HOUSTON, Aug. 5, 2015 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its second quarter 2015 operations and financial results, as well as its 2015 third quarter and full year production and expense guidance. Some of the key items include:

• Successfully completed and brought on production two deepwater wells at Mississippi Canyon 538 "Medusa" field during the second quarter.  The two wells, the SS #6 and SS #7, came on line with a combined initial rate exceeding 17,300 barrels of oil equivalent ("Boe") per day gross, increasing the total field output to over 20,800 Boe per day gross or greater than 3,000 Boe per day net to our interest.
• Production for the second quarter of 2015 averaged approximately 46,500 Boe per day (4.23 million Boe in total for the quarter), 55% of which was oil and liquids. Oil production increased 2.9% for the second quarter of 2015 compared to the second quarter of 2014 while natural gas production decreased 5.5% and natural gas liquids ("NGLs") production decreased 20.6% as we continue our focus on oil related projects.  
• Average realized sales price for the second quarter of 2015 was $56.63 per barrel for oil, $19.18 per barrel for NGLs and $2.74 per thousand cubic feet ("Mcf") for natural gas.  On a combined basis, our average realized sales price was $34.83 per Boe compared to $59.63 per Boe in the second quarter of 2014.
• Revenues for the second quarter of 2015 were $149.1 million, 77.8% of which was from oil and NGLs.
• Lease operating expenses ("LOE") declined 27% for the second quarter of 2015 to $45.1 million compared to $61.8 million in the second quarter of 2014.  In response to our cost control measures, base LOE declined $11.2 million, or 24.5%, quarter over quarter.
• Adjusted EBITDA for the second quarter was $79.7 million and our Adjusted EBITDA margin was 53%.  For the first six months of 2015, Adjusted EBITDA was $128.0 million and our Adjusted EBITDA margin was 46%.
• Deepwater development at our "Big Bend" and "Dantzler" fields located in Mississippi Canyon is proceeding on schedule.  We believe that first production from Big Bend will occur in the fourth quarter of 2015 and production from Dantzler will be by the end of 2015.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "In 2015, we have successfully executed on our plan to focus our capital budget on high value projects that will contribute significantly to both future production and proved reserves. Projects completed so far this year have performed better than expected, including excellent results from two recent wells at our Medusa field. At our Ewing Banks 910 field, we are currently drilling our EW 954 A-8 well, which follows the recently completed and successful ST320 A-5 ST well that is also part of the EW910 field. We expect to have the A-8 well on production by year-end, and seismic data indicates that the well could add substantial reserves. In addition, the water-flood project initiated at Matterhorn last year has continued to exceed our internal estimates. That project success has helped us to validate our expectations for field wide expansion which we hope will allow us to duplicate that success on the western side of the field.

"Development of our Big Bend and Dantzler discoveries is progressing on schedule. We expect that in addition to bringing Big Bend on production in the fourth quarter, we will also bring the two Dantzler wells on production by year-end. We continue to expect the combined production from Big Bend and Dantzler to reach in excess of 8,000 Boe per day (~81% oil) net to our interest. Importantly, by getting these substantial projects on-line by year end, we will maximize our opportunity to realize additional reserve contributions and production from them in 2016.

"We have also been successfully working with our service providers to reduce the cost of goods and services and have significantly reduced our lease operating expenses. LOE was down 27% in the second quarter compared to the second quarter of last year," he said.

Production, Revenues and Price: For the second quarter of 2015, our oil production was 1.9 million barrels, up 2.9% over the second quarter of 2014. NGL production was 408,000 barrels, down 20.6% from the second quarter of 2014. Natural gas production was 11.5 billion cubic feet ("Bcf") for the second quarter of 2015, down 5.5% or 12.2 Bcf from the second quarter of 2014. Our combined total production was 4.23 million Boe in the second quarter of 2015, down 3.7% from the second quarter of 2014.

