W&T Offshore Announces Fourth Quarter 2017 Operational And Financial Results, Year-End 2017 Proved Reserves, 2018 Guidance and 2018 Capital Plan

HOUSTON, Feb. 28, 2018 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its fourth quarter 2017 operational and financial results.  The Company also reported its year-end 2017 proved reserves with a 100% reserve replacement rate and provided its 2018 capital expenditure program, and first quarter and full year 2018 production and expense guidance. Some of the key highlights for the fourth quarter and full year 2017 included:

• The Company's year-end 2017 SEC proved reserves were 74.2 million barrels of oil equivalent, thus, the Company replaced just over 100% of its production for the year.
• Production for the fourth quarter of 2017 averaged 37,526 barrels of oil equivalent ("Boe") per day (or 3.5 million Boe for the quarter), 58% of which was oil and natural gas liquids ("NGLs"), compared to 40,254 Boe per day in the fourth quarter of 2016. Fourth quarter production was impacted by well maintenance, weather, pipeline outages, and platform maintenance that collectively resulted in deferred production of almost 6,100 Boe per day.
• Revenues were $129.1 million, up $13.9 million, or 12.1% compared to the fourth quarter of 2016. Oil and NGLs sales made up 78% of revenues in the fourth quarter of 2017 compared to 72% in the fourth quarter of 2016.
• Operating income was $33.2 million, an increase of 55.6% over the fourth quarter of 2016.
• Net income was $23.4 million or $0.16 per share. Excluding special items, our adjusted net income for the fourth quarter of 2017 was $24.2 million, representing a $16.5 million increase over the fourth quarter of 2016. Excluding special items, our earnings were $0.17 per share which represents an increase of $0.11 per share over the fourth quarter of 2016. (See definitions for a description of special items and reconciliations of non-GAAP measures to GAAP measures at the end of this news release.)
• Net income for the year 2017 was $79.7 million and earnings were $0.56 per share.
• For the year 2017 cash flow from operating activities was $159.4 million which represents an increase of $145.2 million over the year 2016.
• Adjusted EBITDA for the fourth quarter of 2017 was $72.9 million, up $3.3 million compared to the fourth quarter of 2016. Adjusted EBITDA for the full year of 2017 was $268.4 million, up $89.3 million over the full year 2016. Our Adjusted EBITDA margin was 55% for the year of 2017, up from 45% in 2016. (See definitions and reconciliations of non-GAAP measures to GAAP measures at the end of this news release.)

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "Our successful drilling program, combined with the effective development and excellent performance of some of our major fields, allowed us to replace just over 100% of our production on capital expenditures of only $130 million for the year, which we funded with cash on hand and cash flow from operations, i.e., within cash flow.  Production was down about 5% compared to 2016, primarily due to pipeline and platform outages along with tropical storm downtime. 

"One of our objectives over the last few years following the industry downturn has been to build our cash position while maintaining steady production and proved reserve levels.  In 2017, we successfully met those goals while increasing our cash balance by $28.8 million to $99.1 million.  We expect to see further improvement in our 2018 cash flow as well as increases in our cash balances as our unhedged production benefits from higher oil prices and our 2018 capital plan remains a modest $130 million.   

"Additionally, we expect to receive $65.1 million of tax refunds in 2018, although a portion of  it could occur later, related to plugging and abandonment activities that allow us to capture net operating loss carrybacks.  By ending 2017 with a strong cash balance and building cash throughout 2018, we expect to be in a good position to be able to either fund our upcoming 2019 debt maturities during 2018 or refinance, or a combination of both, as appropriate. 

"Our capital expenditure program for 2018 is composed of select lower-risk, high-return, oil-focused projects combined with higher risk, higher return oil focused wells that, assuming success, would be placed on production fairly quickly.  Our inventory of high quality exploration drilling and field extension projects in the Gulf of Mexico is based on advanced seismic and processing which provide further insight into some of our key fields. 

