HOUSTON, March 8, 2016 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its fourth quarter 2015 operations and financial results, as well as its 2016 full year production and expense guidance. Some of the key items and subsequent events include:

• Production for the fourth quarter of 2015 averaged 44,790 barrels of oil equivalent ("Boe") per day (4.1 million Boe for the quarter), 56.7% of which was oil and liquids. Oil production increased 7.9% for the fourth quarter of 2015 compared to the fourth quarter of 2014, while natural gas production decreased 18.6% as we continued our focus on oil related projects.
• Average realized sales prices for the fourth quarter of 2015 were $36.99 per barrel for oil, $16.16 per barrel for NGLs and $2.19 per thousand cubic feet ("Mcf") for natural gas. On a combined equivalent basis, our average realized sales price for the fourth quarter was $24.84 per Boe compared to $42.46 per Boe in the fourth quarter of 2014.
• Revenues for the fourth quarter of 2015 were $104.1 million, 75.9% of which was from oil and NGLs.
• Lease operating expenses ("LOE") declined 34.9% for the fourth quarter of 2015 to $49.3 million compared to $75.6 million in the fourth quarter of 2014 in response to our cost control measures.
• For the full year 2015, Adjusted EBITDA was $225.0 million and Adjusted EBITDA margin was 44%.
• Proved reserves as of December 31, 2015 were 76.4 million barrels of oil equivalent (MMBoe), or 458.1 billion cubic feet equivalent (Bcfe), with 55% comprised of liquids (46% crude oil and 9% NGLs) and 45% natural gas.
• We achieved a 100% drilling success rate in 2015, including discoveries in the deepwater and shelf of the Gulf of Mexico.
• On October 15, 2015, we closed on the sale of our interest in our Yellow Rose field for approximately $372.9 million and the assumption by the buyer of the asset retirement obligation ("ARO") associated with the field. We retained a non-expense bearing overriding royalty interest ("ORRI") based on a sliding scale of 1% to 4% that is benchmarked to the monthly NYMEX WTI oil price.
• Our 2016 Capital Budget for drilling and development has been reduced to $15 million, excluding approximately $84 million for plug and abandonment activities, and is expected to be funded with cash on hand and cash flow from operating activities.
• In February 2016, we drew our remaining available borrowings of $340 million on our revolving credit facility to maximize our liquidity. Our cash balance following the draw was $447 million.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "While 2015 was another outstanding year for our operations in the Gulf of Mexico, we continue to further prepare the Company to weather this period of extreme low prices. Even with our drastically reduced 2015 capital plan, we brought on-line three substantial 2015 deepwater exploration discoveries, achieved 100% exploration success for the third year in a row, and commenced production of our earlier discoveries at Big Bend and Dantzler.

"We are pleased that the production at our Rio Grande Loop project from the Big Bend and Dantzler wells has remained strong and is down only slightly from the peak rate achieved in December. We are also pleased with the high quality pay sands found in the Ewing Banks 954 A-8 well, which reached total depth in December and came on line last week. We have already seen gross production rates from this well of almost 3,500 Boe per day and the well is still cleaning up, and believe the field offers additional opportunities for future drilling. We expect our deepwater projects completed in 2015, combined with new production from our EW 954 A-8 well will help with 2016 production levels. However, unplanned downtime, pipeline maintenance, and well performance are factors leading to lower estimated production in 2016 from 2015.

"Our year-over-year 2015 proved reserves still only reflect a modest impact from our Big Bend and Dantzler discoveries and would have reflected more of our 2015 drilling successes had it not been for the impact of significantly reduced commodity prices. Regardless, we would have replaced our 2015 production with discoveries, extensions and revisions of proved reserves, had it not been for the steep decline in commodity prices.

"In 2015, the average realized price we received per Boe dropped 45% compared to the prior year, and in the first few months of 2016 it has dropped even further. Under the current market conditions, we intend to protect our liquidity, our balance sheet and our cash position, as well as continue to aggressively cut costs and reduce expenses. Our lease operating expenses decreased 35% in the fourth quarter and 27% for the full year while our general and administrative expenses were down 29% in the fourth quarter and down 16% for the year in 2015.

"Also in response to declining product pricing, we slashed our capital expenditures for drilling and development while preserving our inventory of drilling opportunities. With the sale of our Yellow Rose field in West Texas in October, we substantially boosted our liquidity and further increased our cash balance in February 2016 with a full draw-down of our revolving credit facility by $340 million. Our cash position subsequent to the draw was $447 million which we intend to manage judiciously in the face of an expected reduction in our borrowing base and demands for additional coverage and collateral for our supplemental P&A bonding program. We have no long-term drilling rig contracts or drilling obligations of any significance, no material near-term lease expirations as most of our acreage is held by production, and we have no debt obligations that mature in the near term," concluded Mr. Krohn.