Revenues for the second quarter of 2015 were $149.1 million compared to $263.0 million in the second quarter of 2014. Revenues decreased due to a steep decline in commodity prices. Crude oil prices were down $43.29 per barrel or 43.3% between the two quarters. NGLs prices declined 52%, or $20.80 per barrel, as a result of the decline in crude oil 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 $1.88 per Mcf, or 40.7% from the second quarter of 2014. During the second quarter of 2015, our unhedged average realized sales price for oil was $56.63 per barrel, $19.18 per barrel for NGLs and $2.74 per Mcf for natural gas. On a combined basis, we sold approximately 46,500 Boe per day at an average realized sales price of $34.83 per Boe compared to 48,300 Boe per day sold at an average realized sales price of $59.63 per Boe in the second 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 asset retirement obligations ("ARO") settlements, were $87.9 million in the first six months of 2015, compared to the $298.8 million generated over the same time period in 2014. Cash flows declined as revenues were $240.5 million lower in the first half of 2015 compared to the first half of 2014. Changes in working capital were a net usage of $35.9 million primarily related to reductions in accounts payable. Payments to settle asset retirement obligations totaled $21.9 million in the first half of 2015. Adjusted EBITDA for the second quarter of 2015 was $79.7 million compared to $175.7 million reported for the second quarter of 2014. The $96.0 million decline in Adjusted EBITDA for the second quarter of 2015 was driven by the $113.9 million decline in revenues, primarily due to a sharp decline in pricing for all the commodities that we produce and sell, partially offset by a decrease in LOE. For the six months ended June 30, 2015, our Adjusted EBITDA was $128.0 million, down from the $343.7 million generated in the first half of 2014. Our Adjusted EBITDA margin was 53% for the second quarter of 2015, which was much improved from the first quarter of 2015 but still down from 67% in the second quarter of 2014. Net cash provided by operating activities for the first half of 2015 was $30.1 million compared to $271.1 million from the same period in 2014.

Capital expenditures for oil and gas properties in the second quarter of 2015 were $68.2 million and $151.0 million for the first six months of 2015.

At June 30, 2015, we had a cash balance of $5.7 million and $239.4 million of undrawn capacity available under our revolving bank credit facility, which had a borrowing base of $500.0 million.

Lease Operating Expenses ("LOE"): LOE, which includes base lease operating expenses, insurance premiums, workover and maintenance expenses on our facilities, as well as hurricane related expenses and insurance reimbursements, decreased $16.6 million, or 27%, to $45.1 million in the second quarter of 2015 compared to the second quarter of 2014. On a per Boe basis, lease operating expenses decreased to $10.67 per Boe in the second quarter of 2015, a 24% reduction compared to $14.05 per Boe in the second quarter of 2014. On a component basis, Base LOE decreased $11.2 million primarily due to lower costs from service providers, lease terminations and fewer downhole onshore well work activities, partially offset by lower production handling fees we charge to third parties. Facilities maintenance expenses decreased $4.9 million due to timing of activities offshore 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 $24.42 per Boe for the second quarter of 2015 from $29.18 per Boe for the second quarter of 2014. On a nominal basis, DD&A decreased to $103.3 million for the second quarter of 2015 from $128.2 million for the second quarter of 2014 due to lower production and a decrease in the DD&A rate per Boe. The DD&A rate per Boe decreased primarily due to the ceiling test write-down recorded in the first quarter of 2015 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 lower net proved reserves and lower future development costs as a result of lower costs for goods and services.

Ceiling test write-down of oil and natural gas properties: For the second quarter of 2015, we recorded a non-cash ceiling test write-down of $252.8 million (pre-tax) as the book value of our oil and natural gas properties exceeded the ceiling test limit. The write-down resulted from a significant reduction in the market value of all three commodities we sell, which are crude oil, NGLs and natural gas. No ceiling test write-down was incurred during 2014.

General and Administrative Expenses ("G&A"): G&A was essentially flat for the second quarter of 2015 compared to the second quarter of 2014 ($19.8 million versus $19.7 million). Decreases in incentive compensation and bonuses and contractor services were mostly offset by reduced billings to third-parties for joint venture arrangements and a contingent assessment provision. G&A on a per Boe basis was $4.67 per Boe for the second quarter of 2015, compared to $4.48 per Boe for the second quarter of 2014.

Derivatives: For the second quarter of 2015, we recorded a $1.0 million derivative loss for open derivative contracts for crude oil and natural gas as of the end of the period. During the second quarter of 2015 we entered into various oil and natural gas commodity derivative contracts as a financial hedge that represent 25% of our estimated production for the remainder of 2015 and 35% of our estimated production for 2016. We have posted a schedule of these hedges to our website. For the second quarter of 2014, derivative net losses were $13.1 million.

Income Taxes: Our income tax benefit for the three months and six months ended June 30, 2015 was $44.1 million and $147.7 million, respectively. The income tax benefit is partially attributable to recording a ceiling test write-down of $252.8 million and $513.2 million in the second quarter and first six months of 2015, respectively. Our effective tax rate for the second quarter of 2015 was 14.5%, and our effective tax rate for the six months ended June 30, 2015 was 22.3%. Both of these percentages differ from the federal statutory rate of 35.0% primarily due to the recognition of a valuation allowance against our deferred tax assets. Income tax expense was $5.3 million and $11.9 million for the three and six months ended June 30, 2014, respectively. Our effective tax rates for the three and six months ended June 30, 2014 were 34.9% and 36.2%, respectively. The effective rate for the three months and six months ended June 30, 2014 differed from the federal statutory rate primarily as a result of state income taxes and other permanent items.