"To provide additional financial flexibility, as we have previously reported, throughout 2017 and now into 2018 we have been working to establish a drilling joint venture with private investors.  We are in the final stages of establishing such a drilling joint venture that will allow us to drill and exploit assets on a promoted basis and with reduced capital outlay.  We have completed negotiations with an initial group of investors but are subject to funding at an initial closing expected to occur by mid-March.  More investors may join the joint venture before or after the initial closing.

"It's important to note that establishing an investment vehicle with outside parties that will allow us to drill our wells on a promoted basis, will enable our 2018 capital spending requirements, as outlined in this press release, to be much lower.  Once all conditions to the initial closing of this joint venture are met we will announce final terms and revise our 2018 capital budget. Additionally, this joint venture could position us in the future to participate in high quality prospects that we may not otherwise be able to participate in," concluded Mr. Krohn. 

It is expected that entities owned and controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family will invest on the same terms as are negotiated with unaffiliated investors to acquire an approximate 4% interest in the drilling joint venture.

Production, Prices and Revenues: Production for the fourth quarter of 2017 was 3.5 million Boe compared to the fourth quarter 2016 of 3.7 million Boe.  Fourth quarter 2017 production was comprised of 1.6 million barrels of oil, 0.4 million barrels of NGLs and 8.7 billion cubic feet ("Bcf") of natural gas.  Oil and NGLs production comprised 58% of total production in the fourth quarter of 2017 compared to 55% of total production in the fourth quarter of 2016. Production for the fourth quarter of 2017 was primarily impacted by well maintenance, weather, pipeline outages, and platform maintenance that collectively resulted in deferred production of almost 6,100 Boe per day. 

For the full year 2017, production was 14.6 million Boe, compared to 15.4 million Boe in 2016.  Total 2017 production was comprised of 7.1 million barrels of oil, 1.4 million barrels of NGLs and 36.8 Bcf of natural gas.  For the full year, production was impacted by well maintenance, weather, pipeline outages, and platform maintenance that collectively resulted in deferred production of over 4,600 Boe per day.

The Mahogany, Ewing Bank 910, and Virgo fields delivered the largest production increases for the year 2017 compared to the 2016 period because of our successful drilling, completion, recompletion and workover programs. 

For the fourth quarter of 2017 our realized crude oil sales price was $55.83 per barrel, our realized NGL sales price was $27.55 per barrel and our realized natural gas sales price was $2.95 per Mcf.  The combined average realized sales price was $36.79 per Boe compared to $30.83 per Boe in the fourth quarter of 2016.  For the full year of 2017 our realized sales price for crude oil was $48.13 per barrel (representing an increase of 28.9% over 2016), our NGL realized sales price was $23.35 per barrel (representing an increase of 36.2% over 2016) and our realized sales price for natural gas was $2.96 per Mcf (representing an increase of 17.0% over 2016).  Our combined realized sales price was $33.02 per Boe compared to $25.76 per Boe for the full year 2016, representing an increase of 28.2%.  During the last two months of 2017 our crude oil price differentials became positive as the Brent/WTI differentials widened and the light/heavy crude differentials narrowed.  We believe this is primarily attributable to the turmoil in Venezuela that has led to reduced imports of sour and heavy crude oil into the United States.  

Revenues for the fourth quarter of 2017 increased 12.1% to $129.1 million compared to $115.2 million in the fourth quarter of 2016.  The increase in revenues was due to a 19.3% increase in our realized commodity price, offset by production volumes that were adversely impacted by 6,100 Boe per day of deferred production as previously mentioned.  We sold 37,526 Boe per day at an average realized sales price of $36.79 per Boe compared to 40,254 Boe per day as compared to an average realized sales price of $30.83 per Boe in the fourth quarter of 2016.

For the year 2017, revenues were $487.1 million, up 22% or $87.1 million over the 2016 period.  Revenues were up $100.8 million due to higher prices, partially offset by lower production volumes.

