HOUSTON, May 6, 2015 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its first quarter 2015 operations and financial results, and 2015 production and expense guidance. Some of the key items include:

• Production for the first quarter of 2015 averaged approximately 49,000 Boe per day (4.4 million Boe in total for the quarter), 53% of which was oil and liquids. Oil production increased 9.4% for the first quarter of 2015 compared to the first quarter of 2014 while natural gas production decreased 2.1%. Our average quarterly realized sales price was $43.04 per barrel for oil, $16.81 per barrel for natural gas liquids ("NGLs") and $3.01 per thousand cubic feet ("Mcf") for natural gas. On a combined basis our average realized sales price was $28.70 per Boe.
• Revenues for the first quarter of 2015 were $127.9 million, 70% of which was from oil and NGLs.
• Continued deepwater development remains on schedule at "Big Bend", "Dantzler", "Medusa", and Ewing Banks 910.
• In April 2015 we amended our existing revolving bank credit facility and modified certain covenants to enhance the Company's financial flexibility. The borrowing base under the bank credit facility is now $600 million.
• On May 5, 2015, we announced the pricing and marketing of a $300.0 million five-year second-lien term loan bearing interest at an annual rate of 9.0%.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "In the first quarter our operations were focused on our deepwater projects that will contribute significant production and additional proved reserves in 2015. We are having good success at our Medusa field where we are in the process of completing two recently drilled wells which will commence oil production in early May and add proved reserves in 2015. Based on improved seismic data, we believe that our Ewing Bank (EW) 910 field also offers substantial upside and an attractive return on investment at current commodity prices. We are currently drilling the EW 910 A-5 ST well, which assuming success, could contribute oil production in the second quarter of 2015. The EW 910 A-8 well is planned for the second half of 2015, with the potential for a third well to follow along with additional drilling opportunities in the future.

"At our Dantzler and Big Bend discoveries, we are making excellent progress to bring these major projects on production by year-end 2015 for Big Bend and no later than early 2016 for Dantzler. Completion operations at the two Dantzler discoveries were finalized in the first quarter of 2015 and we are now focused on installing the subsea tie-back to connect both fields to the nearby Thunder Hawk platform. While we are certainly looking forward to the additional production from Big Bend and Dantzler, which combined is expected to reach in excess of 8,000 Boe per day (~81% oil) net to our interest, we also anticipate adding substantial proved reserves once the wells are brought online and produce as anticipated.

"No other new exploration wells are currently planned for 2015. At this time, we continue to work with our service providers to reduce the cost of goods and services to be more in-line with lower commodity prices and wait for operating margins to improve prior to committing to new wells. We are pleased to see a quick response from the service providers, but believe that service rates will fall further. In the meantime, we will continue to evaluate efforts to enhance our liquidity. See the section titled "Term Loan" below for an example of those efforts," he said.

Production, Revenues and Price: For the first quarter of 2015, our oil production was 1.9 million barrels, up 9.4% over the first quarter of 2014. NGL production was 443,000 barrels, down 15.3% from the first quarter of 2014. Natural gas production was 12.3 billion cubic feet ("Bcf") for the first quarter of 2015, down slightly from 12.6 Bcf in the first quarter of 2014 as we continue to focus our efforts on increasing oil production. Our combined total production was 0.8% higher in the first quarter of 2015 than the first quarter of 2014.

Revenues for the first quarter of 2015 were $127.9 million compared to $254.5 million in the first quarter of 2014. Revenues decreased due to a steep decline in crude oil prices, which were down $55.52 per barrel or 56.3% between the two quarters. NGLs prices declined $21.45 per barrel as a result of the decline in crude oil prices. Natural gas prices were lower by $2.01 per Mcf or 40%. During the first quarter of 2015, our average realized sales price was $43.04 per barrel for oil, $16.81 per barrel for NGLs and $3.01 per Mcf for natural gas. On a combined basis, we sold approximately 49,000 Boe per day at an average realized sales price of $28.70 per Boe compared to 48,400 Boe per day sold at an average realized sales price of $58.29 per Boe in the first 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.

Adjusted EBITDA for the first quarter of 2015 was $48.3 million compared to $168.0 million reported for the first quarter of 2014. Adjusted EBITDA for the first quarter of 2015 exhibited a $126.6 million decrease in revenues primarily due to pricing. Net cash provided by operating activities for the first quarter of 2015 was $0.7 million compared to $118.5 million for the same period in 2014. Capital expenditures in the first quarter of 2015 were $82.8 million compared to $95.1 million in the first quarter of 2014.