Production, Revenues and Price: For the fourth quarter of 2015, our oil production was 1.975 million barrels, up 7.9% over the fourth quarter of 2014. NGL production was 363,450 barrels, down 36.0% from the fourth quarter of 2014. Natural gas production was 10.7 Bcf for the fourth quarter of 2015, down 18.6% from the fourth quarter of 2014. Our combined total production was 4.1 MMBoe in the fourth quarter of 2015, down 10.2% from the fourth quarter of 2014.

Revenues for the fourth quarter of 2015 were $104.1 million compared to $196.7 million in the fourth quarter of 2014. Revenues decreased due to the steep decline in commodity prices. Crude oil prices were down $33.73 per barrel, or 47.7%, between the two quarters. NGLs prices declined 40.1%, or $10.81 per barrel, as a result of the decline in crude oil prices, continued weak natural gas prices and a significant oversupply of both ethane and propane, which comprise the majority of NGLs on a component basis. Natural gas prices were lower by $1.62 per Mcf, or 42.5%, from the fourth quarter of 2014. During the fourth quarter of 2015, our average realized sales price for oil was $36.99 per barrel, $16.16 per barrel for NGLs and $2.19 per Mcf for natural gas. On a combined basis, we sold 44,790 Boe per day at an average realized sales price of $24.84 per Boe compared to 49,862 Boe per day sold at an average realized sales price of $42.46 per Boe in the fourth quarter of 2014.

Cash Flow from Operating Activities and Adjusted EBITDA: 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.

Cash flows from operating activities, before changes in working capital and ARO settlements, were $140.3 million for the year ended December 31, 2015, compared to $500.8 million generated over the same period in 2014. Cash flows declined as revenues were $441.4 million lower in the 2015 period compared to the 2014 period. Payments to settle asset retirement obligations totaled $32.6 million in 2015.

Adjusted EBITDA for the year ended December 31, 2015 was $225.0 million, down from $569.2 million generated over the same period in 2014. Our Adjusted EBITDA margin was 44% in the 2015 period compared to 60% in the 2014 period.

Net cash provided by operating activities for the full year of 2015 was $132.6 million compared to $474.0 million for the same period in 2014.

Liquidity: At December 31, 2015, we had a cash balance of $85.4 million and $349.1 million of undrawn capacity available under our revolving bank credit facility, which had a borrowing base of $350.0 million. On October 15, 2015, we closed on the sale of our interest in our Yellow Rose field for approximately $372.9 million and the assumption by the buyer of the ARO associated with the field. Proceeds from the sale were used to pay off all borrowings outstanding under our revolving bank credit facility (which were subsequently reborrowed) with the remaining balance of approximately $100 million added to available cash balances.

In February 2016, we borrowed substantially all of our available borrowings of $340 million remaining under the Company's revolving bank credit facility, to be used for general corporate purposes. Including these funds, the Company's cash position subsequent to the draw was $447 million. Our next scheduled borrowing base redetermination under our revolving bank credit facility will likely occur before the end of March 2016. To the extent our outstanding borrowings exceed the amount of the redetermined borrowing base, we will have to repay such excess borrowings in three equal monthly installments.

In February and March, 2016, the Company received several letters from the U.S. Department of the Interior's Bureau of Ocean Energy Management ("BOEM") ordering the Company to provide additional supplemental bonding on or before March 29, 2016, in the aggregate amount of $260.8 million to cover its obligations under certain Federal offshore oil and gas leases operated by the Company. The issuance of any additional surety bonds to satisfy the BOEM order or any future orders may require the posting of cash collateral, which could be substantial. We plan to continue our discussions with BOEM regarding satisfying their requests for additional financial assurances.

