HOUSTON, Nov. 2, 2016 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its third quarter 2016 operational and financial results, as well as its 2016 fourth quarter and full year production and expense guidance.  Some of the key items for the third quarter include:

• On September 7, 2016, completed an Exchange Transaction (defined and described below) of $710.2 million, or approximately 79%, of our 8.50% Senior Notes due 2019 for new secured notes and common stock. At the same time we closed on a new $75 million 1.5 Lien Term Loan. The Company recognized a gain on the debt exchange of $124.0 million.
• Production for the third quarter of 2016 averaged 41,508 barrels of oil equivalent ("Boe") per day (3.8 million Boe for the quarter), 56.6% of which was oil and natural gas liquids ("NGLs").
• Drilling has resumed on the A-18 well at Ship Shoal 349, Mahogany.
• Revenues were $107.4 million, 72.3% of which was from oil and NGLs.
• Lease operating expenses (LOE) declined 16.7% to $37.5 million compared to the third quarter of 2015 reflecting our continued focus on cost reduction efforts.
• General and administrative (G&A) expenses decreased 23.2% to $12.7 million compared to the third quarter of 2015.
• Net income for the third quarter of 2016 was $45.9 million and earnings per share were $0.48. Excluding special items, our net income would have been a loss of $22.6 million or $0.24 per share. Adjusted EBITDA was $52.5 million for the third quarter of 2016 compared to $61.4 million in the third quarter of 2015. (See definitions and reconciliations of non-GAAP measures to GAAP measures at the end of this release.)

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "We are pleased to have received the support of our shareholders and senior noteholders in completing our Exchange Transaction, significantly improving our liquidity which in turn will allow us to turn our focus toward new capital projects. While operating margins are still below our historic levels, they have improved from early in the year, allowing us to expand our capital program in 2016, currently estimated at $60 million, and pursue projects that were delayed when margins began declining rapidly.  We are currently working on our plan for 2017 and expect to increase our capital budget to levels well above 2016 expenditures.  We intend to devote more capital to drilling and completing new wells along with an expanded recompletion program.

"We are currently drilling the Ship Shoal 349 A-18 development well in our Mahogany field, targeting the 'T' sand that has produced so prolifically in the field's A-14 well since mid-2013. During the industry downturn, we remained focused on evaluating the drilling and production data from certain of the other wells drilled in the field, as well as the advanced seismic data we have acquired and interpreted to help us better understand Mahogany's sub-salt opportunities.  Additionally, we have a number of recompletion and workover opportunities planned, including two workovers at Mahogany, which offer low risk and solid returns from wells that were drilled in stacked reservoirs with multiple pay zones.  These projects help us to maintain our production profile with a modest capital budget.

"Although we are encouraged by the improved commodity prices, we remain diligent about cost control and are maintaining a prudent approach to spending.  Over the last two years, we have reduced LOE by 48% and G&A expense by 40% and believe that we can continue to drive down costs.  Our objective is to maintain steady production on a modest capital budget in the range of $75 million to $150 million per year until we are confident that the time is right to return to a more robust growth profile," added Mr. Krohn. 

Exchange Transaction:  On September 7, 2016, we consummated an exchange transaction that reduced our long-term debt by $408.2 million, excluding our new 1.5 Lien Term Loan (defined below) and before changes that result from accounting for the Exchange Transaction as a Troubled Debt Restructuring (described below).  We exchanged approximately 79% of our 8.500% Senior Notes, due June 15, 2019 (the "Unsecured Senior Notes") in an aggregate principal amount of $710.2 million for: (i) 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 2020, in an aggregate principal amount of $159.8 million (the "Second Lien PIK Toggle Notes"); (ii) 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021, in an aggregate principal amount of $142.0 million (the "Third Lien PIK Toggle Notes"); and (iii) 60.4 million shares of our common stock (the "Debt Exchange").  The Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes contain payment-in-kind ("PIK") interest provisions, where certain semiannual interest is added to the principal amount instead of being paid in cash in the then current semiannual period. In conjunction with the Debt Exchange, we issued a $75 million 1.5 Lien Term Loan with an interest rate of 11%, due November 2019 (the "1.5 Lien Term Loan") (collectively with the Debt Exchange, the "Exchange Transaction").  We accounted for the Exchange Transaction as a Troubled Debt Restructuring ("TDR") pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring.  The Exchange Transaction resulted in a gain of $124.0 million due to the fact that the sum of the future undiscounted principal and interest payments of the newly issued debt was less than the net carrying value of the original debt (after adjusting for the consideration in the form of the shares of common stock, transaction costs of the Exchange Transaction, and the funds received from the issuance of the 1.5 Lien Term Loan).  Under TDR accounting, all future principal and interest payments have been recorded as a liability; therefore, no interest expense was recorded for the new debt in September 2016 and no future interest expense will be recorded for the new debt, thus our reported interest expense will be significantly less than the contractual interest payments through the terms of the new debt.  To the extent interest on the new debt is paid in cash in future periods it will reduce the liability recorded in connection with such debt. 