At March 31, 2015, we had a cash balance of $8.4 million and $235.4 million of undrawn capacity available under our revolving bank credit facility, which had a borrowing base of $750.0 million. In April 2015, the borrowing base was revised to $600.0 million, which reduced the undrawn capacity on the revolving bank credit facility to $85.0 million.

Term Loan: On May 5, 2015, we announced the pricing and marketing of a $300.0 million five-year second-lien term loan bearing interest at an annual rate of 9.0% with an original issue discount at 99. The net proceeds will be used to repay a portion of the outstanding borrowings under the revolving bank credit facility. Upon issuance of the term loan, the borrowing base of the revolving bank credit facility will be reduced from $600.0 million to $500.0 million. The lender commitments and completion of the term loan are subject to the negotiation, approval and execution of definitive loan documentation. Details of the term loan agreement will be available in a few days via a Current Report on Form 8-K that we intend to file with the Securities and Exchange Commission.

Lease Operating Expenses ("LOE"): LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $53.3 million for the first quarter of 2015, down $2.3 million from $55.6 million reported in the first quarter of 2014. Base LOE increased $2.0 million to $41.8 million in the first quarter of 2015 primarily due to increased costs related to the acquisition of the Woodside Properties. Workover costs decreased $2.1 million to $3.2 million, and facilities costs decreased $2.8 million to $2.4 million, primarily due to lower onshore activity.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for asset retirement obligations, was $28.55 per Boe for the first quarter of 2015, up from $28.29 per Boe in the first quarter of 2014. On a nominal basis, DD&A was $125.5 million for the first quarter of 2015 versus $123.3 million in the first quarter of 2014.

The DD&A per Boe rate increased primarily due to the effect of deep water investments, which create large timing differences between capital expenditures and the booking of reserves that can span several years. Partially offsetting the increases were lower estimated future development costs, which were reduced in light of decreased prices being charged by service companies.

Ceiling test write-down of oil and natural gas properties: For the first quarter of 2015, we recorded a non-cash ceiling test write-down of $260.4 million as the book value of our oil and natural gas properties exceeded the ceiling test limit. The decrease was primarily due to decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas. No ceiling test write-down was incurred in any quarter of 2014.

General and Administrative Expenses ("G&A"): G&A decreased to $20.8 million in the first quarter of 2015, down $2.8 million from the first quarter of 2014 primarily due to lower incentive compensation expenses, partially offset by lower billings to third-parties for joint venture arrangements.

Derivatives: For the first quarter of 2015, we had no derivative contracts open during the period. For the first quarter of 2014, derivative net losses were $7.5 million.

Income Taxes: For the first quarter of 2015, our Federal income tax benefit was $103.6 million compared to tax expense of $6.6 million for the first quarter of 2014. Our effective tax rate for the first quarter of 2015 was 28.9% compared to 37.3% in the first quarter of 2014. For the first quarter of 2015, our effective tax rate differs from the statutory rate due to the effect of a valuation allowance of $22.5 million for our 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 produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income. In assessing the need for a valuation allowance on our deferred tax assets, we also consider whether it is more likely than not that some portion or all of them will not be realized.

Net Income (Loss) & Earnings (Loss) Per Share: We reported a net loss for the first quarter of 2015 of ($255.1) million, or ($3.36) per common share, compared to net income of $11.2 million, or $0.15 per common share, during the same period in 2014. The first quarter 2015 net loss includes a $260.4 million ceiling test write-down of oil and natural gas properties. Excluding special items (including the tax adjusted ceiling test write-down on properties in 2015 and tax adjusted derivative loss in 2014), our net loss for the first quarter of 2015 was ($85.8) million, or a loss of ($1.13) per common share compared to first quarter 2014 net income of $16.1 million, or $0.21 per common share. Earnings excluding special items were down primarily due to a $126.6 million decrease in revenues driven by a 50.8% decline in our realized prices, partially offset by a $4.8 million decrease in operating expenses ($2.8 million in G&A, $2.3 million in LOE, $1.8 million in gathering, transportation cost and production taxes, partially offset by a $2.1 million increase in DD&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 for the first quarter of 2015 were $82.8 million compared to $95.1 million in the first quarter of 2014. In the first quarter of 2015, capital expenditures for oil and gas properties consisted of $26.6 million for offshore exploration activities, $43.1 million for offshore development activities, $1.8 million for acquisitions (post-closing adjustments related to acquisitions done in 2014) of offshore properties, and $2.6 million for seismic and other. Onshore capital expenditures consisted of $2.6 million for exploration activities and $6.1 million for development activities. The Company's capital expenditure budget for 2015 is currently set at $200 million. Capital expenditures for the second quarter are expected to be in a similar range to the first quarter and all dedicated to the deepwater with approximately 80% of our total expenditures for the year spent in the first half of 2015.