Lease Operating Expenses: LOE, which includes base lease operating expenses, insurance premiums, workovers, and maintenance expenses on our facilities decreased $26.4 million, or 34.9%, to $49.3 million in the fourth quarter of 2015 compared to the fourth quarter of 2014. On a per Boe basis, lease operating expenses decreased to $11.96 per Boe in the fourth quarter of 2015, a 27.5% reduction compared to $16.49 per Boe in the fourth quarter of 2014. On a component basis, base LOE (which includes insurance) decreased $7.2 million primarily due to lower costs from service providers, reduced onshore downhole well work activities and reduced insurance costs. Workover costs decreased $17.5 million due to reduced workovers performed at our Yellow Rose field before it was sold in October 2015 and two rig workovers that occurred in the 2014 period that did not reoccur in the 2015 period. Facilities maintenance expenses decreased $1.7 million due to reduced activity at multiple offshore locations and general cost reductions similar to those discussed above for base LOE.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for ARO, decreased to $16.49 per Boe for the fourth quarter of 2015 from $28.53 per Boe for the fourth quarter of 2014. On a nominal basis, DD&A decreased to $67.9 million for the fourth quarter of 2015 from $130.9 million for the fourth quarter of 2014 due to a decrease in the DD&A rate per Boe. The DD&A rate per Boe decreased primarily due to the ceiling test write-downs recorded in 2015, the proceeds from the sale of the Yellow Rose field and lower capital expenditures in relation to DD&A expense, which lowered the full-cost pool subject to DD&A. Additional factors affecting the DD&A rate were the sale of the Yellow Rose field in October 2015 and the resultant decrease in future development costs, lower net proved reserves and the general reduction in the costs of goods and services.

Ceiling test write-down of oil and natural gas properties: For the fourth quarter of 2015, we recorded a non-cash ceiling test write-down of $32.4 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The write-down resulted from a significant reduction in the market value of all three commodities we sell. Ceiling test write-downs during 2015 totaled $987.2 million. No ceiling test write-down was recorded during 2014.

General and Administrative Expenses ("G&A"): G&A decreased $6.7 million, or 29.3% to $16.1 million for the fourth quarter of 2015 compared to the fourth quarter of 2014. The decrease was primarily due to lower incentive compensation and bonus costs, a general reduction in contractor usage, and a decrease in professional fees, partially offset by lower billings to joint venture partners and higher surety bond premiums. G&A on a per Boe basis was $3.90 per Boe for the fourth quarter of 2015 compared to $4.95 per Boe for the fourth quarter of 2014.

Derivatives: For the fourth quarter of 2015, we recorded a $5.2 million derivative gain for derivative contracts for crude oil and natural gas. For the fourth quarter of 2014, derivative gains were $10.8 million related to derivative contracts for crude oil. No new contracts were entered into during the fourth quarter of either year. The Company has hedges in place covering approximately 35% of estimated 2016 production. A report providing our commodity derivative positions is posted to our website.

Income Taxes: Our income tax benefits for the three months ended and for the full year ended December 31, 2015 were $36.8 million and $203.0 million, respectively. These income tax benefits were partially attributable to recording ceiling test write-downs of $32.4 million and $987.2 million in the fourth quarter and full year of 2015, respectively, and the significant decline in commodity prices. Our effective tax rate for the fourth quarter of 2015 was 41.6%, and our effective tax rate for the twelve months ended December 31, 2015 was 16.3%. Both of these percentages differ from the federal statutory rate of 35.0% primarily due to recording a valuation allowance against a majority of our deferred tax assets. Income tax benefits were $17.3 million and $4.5 million for the three months ended and for the year ended December 31, 2014, respectively. Our effective tax rates for the three months and full year ended December 31, 2014 were 34.1% and 27.7%, respectively.

Our valuation allowance at December 31, 2015 is $232.9 million and relates to federal deferred tax assets. Deferred tax assets are related to 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 taxable income in the future. 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 in the future. We have $418.4 million of federal net operating loss carryforwards and carrybacks (tax basis) available to offset future and prior federal taxable income.

Net Income (Loss) & Earnings (Loss) Per Share: We reported a net loss for the fourth quarter of 2015 of ($51.6) million, or ($0.68) per common share, compared to net loss of ($33.4) million, or ($0.44) per common share, during the same period in 2014. Excluding special items (including the ceiling test write-down of oil and natural gas properties and derivative gains in 2014 and 2015, net of applicable federal income tax at the effective tax rate for the periods presented), our net loss for the fourth quarter of 2015 was ($33.4) million, or ($0.44) per common share, compared to fourth quarter 2014 net loss of ($40.5) million, or ($0.54) per common share. Operating results for the fourth quarter of 2015, excluding special items, were down primarily due to a $92.6 million decrease in revenues driven by a 41.5% decline in our realized prices, partially offset by a $26.4 million decrease in LOE and a $63.0 million decrease in DD&A and a $6.7 million decrease in G&A.

See the "Reconciliation of Net Income to Net Income Excluding Special Items" and related earnings per share, excluding special items in the table under "Non-GAAP Financial Information" at the end of this news release for a description of the special items.