Production, Revenues and Price: For the third quarter of 2016, our oil production was 1.8 million barrels, down 9.2% from the third quarter of 2015.  NGL production was 371,571 barrels, down 4.4% from the third quarter of 2015 and natural gas production was 9.9 billion cubic feet ("Bcf") for the third quarter of 2016, down 14.6% from the third quarter of 2015.  Our combined total production was 3.8 million barrels of oil equivalent ("MMBoe") in the third quarter of 2016, down 11.2% from the third quarter of 2015.  Production was lower in the third quarter of 2016 compared to the third quarter of 2015 due to natural production declines, pipeline outages, field and platform maintenance and the loss of production as a result of the sale of our Yellow Rose field in October 2015.  This was partially offset by new oil production from the development of certain deepwater fields within the last year (Big Bend, Dantzler and EW 910).

During the quarter we experienced production deferrals attributable to third-party pipeline outages, operational issues, and maintenance, which occurred at Mahogany, East Cameron 321 A and various other locations.  We estimate production deferrals reduced our quarterly production by approximately 0.2 MMBoe during the third quarter of 2016.

Revenues for the third quarter of 2016 were $107.4 million compared to $126.2 million in the third quarter of 2015.  The decrease in revenues was primarily due to a 3.3% decline in realized commodity prices, combined with an 11.2% decrease in production.  Our average realized crude oil sales price was down $4.23 per barrel, or 9.6%, between the two quarters.  NGLs prices improved 7.6%, or $1.28 per barrel and natural gas prices improved 8.9% or $0.24 per Mcf from the third quarter of 2015.  During the third quarter of 2016, our average realized sales price for oil was $39.62 per barrel, $18.02 per barrel for NGLs and $2.93 per Mcf for natural gas.  On a combined basis, we sold 41,508 Boe per day at an average realized sales price of $27.97 per Boe compared to 46,757 Boe per day sold at an average realized sales price of $28.92 per Boe in the third quarter of 2015. 

West Texas Intermediate ("WTI") crude oil prices averaged $41.35 per barrel for the first nine months of 2016 compared to our average realized crude oil price of $35.01 per barrel. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Just like crude oil prices, the differentials for our offshore crude oil have also experienced significant volatility.  For example, the monthly average differentials of WTI crude oil prices versus Light Louisiana Sweet ("LLS"), Heavy Louisiana Sweet ("HLS") and Poseidon crude oil prices for the first nine months of 2016 were a positive $1.79 and $0.87, and a negative $3.58 per barrel, respectively. The majority of our crude oil is priced similar to Poseidon and, therefore, is experiencing negative differentials.  In addition, a few of our crude oil fields have a negative quality bank adjustment due to crude oil quality which reduces our crude oil price realizations.

Lease Operating Expenses: LOE, which includes base lease operating expenses, insurance premiums, workovers, and facilities maintenance, decreased $7.5 million, or 16.7%, to $37.5 million in the third quarter of 2016 compared to the third quarter of 2015.  On a per Boe basis, LOE decreased to $9.82 per Boe in the third quarter of 2016, a 6.2% reduction compared to $10.47 per Boe in the third quarter of 2015.  On a component basis, base lease operating expenses decreased $1.1 million, workover expense decreased $4.9 million, insurance premiums decreased $1.7 million and facilities maintenance increased $0.2 million.  Base lease operating expenses decreased primarily due to lower costs from service providers and the elimination of field expenses related to the Yellow Rose field which was sold in October 2015, partially offset by costs related to our new deepwater fields at Dantzler and Big Bend and lower production handling fees (cost offsets) at our Mississippi Canyon 243 field (Matterhorn).  The decrease in workover costs was primarily due to the sale of the Yellow Rose field and reduced activities offshore.   