During the three months and six months ended June 30, 2015, we recorded a valuation allowance of $62.9 million and $85.4 million, respectively, related to federal deferred tax assets and net operating losses. 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 consider whether it is more likely than not that some portion or all of them will not be realized in the future.

Net Income (Loss) & Earnings (Loss) Per Share: We reported a net loss for the second quarter of 2015 of ($260.5) million, or ($3.43) per common share, compared to net income of $9.8 million, or $0.13 per common share, during the same period in 2014. The second quarter 2015 net loss included a $252.8 million ceiling test write-down of oil and natural gas properties. Excluding special items (including the ceiling test write-down of oil and natural gas properties, debt issuance costs write-off, a contingent assessment provision in 2015 and derivative loss in 2014 and 2015, net of applicable federal income tax at the effective tax rate for the periods presented), our net loss for the second quarter of 2015 was ($40.9) million, or a loss of ($0.54) per common share, compared to second quarter 2014 net income of $18.4 million, or $0.24 per common share. As indicated above, our effective tax rate benefit in the second quarter of 2015 was 14.5% instead of a statutory rate of 35% due to the need for a valuation allowance also discussed above. Operating results for the second quarter of 2015, excluding special items, were down primarily due to a $113.9 million decrease in revenues driven by a 41.6% decline in our realized prices and a 3.7% decline in production, partially offset by a $16.6 million decrease in LOE and a $24.9 million decrease 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 oil and gas properties for the first half of 2015 were $151.0 million compared to $266.0 million in the first half of 2014. For the first six months of 2015, capital expenditures for oil and gas properties consisted of $40.2 million for exploration activities, $99.1 million for development activities and $11.6 million for seismic, capitalized interest, and other. The majority of the capital has been dedicated to offshore, primarily the deepwater, with only $12.3 million dedicated to onshore. The Company's capital expenditure budget for 2015 is currently set at $200 million and, as shown above, 75% of this year's capital budget has already been expended. During the first half of 2015, we completed four deepwater wells with two wells at Dantzler and two wells at Medusa. Also during the first half of 2015 we completed five wells onshore, three of which were horizontal. Capital expenditures for the third quarter and the remainder of 2015 are dedicated predominately to the deepwater.

OPERATIONS UPDATE

Offshore Gulf of Mexico: The Company currently has one rig running offshore in the deepwater at our Ewing Bank 910 field. Additional details about our offshore operations are as follows:

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

A platform rig is currently on location drilling the EW 954 A-8 well at our EW 910 field, which is the second well in a two-well exploration drilling program. If successful, the A-8 well is expected to be on production by year-end 2015. The first well in the program was the ST 320 A-5 ST well, an exploration well that logged approximately 160 feet of net pay in two zones in the GA-15 target sand, was completed in June 2015. The A-5 well reached an early IP rate of approximately 2,700 Boe per day gross or 1,350 Boe per day net to our working interest. The currently drilling A-8 well is targeting a deeper exploratory sand and, based on seismic data, has the potential for a larger impact on reserves than the A-5ST.

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

The Mississippi Canyon 538 SS # 7 well, which encountered over 140 feet of net pay, was completed and put on production in June 2015. Along with the recently completed SS # 6 well, the two wells are making a significant contribution to the Medusa field which was recently producing in excess of 20,800 Boe per day gross or greater than 3,000 Boe per day net to our interest. We continue to evaluate further drilling opportunities within the field.

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

The subsea development work to connect the 2012 discovery at Big Bend and the 2013/2014 Dantzler discoveries to the nearby Thunder Hawk platform is ongoing and progressing well. First production is expected in the middle of the fourth quarter of 2015 and ramping up towards peak rates when Dantzler comes on line by the end of 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 at our Matterhorn Field continues to perform well and has helped to increase total production from the field to over 3,800 Boe per day in June 2015.

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

During the second quarter, no additional wells were completed or brought on production in our Yellow Rose field. For the month of June 2015, net production from the field averaged over 2,700 Boe per day.

Third Quarter and Full Year 2015 Outlook

Our guidance for the third 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, August 6, 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 August 13, 2015 and may be accessed by calling 201-612-7415 and using the passcode 13613143.

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 60 offshore fields in federal and state waters (56 producing and four fields capable of producing). W&T currently has under lease approximately 1.0 million gross acres offshore, including approximately 0.6 million gross acres on the Gulf of Mexico Shelf, approximately 0.4 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 loss, debt issuance costs write-off, contingent assessment provision, 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 (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 loss related to our derivatives, debt issuance costs write-off 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, 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.