Lease Operating Expenses: Lease operating expense ("LOE"), which includes base lease operating expenses, insurance premiums, workovers and facilities maintenance, was $36.9 million in the fourth quarter of 2017 compared to $33.8 million in the fourth quarter of 2016.  On a component basis, base lease operating expenses were $30.4 million, insurance premiums were $2.6 million, workovers were $0.3 million and facilities maintenance was $3.6 million.   Base LOE was up $2.2 million over the fourth quarter of 2016 with higher incentive compensation accruals due to significantly better financial performance and due to increased activities at three of our fields.  Insurance premiums were up $0.6 million while workover expenses decreased $1.9 million due to the 2016 period reflecting higher activity.  Facilities maintenance increased $1.0 million due to increased activity at several fields but primarily associated with work at Matterhorn.  Finally, the 2016 period reflected a portion of an insurance reimbursement related to settlement of a Hurricane Ike claim. 

For the year 2017, LOE was $143.7 million which was $8.7 million below the 2016 period due to lower base LOE and lower insurance premiums.  Base LOE was lower by $10.5 million on a decrease in the cost of goods and services resulting from structural operational changes, reduced vendor pricing in the Gulf of Mexico and  higher production handling fees (cost offsets) at certain fields.

Depreciation, depletion, amortization and accretion ("DD&A"):  DD&A, including accretion for asset retirement obligations ("ARO"), was $11.25 per Boe for the fourth quarter of 2017 compared to $10.50 per Boe for the fourth quarter of 2016.  On a nominal basis, DD&A was $38.8 million for the fourth quarter of 2017 which was flat with the fourth quarter of 2016.  For the year 2017, DD&A on a nominal basis was $155.7 million which is down $55.9 million from the 2016 period primarily because of the ceiling test write-downs of $279.1 million in the 2016 period which lowered the full cost pool subject to depletion.

General and Administrative Expenses ("G&A"):  G&A was $14.4 million for the fourth quarter of 2017 and flat with the fourth quarter of 2016.  Decreases in medical claims and lower legal costs were entirely offset by higher professional services associated with reservoir engineering and higher surety bond premiums.  G&A for the full year 2017 was also flat compared to the full year of 2016.

Derivative (gain) loss:  Fourth quarter of 2017 reflects a loss of $0.6 million associated with crude oil derivative contracts compared to a loss of less than $0.1 million in the fourth quarter of 2016.  For the year 2017, the Company realized a gain of $4.2 million compared to a loss of $2.9 million in the 2016 period.

Interest expense:  Interest expense was $11.6 million in the fourth quarter of 2017, flat with the fourth quarter of 2016.    For the year 2017, interest expense was $45.8 million which represents a decrease of $46.4 million from the 2016 period due to the Exchange Transaction that was completed on September 7, 2016, when we exchanged $710.2 million of our Unsecured Senior Notes for $301.8 million of new secured notes and 60.4 million shares of common stock, and at the same time, closed on a $75.0 million, 1.5 Lien Term Loan.  Interest expense was also lower because we had no borrowings on the $150 million revolving bank credit facility during 2017 compared to borrowings averaging approximately $150.0 million from the beginning of January 2016 until we closed on the Exchange Transaction. 

Income Tax:  We recorded an income tax benefit of $1.5 million in the fourth quarter of 2017 on pre-tax income of $21.9 million compared to income tax expense of $1.0 million on pre-tax income of $17.5 million in the fourth quarter of 2016.  Our annualized effective tax rate for both periods was not meaningful.  The income tax benefit in the 2017 period relates to NOL carryback claims made pursuant to IRC Section 172(f) (related to rules for "specified liability losses"-, which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  The full year 2017 reflects a tax benefit of $12.6 million on pre-tax income of $67.1 million.  The benefit for 2017 reflects an estimated tax refund of $13.0 million that we expect to receive sometime in the second or third quarter of 2018 that relates to our specified liability loss carryback for plugging and abandonment expenditures made in 2017.

As of December 31, 2017, the balance sheet reflects current income tax receivables of $13.0 million and non-current income tax receivables of $52.1 million.  The non-current income tax receivable relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years.  These various carryback claims are made pursuant to IRC Section 172(f) described above.

