 65 – Asset Retirement Obligations, and under Part I, Item 1 of this Form 10-Q. As of ~~June 30, 2018,~~March 31, 2019, drilling rig commitments, excluding ARO drilling rig commitments, were approximately ~~$5.4~~$9.2 million, ~~compared to $5.7 million~~which was approximately the same as the amount as of December 31, 2017. In conjunction with the purchase of the Heidelberg field interest, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million.2018. Except for scheduled utilization, other contractual obligations as of ~~June 30, 2018~~March 31, 2019 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, ~~2017. Also refer to~~2018. See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1 of this Form ~~10-Q.~~10-Q for additional information.

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

Information about market risks for the three months ended ~~June 30, 2018~~March 31, 2019 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and could have impacts on our business in the future. During ~~the second quarter of~~ 2018, we entered into derivative crude oil contracts related to a portion of our estimated ~~production for the remainder of 2018.~~future production. We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments. Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements. See Financial Statements – Note 76 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk. As of ~~June 30, 2018,~~March 31, 2019, we had no$21.0 million borrowings outstanding ~~borrowings on~~under our ~~revolving bank credit facility. The revolving bank credit facility has a~~Credit Agreement and were subject to the 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, 2018, we~~Applicable Margin. We did not have any derivative instruments related to interest rates.

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, 2018,~~March 31, 2019, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended ~~June 30, 2018,~~March 31, 2019, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See Financial Statements – Note 1110 – Contingencies, under Part I Item 1 of this Form 10-Q for information on various legal ~~matters.~~proceedings to which we are a party or our properties are subject.

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

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~~May 2, ~~2018.~~2019.

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

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


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

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

		Page
PART I –FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	1
	Condensed Consolidated Statements of Operations for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	2
	Condensed Consolidated Statement of Changes in Shareholders’ Deficit for the ~~Six~~Three Months Ended ~~June 30,~~March 31, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows for the ~~Six~~Three Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3221
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4531
Item 4.	Controls and Procedures	4632

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4633
Item 1A.	Risk Factors	4633
Item 6.	Exhibits	4734

SIGNATURE		4835

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

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

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

	June 30,		December 31,
	2018		2017
Prepaid/accrued insurance	$	4,526	$	2,401
Surety bond unamortized premiums		3,305		2,676
Prepaid deposits related to royalties		8,391		6,456
Advances for capital expenditures		1,098		—
Derivative contract premiums		1,582		—
Other		1,568		1,886
Prepaid expenses and other assets	$	20,470	$	13,419


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

	June 30, 2018								December 31, 2017
			Adjustments to								Adjustments to
			Carrying			Carrying					Carrying			Carrying
	Principal		Value ⁽¹⁾			Value			Principal		Value ⁽¹⁾			Value
11.00% 1.5 Lien Term Loan, due November 2019:
Principal	$	75,000	$	—		$	75,000		$	75,000	$	—		$	75,000
Future interest payments		—		11,482			11,482			—		15,596			15,596
Subtotal		75,000		11,482			86,482			75,000		15,596			90,596

9.00 % Second Lien Term Loan, due May 2020:		300,000		—			300,000			300,000		—			300,000

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020:
Principal		177,513		—			177,513			171,769		—			171,769
Future payments-in-kind		—		—			—			—		5,745			5,745
Future interest payments		—		31,952			31,952			—		34,872			34,872
Subtotal		177,513		31,952			209,465			171,769		40,617			212,386

8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021:
Principal		160,852		—			160,852			153,192		—			153,192
Future payments-in-kind		—		3,664			3,664			—		11,323			11,323
Future interest payments		—		38,682			38,682			—		38,682			38,682
Subtotal		160,852		42,346			203,198			153,192		50,005			203,197

8.50% Unsecured Senior Notes, due June 2019		189,829		—			189,829			189,829		—			189,829