Depreciation, depletion, amortization and accretion ("DD&A"):  DD&A, including accretion for ARO, decreased to $13.49 per Boe for the third quarter of 2016 from $22.62 per Boe for the third quarter of 2015.  On a nominal basis, DD&A decreased to $51.5 million for the third quarter of 2016 from $97.3 million for the third quarter of 2015 due to a decrease in the DD&A rate per Boe and lower production volumes. DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2015 and the first half of 2016 (the third quarter 2016 ceiling test write-down will not affect the DD&A rate until the fourth quarter of 2016) and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A.  In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field reserves.  Other factors affecting the DD&A rate are lower future development costs and lower proved reserves.     

Ceiling test write-down of oil and natural gas properties:  For the third quarter of 2016, we recorded a non-cash ceiling test write-down of $57.9 million as the book value of our proved oil and natural gas properties exceeded the ceiling test limitation. The write-down is primarily the result of decreases in prices for crude oil as the twelve month moving average has continued to move down under SEC pricing methodology.  For the third quarter of 2015, the ceiling test write-down was $441.7 million. 

General and Administrative Expenses ("G&A"):  G&A decreased $3.8 million, or 23.2% to $12.7 million for the third quarter of 2016 compared to the third quarter of 2015.  The decrease was primarily due to reclassifying transaction costs associated with the Exchange Transaction previously recorded in G&A expense to Gain on exchange of debt.  In addition, decreases in headcount related expense (salaries, benefits, and contractor expenses) and elimination of certain employee benefits also contributed to the decrease.

Derivatives:  For the third quarter of 2016, we recorded a $0.4 million net derivative loss on derivative contracts for crude oil and natural gas.  For the third quarter of 2015, there was a $10.2 million net derivative gain recorded.  A report providing our commodity derivative positions is posted to our website. 

Interest expense:  Interest expense incurred was $23.7 million in the third quarter of 2016, compared to $28.8 million in the third quarter of 2015.  The decrease was primarily attributable to the Exchange Transaction.  Interest expense was reduced for the Unsecured Senior Notes exchanged on September 7, 2016 (the close date).  For the new debt issued, undiscounted future cash flows (principal, PIK and cash interest) are recorded as liabilities under the accounting guidance for TDR; therefore, no interest expense was recorded for the new debt for the period of September 7, 2016 to September 30, 2016.  In addition, interest expense was lower due to lower average borrowings on the revolving bank credit facility.  To the extent interest on the new debt is paid in cash in future periods it will reduce the liability recorded in connection with such debt. 

Gain on Exchange of Debt:  Under the accounting guidance for TDR, a gain of $124.0 million was recorded related to the Exchange Transaction.  The gain was measured as the difference between (i) the sum of; the future undiscounted principal and interest payments of the new debt (the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes, and the 1.5 Lien Term Loan);  the fair value of the common stock issued; and transaction costs associated with the Exchange Offer of $18.9 million and (ii) the sum of the principal amount of the Unsecured Senior Notes exchanged of $710.2 million, adjusted for related debt premium and debt issuance costs, and the funds received from the issuance of the 1.5 Lien Term Loan.      

Income Tax Benefit:  Our income tax benefit for the third quarter of 2016 and 2015 was $3.8 million and $18.5 million, respectively.  Our annualized effective tax rate for the third quarter of 2016 was not meaningful primarily due to adjustments related to the book gain associated with the Exchange Transaction.  For the third quarter 2015, our effective tax rate was 3.7%, and differs from the federal statutory rate of 35% primarily due to the valuation allowance recorded for our deferred tax assets.  During the three months ended September 30, 2016 and 2015, we recorded a valuation allowance decrease of $19.1 million and an increase of $156.2 million, respectively, related to federal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to generate 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. 

During the third quarter of 2016, we received an income tax refund of $5.6 million that relates to a net operating loss ("NOL") claim for 2015 carried back to 2005.  In the second quarter of 2016 we recorded $52.1 million as non-current income tax receivables related to our NOL claims for the years 2012, 2013 and 2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011.  These carryback claims are made pursuant to Internal Revenue Code ("IRC") Section 172(f) which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.

In connection with the privately negotiated exchange agreement to exchange a portion of our Unsecured Senior Notes for new Notes due in 2020 and 2021 and for our common stock, we realized a tax gain due to the concession extended by our note holders.  This tax gain will be offset by a reduction in our net operating losses and other deferred tax asset attributes. The reduction in our deferred tax assets will be fully offset by a corresponding reduction in our valuation allowance. 