OPERATIONS UPDATE

Offshore Gulf of Mexico: The Company currently has two rigs running offshore in the deepwater, of which one is operated and one is non-operated. The operated rig is drilling a well at our Ewing Bank 910 field and the non-operated rig is drilling a well at our Medusa field. Additional details about our offshore operations are as follows:

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

A platform rig is on location drilling the A-5 ST well at Ewing Bank 910, the first well in a two-well exploration drilling program. The A-5 ST is expected to be completed and put on-line in the second quarter of 2015. The second well, the A-8, is expected to follow and could be on-line by the third quarter of 2015.

Mississippi Canyon 538 "Medusa" Field (15% WI, non-operated) (Deepwater)

In late March 2015, we successfully drilled the Mississippi Canyon 538 SS No. 7 well, encountered over 100 feet of net pay, and have recently commenced completion operations. The first well, the SS No. 6 well drilled earlier this year, was recently put on line and is still ramping up. Production from the SS No. 7 well should begin in mid-2015. This deepwater field currently produces approximately 4,500 Boe per day gross to the Medusa spar, which is the host facility.

Mississippi Canyon 782 "Dantzler" Field & Mississippi Canyon 698 "Big Bend" Field (20% WI, non-operated) (Deepwater)

During the first quarter we finished the completions of the Dantzler #1 and Dantzler #2 wells. Production from these two high-impact oil wells is expected to commence in late 2015 or early 2016. The subsea development work to connect the 2012 discovery at Big Bend and the Dantzler wells to the nearby Thunder Hawk platform is ongoing and on schedule, with Big Bend expected to be on production in late 2015. The anticipated combined rate from both Dantzler and Big Bend is expected to reach in excess of 8,000 barrels per day, net to our interest (81% oil).

Mississippi Canyon 243 "Matterhorn" Field (100% WI, operated) (Deepwater)

A water flood and field pressure maintenance program that commenced in September 2014 showed a significant response in the first quarter of 2015. Since mid-December 2014, production from the A-2 well has increased from around 200 barrels per day to over 1,400 barrels of oil per day and is still increasing. Production from the entire field averaged approximately 4,450 Boe per day, net.

Onshore West Texas Permian Basin Yellow Rose Field (100% WI, operated)

As of the end of March 2015, we had six wells awaiting completion in our Yellow Rose field, two of which are vertical and four of which are horizontal.

The Beaujolais A 1302 H well drilled to the Wolfcamp "B" formation is now in flowback. Our most recent Lower Spraberry Shale well achieved a peak rate of 1,709 Boe per day (91% oil) or 224 Boe per day per 1,000' of lateral. The University Land ("UL") 7-10 6H well in Andrews County targeting the Lower Spraberry Shale is waiting on completion. The Chenin 8H and the Chenin 10H wells were drilled from the same drilling pad and both wells are awaiting completion as horizontal Wolfcamp "B" formation wells. The rig has since been released. For the month of March 2015, production from the field averaged 3,420 Boe per day net.

Second Quarter and Full Year 2015 Outlook

Our guidance for the second quarter and full year 2015 is provided in the table below and represents the Company's best estimate of the range of likely future results. It is 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, May 7, 2015, 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 May 14, 2015 and may be accessed by calling 201-612-7415 and using the passcode 13608155.

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 onshore in the Permian Basin of West Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 63 offshore fields in federal and state waters (61 producing and two fields capable of producing). W&T currently has under lease approximately 1.2 million gross acres, including approximately 0.6 million gross acres on the Gulf of Mexico Shelf, approximately 0.5 million gross acres in the deepwater and approximately 50,000 gross acres onshore, primarily in Texas. A substantial 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.

Hydrocarbon Quantity Estimates

The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this news release, such as "prospective resources" or "gross resources" to refer to estimates of potentially recoverable hydrocarbon quantities. These estimates, which require implementation of a development plan to recover, and are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. The estimated range of gross resources for the Dantzler Field included herein are based upon publicly disclosed internal estimates of the third party operator, which may not be comparable to similarly titled hydrocarbon quantities. 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 Income to Net Income Excluding Special Items

"Net Income (Loss) Excluding Special Items" does not include the derivative (gain) loss, ceiling test write-down of oil and natural gas properties and associated tax effects. Net Income 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.

Reconciliation of Net Income to Adjusted EBITDA

We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. Adjusted EBITDA excludes the (gain) loss related to our derivative. 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, 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 income to consolidated EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.