Debt premium, discount, issuance costs, net of amortization		—		(3,258	)		(3,258	)		—		(3,956	)		(3,956	)
Total long-term debt		903,194		82,522			985,716			889,790		102,262			992,052
Current maturities of long-term debt ⁽²⁾		189,829		34,917			224,746			—		22,925			22,925
Long term debt, less current maturities	$	713,365	$	47,605		$	760,970		$	889,790	$	79,337		$	969,127

	Hierarchy	June 30, 2018		December 31, 2017
11.00% 1.5 Lien Term Loan, due November 2019	Level 2	$	75,000	$	75,000
9.00 % Second Lien Term Loan, due May 2020	Level 2		300,000		288,000
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020	Level 2		177,513		162,322
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021	Level 2		153,614		119,490
8.50% Unsecured Senior Notes, due June 2019	Level 2		187,931		178,439

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

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

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

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

													Consolidated
	Parent			Guarantor			Non-Guarantor						W&T
	Company			Subsidiaries			Adjustments			Eliminations			Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	129,440		$	—		$	—		$	—		$	129,440
Receivables:
Oil and natural gas sales		8,109			44,161			(197	)		—			52,073
Joint interest		19,366			—			—			—			19,366
Income taxes		193,594			—			—			(128,354	)		65,240
Total receivables		221,069			44,161			(197	)		(128,354	)		136,679
Prepaid expenses and other assets		16,739			3,700			31			—			20,470
Total current assets		367,248			47,861			(166	)		(128,354	)		286,589

Oil and natural gas properties and other, net		416,539			121,075			48,003			(9,544	)		576,073
Restricted deposits for asset retirement obligations		26,072			—			—			—			26,072
Other assets		607,463			544,029			(46,464	)		(1,035,610	)		69,418
Total assets	$	1,417,322		$	712,965		$	1,373		$	(1,173,508	)	$	958,152
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	38,445		$	6,457		$	1,562		$	—		$	46,464
Undistributed oil and natural gas proceeds		21,390			1,259			—			—			22,649
Asset retirement obligations		21,663			6,260			—			—			27,923
Current maturities of long-term debt:
Principal		189,829			—			—			—			189,829
Carrying value adjustments		34,917			—			—			—			34,917
Current maturities of long-term debt - carrying value		224,746			—			—			—			224,746
Accrued liabilities		20,523			128,336			—			(128,354	)		20,505
Total current liabilities		326,767			142,312			1,562			(128,354	)		342,287
Long-term debt:
Principal		713,365			—			—			—			713,365
Carrying value adjustments		47,605			—			—			—			47,605
Long term debt, less current portion - carrying value		760,970			—			—			—			760,970

Asset retirement obligations, less current portion		164,010			125,275			12			—			289,297
Other liabilities		663,239			—			—			(590,232	)		73,007
Shareholders’ deficit:
Common stock		1			—			—			—			1
Additional paid-in capital		548,196			704,885			—			(704,885	)		548,196
Retained earnings (deficit)		(1,021,694	)		(259,507	)		(201	)		249,963			(1,031,439	)
Treasury stock, at cost		(24,167	)		—			—			—			(24,167	)
Total shareholders’ equity (deficit)		(497,664	)		445,378			(201	)		(454,922	)		(507,409	)
Total liabilities and shareholders’ equity (deficit)	$	1,417,322		$	712,965		$	1,373		$	(1,173,508	)	$	958,152

Volume ~~measurements:~~measurements not previously defined:
~~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~~Mcf — thousand cubic feet
MBoe -— thousand barrels of oil equivalent		~~MMcfe -~~MMcf — million cubic feet ~~equivalent~~

Exhibit Number		Description

3.1		Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

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

3.3		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))
3.4
~~3.4~~		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc., dated as of September 6, 2016. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed September 6, 2016 (File No. 001-32414))
3.5		Second Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed March 22, 2019 (File No. 001-32414))
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.


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