Net Income (Loss) & Earnings (Loss) Per Share:  We reported net income for the third quarter of 2016 of $45.9 million or $0.48 per common share, compared to a reported net loss of ($477.6) million, or ($6.29) per common share, during the same period in 2015.  Excluding special items (including the ceiling test write-down of oil and natural gas properties, gain on exchange of debt, write-off of debt issuance and other non-operating costs, and an unrealized commodity derivative gain or loss, net of an applicable federal income tax adjustment), our net loss for the third quarter of 2016 was ($22.6) million and our loss per common share was ($0.24), compared to the third quarter of 2015 net loss of ($60.0) million, or ($0.79) per common share. Operating results for the third quarter of 2016, excluding special items, were down primarily due to a $18.8 million decrease in revenues resulting from a 3.3% decline in our realized sales prices and an 11.2% decline in production, partially offset by a $7.5 million decrease in LOE, a $3.8 million decrease in G&A and a $45.8 million decrease in DD&A.  See the "Reconciliation of  Net Loss to Net Loss Excluding Special Items" and related earnings per share, excluding special items in the table under "Non-GAAP Information" at the end of this news release for a description of the special items. 

Cash Flow and Adjusted EBITDA: Adjusted EBITDA and Adjusted EBITDA margin are non-GAAP measures and are defined in the "Non-GAAP Financial Measures" section at the end of this news release.  

Net cash used in operating activities for the first nine months of 2016 was $9.2 million compared to net cash provided by operating activities of $134.8 million for the same period in 2015. 

Cash flows from operating activities, before changes in working capital and asset retirement obligations ("ARO") settlements, were $42.8 million in the first nine months of 2016, compared to $125.5 million generated over the same period in 2015.  Cash flows declined as revenues were $118.4 million lower in the 2016 period compared to the 2015 period while operating expenses were $34.2 million lower over the same time period.  Asset retirement obligation settlements totaled $56.2 million in the first nine months of 2016. 

Adjusted EBITDA for the third quarter of 2016 was $52.5 million, down from $61.4 million generated over the same period in 2015.  Our Adjusted EBITDA margin was 49% for both periods.   For the nine months ended September 30, 2016 our Adjusted EBITDA was $109.8 million and our Adjusted EBITDA margin was 39% compared to Adjusted EBITDA of $189.4 million and an Adjusted EBITDA margin of 47% for the same period in 2015.

Liquidity:

On September 7, 2016, we closed on our new $75 million 1.5 Lien Term Loan, the proceeds of which were used to pay transaction costs associated with the Exchange Offer and to repay a portion of the borrowings outstanding under our revolving bank credit facility.

At September 30, 2016, our total liquidity was $222.5 million consisting of cash balances of $73.4 million and $149.1 million of availability under our revolving bank credit facility.

2016 Capital Expenditures Update:  Our capital expenditures on an accrual basis for the first nine months of 2016 were $24.1 million ($61.5 million on a cash basis) compared to $192.8 million ($258.3 million on a cash basis) for the first nine months of 2015.  Thus far in 2016 our capital expenditures have been directed at completion activities of the Ewing Bank 954 A-8 well, drilling of the A-18 well at Mahogany, recompletions at Virgo (VK 823) and Main Pass 69 and a new pipeline at East Cameron 321.  The remainder of the expenditures was associated with other development activities and seismic.  

Our capital expenditures for 2016 are currently estimated at $60 million and well below prior year levels.  Our plug and abandonment activities for 2016 are currently estimated to total $74 million ($90.2 million over the next twelve months) and are expected to be funded with cash on hand and cash flow from operating activities.

OPERATIONS UPDATE 

Ship Shoal 349 A-18 "Mahogany" (100% WI, operated, shelf) 

We re-initiated drilling operations on the SS349 A-18, which is expected to reach total target depth of 18,722 feet in the November/December timeframe.  We plan on completing and bringing the well on line around the end of the year or possibly early January 2017.  The A-18 is a development well.  To date, we have penetrated and logged pay in two field sands, the results from which are encouraging.  Following the completion of the A-18 well, we expect to conduct workover activities on several wells to further enhance field production, likely beginning in early 2017.   

Well Recompletions and Workovers

We have recently finished a recompletion of the A-1 well at Viosca Knoll 823 "Virgo" and the Ewing Bank 954 A-8 well. Both of these wells are performing better than expected (4,400 Boe per day gross, 3,200 Boe per day net, production rate on early tests) and should contribute nicely to fourth quarter production levels.

Bureau of Ocean Energy Management ("BOEM") Matters: The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or post surety bonds or other acceptable financial assurances, which, among other things, will insure that such decommissioning obligations will be satisfied.  Prior to 2015, we were partially exempt from providing such financial assurances.  The significant and sustained decline in crude oil and natural gas prices, however, has resulted in the Company in 2015 no longer meeting the relevant financial strength and reliability criteria for such exemptions set forth in the then current regulations and procedures of the BOEM.  As a result, we were notified by the BOEM in 2015 that the Company was no longer eligible for any exemption from providing financial assurances to the BOEM. 