Tax Cuts and Jobs Act ("TCJA"):   The TCJA of 2017 modified certain U.S. Federal income tax provisions available to corporations.  Along with lowering the corporate income tax rate, the TCJA changed certain income tax rules and deductions including cost recovery, limits on the deductions of interest expense, the elimination of the deduction from domestic production activities and utilization of net operating losses.  Under the TCJA effective in 2018, the rules related to specified liability losses have been eliminated and additional claims will not be allowed in 2018 and forward.  The TCJA does not affect the NOL carryback claims that we previously filed and are referenced above, nor does the TCJA affect the review process for such claims.  As a result of TCJA, our net deferred tax assets and associated valuation allowance were provisionally adjusted downwards by $105.9 million as of December 31, 2017.  No other changes were needed to either the income statement or balance sheet as a result of the TCJA. 

Net Income (Loss) & Earnings Per Share:  We reported net income for the fourth quarter of 2017 of $23.4 million or $0.16 per common share.  Excluding special items, our adjusted net income was $24.2 million and our earnings were $0.17 per share.  For the fourth quarter of 2016 we reported net income of $16.5 million, or $0.12 per common share; excluding special items, adjusted net income for the fourth quarter of 2016 would have been $7.7 million, or $0.06 per share.  (See the "Reconciliation of Net Income (Loss) to Net Income (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:  Net cash provided by operating activities for the year 2017 was $159.4 million which represents an increase of $145.2 million over the year 2016.  Cash flows from operating activities, (before changes in working capital, insurance reimbursements, escrow deposits and ARO settlements), were $235.6 million in 2017 compared to $103.1 million in 2016.       

The increase in cash flows in 2017 was primarily due to higher realized prices for all our commodities – crude oil, NGLs and natural gas, lower operating expenses and lower interest payments, primarily offset by deferred production volumes.  Our combined average realized sales price per Boe increased 28.2%, which increased revenues by $100.8 million.  However, production volumes decreased on a Boe basis by 5.2%, which lowered revenues by $15.4 million.  Operating expenses decreased by $11.3 million and interest expense decreased $46.4 million.  Interest payments related to the debt that was part of the Exchange Transaction are reported as a part of "cash flows from financing activities".  Other items affecting operating cash flows for 2017 were ARO settlements of $72.4 million and an escrow deposit of $49.5 million to secure the appeal of the Apache lawsuit, partially offset by insurance reimbursements of $31.7 million.

Adjusted EBITDA for the fourth quarter of 2017 was $72.9 million and our Adjusted EBITDA margin was 56%.  Adjusted EBITDA for the year 2017 was $268.4 million, up from $179.1 million in the 2016 period.  Our Adjusted EBITDA margin was 55% for the year 2017 compared to 45% for the 2016 period. 

Adjusted EBITDA and Adjusted EBITDA margin are non-GAAP measures and are defined in the "Non-GAAP Information" section at the end of this news release.  

Liquidity:  At December 31, 2017, our total liquidity was $248.8 million, consisting of an unrestricted cash balance of $99.1 million and $149.7 million of availability under our $150 million revolving bank credit facility. 

Capital Expenditures:  Our capital expenditures for oil and gas properties on an accrual basis for the year 2017 were $130.0 million compared to $48.6 million for the 2016 period ($106.2 million in the 2017 period on a cash basis compared to $83.8 million for the 2016 period).  In 2017 about 44% of our capital expenditures were dedicated to four drill wells at our Mahogany field while the remainder was dedicated to new exploration wells at Ship Shoal 300, Main Pass 286, and an unsuccessful well at South Timbalier 224.  We also performed recompletions at Main Pass 69, High Island 22, Main Pass 108 and a number of other fields. The remaining expenditures were associated with development activities and seismic.  