2015 Capital Expenditures Update: Our capital expenditures on an accrual basis for the year ended December 31, 2015 were $231.4 million compared to $630.0 million for the same period in 2014. In 2015, capital expenditures for oil and gas properties consisted of $53.1 million for exploration activities, $173.1 million for development activities and $4.0 million for acquisition activities. Over 95% of our capital expenditures was dedicated to offshore, primarily the deepwater, with only $11.2 million dedicated to onshore. For the year ended December 31, 2015, we completed five deepwater wells with two wells at Dantzler, two wells at Medusa and one well at the Ewing Bank 910 field. For the same period of 2015 we completed five wells onshore.

2016 Capital Budget

The Company's capital expenditure budget for 2016 is currently set at $15 million, which excludes approximately $84 million for plug and abandonment activities and is expected to be funded with cash on hand and cash flow from operating activities.

Year-End 2015 Proved Reserves

Proved reserves as of December 31, 2015 were 76.4 MMBoe, or 458.1 Bcfe, with 55% comprised of liquids (46% crude oil and 9% NGLs) and 45% natural gas. Total proved reserves at December 31, 2014, excluding the reserves attributable to the Yellow Rose field were 82.7 MMBoe (120.0 MMBoe including the Yellow Rose field). Approximately 75% of our 2015 proved reserves were classified as proved developed producing, 15% as proved developed non-producing and 10% as proved undeveloped.

The 7.6% decline in year-over-year proved reserves (excluding the Yellow Rose field reserves sold in October) was due primarily to the significant reduction in commodity prices and from production, partially offset by increases from revisions, extensions and discoveries. The reduction due to lower commodity prices on reserve balances at December 31, 2015 was estimated at 10.7 MMBoe and production reduced reserve balances by 17.0 MMBoe. Net increases were from revisions of 15.3 MMBoe; extensions and discoveries of 4.1 MMBoe and purchases of 1.0 MMBoe.

Our total proved reserves had an estimated present value of future net revenues discounted at 10% ("PV-10") of $966 million. Our PV-10 after considering future cash outflows related to asset retirement obligations ("ARO"), and our standardized measure of discounted future cash flows were both $614 million as of December 31, 2015. The amounts are the same as no income taxes on future cash flows are estimated due to our current tax position net operating loss carryforwards. Neither PV-10 nor PV-10 after ARO is a financial measure defined under generally accepted accounting principles ("GAAP"). For additional information about our proved reserves and a reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows, see our Annual Report on Form 10-K.

Our proved reserves as of December 31, 2015 are summarized below:

OPERATIONS UPDATE

Offshore Gulf of Mexico:

Ewing Bank 910 (50% WI, operated, deepwater)

The Company recently completed, in two separate zones, the Ewing Bank 954 A-8 well that was drilled from the EW 910 platform. The rig has now been released. This is the second well in a two-well exploration program that was drilled from the EW 910 platform, following the earlier discovery at the ST 320 A-5 well in May 2015. The EW 954 A-8 well reached total depth in December and penetrated a total of 150 feet of measured depth hydrocarbon pay contained in two sands. The well has achieved a gross initial production rate from the lower sand completion of approximately 3,500 Boe per day and is still cleaning up. We also have pre-completed a second zone in the A-8 well, which was actually the primary and larger target zone and plan to place this second completion on production later as the lower completion depletes. W&T is operator of the EW 910 field and owns a 50% working interest in the well.

First Quarter and Full Year 2016 Outlook

Our guidance for the first 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. Lower full-year production guidance is due primarily to the sale of our Yellow Rose field, while lower guidance for operating expenses is due to reduced activity, lower cost of goods and services and the sale of Yellow Rose. 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 Wednesday, March 9, 2016, at 9:30 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 March 16, 2016 and may be accessed by calling 201-612-7415 and using the passcode 13629410.

About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 54 offshore fields in federal and state waters (50 producing and four fields capable of producing). W&T currently has under lease approximately 900,000 gross acres offshore, including approximately 550,000 gross acres on the Gulf of Mexico Shelf and approximately 350,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate offshore. For more information on W&T Offshore, please visit our 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 and Section 21E of the Securities Exchange Act of 1934. 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, 2014 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 our most recent annual report on Form 10-K and in other periodic reports on file with the SEC, available from our website at www.wtoffshore.com.

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 Loss to Net Loss Excluding Special Items

"Net Loss Excluding Special Items" does not include the derivative (gain) loss, write-off of debt issuance and other non-operating costs, contingent assessment provision, ceiling test write-down of oil and natural gas properties and associated tax effects. 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 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 (gain) loss related to our derivatives, write off of debt issuance and other non-operating costs, and 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.