In February and March 2016, we received several orders from the BOEM ordering the Company to secure financial assurances in the form of additional security in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, rights of use and easement and rights of way.  We filed appeals with the Interior Board of Land Appeals ("IBLA") regarding four of the BOEM orders - specifically the February order requiring the Company to post a total of $159.8 million in additional security and three March orders requiring $101.0 million in additional security.  The IBLA, acknowledging that the BOEM and the Company were seeking to resolve the BOEM orders through settlement discussions, has agreed to stay the effectiveness of the orders.  This is the third stay that we have received from the IBLA and this latest order extends the effectiveness to January 31, 2017.  We submitted a proposal for a tailored plan of compliance in May of 2016 in an effort to seek an acceptable resolution of the orders.

In July 2016, effective September 12, 2016, the BOEM issued NTL #2016-N01, related to obligations for decommissioning activities on the federal OCS, thereby superseding and replacing the prior applicable NTL which was NTL #2008-N07.  Implementation of this new NTL could result in us having to obtain additional bonds or other financial assurances and having to post collateral to obtain such additional bonds or other financial assurances.  In September of 2016, we submitted to the BOEM a revision of our proposed tailored plan of compliance that we believe to be consistent with a tailored arrangement allowed under NTL #2016-N01.  Discussions with the BOEM are ongoing and we are hopeful that we can reach agreement with them on an acceptable tailored plan.

Fourth Quarter and Full Year 2016 Outlook  

Our guidance for the fourth quarter and full year 2016 is provided in the table below and represents the Company's best estimate of the range of likely future results.   Guidance could be affected by the factors described below in "Forward-Looking Statements."   

 

Conference Call Information:  W&T will hold a conference call to discuss our financial and operational results on Thursday, November 3, 2016, at 8:30 a.m. Eastern Time.  To participate, dial 412-902-0030 a few minutes before the call begins.  The call will also be broadcast live over the Internet from the Company's website at www.wtoffshore.com.  A replay of the conference call will be available approximately two hours after the end of the call until November 10, 2016 and may be accessed by calling 201-612-7415 and using the passcode 13648354#.

About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and has grown through acquisitions, exploration and development.  The Company currently has working interests in approximately 54 fields in federal and state waters (50 producing and four fields capable of producing) and has under lease approximately 750,000 gross acres, including approximately 450,000 gross acres on the Gulf of Mexico Shelf and approximately 300,000 gross acres in the deepwater.  A majority of the Company's daily production is derived from wells it operates.  For more information on W&T Offshore, please visit the Company's website at www.wtoffshore.com.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. No assurance can be given, however, that these events will occur. These statements are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of our risk management activities, governmental regulations, uncertainties and other factors discussed in W&T Offshore's Annual Report on Form 10-K for the year ended December 31, 2015 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section. Investors are urged to consider closely the disclosures and risk factors in these reports.

 

 

 

 

 

 

 

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES
Non-GAAP Information

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP.  These non-GAAP financial measures are "Net Income Excluding Special Items," "EBITDA" and "Adjusted EBITDA."   Our management uses these non-GAAP financial measures in its analysis of our performance.   These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures which may be reported by other companies. 

Reconciliation of Net Income (Loss) to Net (Loss) Excluding Special Items

"Net Loss Excluding Special Items" does not include the unrealized commodity derivative (gain) loss, write-off of debt issuance and other non-operating costs, a contingent assessment provision, ceiling test write-down of oil and natural gas properties, gain on exchange of debt and associated income tax adjustments.  Net Loss excluding special items is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current periods to prior periods.

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES
Non-GAAP Information

Reconciliation of Net Income (Loss) to Adjusted EBITDA

We define EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization, and accretion and ceiling test write-down of oil and natural gas properties. Adjusted EBITDA excludes the unrealized commodity derivative (gain) loss, write off of debt issuance and other non-operating costs, gain on exchange of debt, and a contingent assessment provision.  We believe the presentation of EBITDA and Adjusted EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures.  We believe this presentation is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital and tax structures.  EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income (loss), as an indication of operating performance or cash flows from operating activities or as a measure of liquidity.  EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies.  In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use. Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues.   

The following table presents a reconciliation of our consolidated net loss to consolidated EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.

 

 

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SOURCE W&T Offshore, Inc.