2018 Capital Expenditure Program:  Currently, we have established a 2018 capital program of $130.0 million that includes 12 wells to be drilled (four of which were started in 2017, one of which has been abandoned as a dry hole), of which seven are deepwater wells and five are shelf wells.  Six of the deepwater wells and four of the shelf wells are exploratory.  The budget also includes 12 recompletes that are expected to cost approximately $7.5 million.  Approximately $35 million of the budget is related to projects that commenced in 2017 with the remainder dedicated to new projects in 2018.  Additionally, we estimate we will spend approximately $24 million on plugging and abandonment activities in 2018. 

We expect that this budget may result in a slight decrease in our 2018 production compared to 2017.  Our estimates of production for 2018 are a function of the timing of the expenditures and the success of the wells and our other work programs.  Our estimates do not yet reflect the full impact of our proposed drilling joint venture.  Nor do these estimates reflect what we believe are viable acquisition opportunities that can increase both production and reserves.  We continue to evaluate these opportunities and are confident that we can execute on them as they arise.

Projects included in the 2018 capital spending plan that are already under way include the completion of Ship Shoal 349 (Mahogany) A-17, a well that has found two new objectives in two new sands; development of the Main Pass 286 #1, a successful 2017 exploration well; and Viosca Knoll 823 (Virgo) A-10 ST, a deepwater development well that is up-dip to known pay. 

New projects in our 2018 capital program include two more wells at the Mahogany field, the SS 349 A-5 ST2, a low-cost side track well targeting the "P" sand; and the SS 359 A-20, an exploration/exploitation well.  Two wells are also planned at Ewing Bank 910 field, the ST 311 A-2 and A-3 wells, both of which are low-risk, high-return exploration opportunities with multiple stacked pay sands.  If successful, all of these wells can be brought on line quickly via existing infrastructure and pipelines.  Additionally, we expect the recompletions that are planned will provide low-cost production additions.

Virtually all of these projects meet our objectives of having a very high probability of success, expected high rates of return and short-term payout, and the ability to boost production levels in 2018 or early 2019.

OPERATIONS UPDATE 

Ship Shoal 349 "Mahogany" (100% WI, operated, shelf):   We recently completed the drilling of the A-17 well that found a previously undiscovered deeper sand (V-Sand) and extended the known limits of one of the field pay sands seen in earlier wells, resulting in proved reserve additions with significant upside.  The A-17 well will initially be completed in the newly discovered sands with production expected to commence late in the first quarter.  Following the A-17 well, we will begin drilling the A-5 ST well targeting the 'Q' and 'P' sands that were logged and evaluated in the A-18 well drilled in 2017.  Workover and recompletion opportunities continue to exist at Mahogany and will be done as time and operating conditions permit.  Mahogany production averaged over 6,900 Boe per day net to our interest in 2017.

Viosca Knoll 823 "Virgo":  We recently mobilized a rig to our Virgo Platform to commence what we anticipate will be a multi-well deepwater drilling program.  Our first well in the program, the A-10 ST well, targeted an up-dip attic position nearby to a logged well in some of the deep main field pays.  The well recently reached total depth of 16,770 feet and logged a significant hydrocarbon column in our target objective.  We are now moving into completion mode and will likely have the well on line during early second quarter.  Following the completion of the A-10 ST, we expect to begin drilling the second well in our drilling program at Virgo.  One attractive feature of this drilling program is our ability to achieve early cash flow from the wells due to the presence of infrastructure and our Virgo production platform.  W&T Offshore, Inc. is the operator with an 80% working interest in the A-10 ST well.  The co-owner is EnVen Energy Ventures, LLC, a wholly owned subsidiary of EnVen Energy Corporation, with 20% working interest. 

Ewing Bank 910 (36% - 50% WI, operated, deepwater):  Two wells are planned in our Ewing Bank 910 field, which are the South Timbalier 311 A-2 and A-3 wells.  We anticipate beginning rig mobilization in the first quarter of 2018 with a likely spud date sometime in the second quarter of 2018.  We believe both of these wells are low-risk exploration opportunities with multiple stacked pay sands.  Assuming success, these wells can be brought on line quickly via existing infrastructure and pipelines.

Main Pass 286 (100% WI, operated, shelf):  This well was drilled late in the fourth quarter of 2017 resulting in a new field discovery.  We are evaluating our optimal development scenarios, which will likely include bringing the production back to a platform at MP 283 which is a nearby W&T owned facility.  We expect to proceed with development later this year.  Although dependent upon final project sanction and our development solution, we are expecting this discovery to achieve first production sometime during early 2019. 

Well Recompletions and Workovers:  During 2017, we performed 16 recompletions that added approximately 4,440 Boe per day of initial production and 11 workovers that added approximately 6,600 Boe per day of initial production.  For 2018 we anticipate performing 12 recompletions for a cost of around $7.5 million that will lead to additional production.

Year-End 2017 Proved Reserves

The Company's year-end 2017 SEC proved reserves were 74.2 million Boe, or 445.3 Bcfe, with 57% comprised of liquids (46% crude oil and 11% NGLs) and 43% natural gas.  The Company achieved a reserve replacement rate in excess of 100% for calendar year 2017.  At year end, approximately 74% of our 2017 proved reserves were classified as proved developed producing, 10% as proved developed non-producing and 16% as proved undeveloped.  This represents an increase 15.2% in our proved developed reserves over 2016.

Total production in 2017 of approximately 14.6 million Boe was more than offset by upward revisions to previous reserve estimates due to successful well performance in several key fields, as well as new extensions and discoveries.  We also had favorable revisions due to an increase of $8.59 per barrel in crude prices and an increase of $0.50 per Mcf in natural gas prices.  Total proved reserves at year-end 2016 were 74.0 million Boe, 55% of which were comprised of crude oil and NGLs.

The present value of our reported SEC proved reserves, discounted at 10% ("PV-10"), at such date was $992.9 million, up 32% from $754.9 million at the end of 2016.  The standardized measure of future net cash flows of our SEC proved reserves was $740.6 million at December 31, 2017.  The 2017 SEC PV-10 is based on an average crude oil price of $51.34 per barrel and average natural gas price of $2.98 per Mcf, both after adjustment for quality, transportation, fees, energy content, and regional price differentials.  For purposes of calculating the SEC PV-10 for 2016, the average crude oil price was $42.75 per barrel and the average natural gas price was $2.48 per Mcf.

For comparative purposes, utilizing the forward closing prices on the New York Mercantile Exchange (NYMEX) for crude oil and natural gas on December 29, 2017 (the last day of trading in 2017), totaled proved reserves would have been 74.3 million Boe, with a PV-10 value of $1.1 billion.

First Quarter and Full Year 2018 Production and Expense Guidance:

Our guidance for the first quarter and full year 2018 in the table below 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" and our estimates do not yet reflect the full impact of our proposed drilling joint venture.

Conference Call Information:  W&T will hold a conference call to discuss our financial and operational results on Thursday, March 1, 2018, at 10:00 a.m. Eastern Time (9:00 a.m. Central 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 after the call until March 8, 2018, and may be accessed by calling 201-612-7415 and using the passcode 13676094#.

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 49 producing fields in federal and state waters and has under lease approximately 700,000 gross acres, including approximately 470,000 gross acres on the Gulf of Mexico Shelf and approximately 230,000 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, 2016 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 Income (Loss) Excluding Special Items

"Net Income (Loss) Excluding Special Items" does not include the unrealized commodity derivative (gain) loss, default in payment by joint interest partners, write-down of debt issue costs, ceiling test write-down of oil and natural gas properties, gain on exchange of debt, Apache lawsuit, East Cameron 321 settlement, civil penalties, certain cost recovery from insurance settlement, and associated income tax adjustments.  Net Income (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, default in payment by joint interest partners, gain on exchange of debt, Apache lawsuit, East Cameron 321 settlement, civil penalties, and write-down of debt issue costs.  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 net income (loss) to EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.

SOURCE W&T Offshore, Inc.