HOUSTON, Nov. 5, 2014 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported third quarter 2014 financial and operational results. Some of the highlights include:

• Continued success in our deepwater Gulf of Mexico drilling program with two discoveries in the third quarter, both of which are being completed.  Successfully drilled the Dantzler No. 2 well at Mississippi Canyon Block 782 and found over 121 net feet of oil pay in the target intervals.  This well, in which we have a 20% working interest, increased the operator's estimate of the total gross resources at the field to between 65 and 100 MMBoe.  The Atwater Valley 574 "Neptune" Field SB-03 well was also successfully drilled and found in excess of 300 feet of net pay.
• Our Gulf of Mexico shelf program had a successful exploration discovery at the East Cameron 321 A-2 ST well, which found over 140 feet of net oil pay and is currently being completed.  A successful development well at Ship Shoal 349 "Mahogany" Field, the A-16 well, was also brought online in late October 2014 at an initial rate of 2,500 barrels of oil equivalent per day gross.
• Substantial progress was made in our Permian Basin horizontal drilling program with recent horizontal wells achieving rates in line with performance metrics of wells of nearby operators. During the third quarter, we completed two Wolfcamp "B" wells and one Lower Spraberry Shale horizontal well using optimized completion techniques.
• In September, we acquired the remaining 35.7% working interest in our Fairway Field and associated Yellowhammer Plant.  The Fairway Field is located in the state waters of Alabama.  This additional interest will add 12 MMcfe per day, net, of additional production.
• Production for the third quarter of 2014 exceeded our initial expectations and averaged 46,700 barrels of oil equivalent ("Boe") per day, of which 53% was oil and liquids. Our average realized sales price was $95.10 per barrel for oil, $33.47 per barrel for natural gas liquids ("NGLs") and $3.97 per thousand cubic feet ("Mcf") for natural gas or $54.13 per Boe.
• Revenues for the third quarter of 2014 were $234.5 million, of which 78.5% was from oil and NGLs.
• Net income for the third quarter of 2014 was $0.7 million, or $0.01 per share.
• Adjusted EBITDA for the third quarter and first nine months of 2014 was $135.9 million and $479.6 million, respectively.  For the first nine months of 2014, our Adjusted EBITDA margin was 64%.
• Paid regular quarterly dividend of $0.10 per share during the third quarter.
• The borrowing base under our revolving credit facility was reaffirmed at $750 million effective October 22, 2014.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "We are pleased with our performance in the third quarter, with production of oil, NGLs and natural gas all coming in above our expectations and operating expenses coming in well below the mid-point of our guidance. As expected, our financial results were negatively impacted by a decline in product pricing and an increase in our depletion, depreciation and amortization ("DD&A"), as we have invested in high-impact, longer-term deepwater projects that we expect will contribute reserves in future years.

"We have continued to maintain our high drilling success rate which stands at 100% so far this year, even with an active drilling program weighted toward deepwater exploration. To balance our cash flow stream, we have added several quality projects that can be brought online more quickly to fill production decline gaps until our Big Bend and Dantzler discoveries can be brought online during the back half of 2015 and early 2016. Currently, we are completing a deepwater discovery at our Neptune field, which could be brought online as early as year-end 2014. We are also drilling a deepwater well at Medusa and are mobilizing a rig to spud the first of a multi-well deepwater drilling program at Ewing Bank 910 that, if successful, could contribute production in the first half of 2015 with the first well.

"Our horizontal drilling program in the Permian Basin is progressing well as we continue to optimize our drilling and completion processes. Like other operators in the area, we are having success with drilling longer laterals, fracing more stages and using more proppant per stage, which is yielding results that are as good as any of our nearby offset operators. Thus far, we have demonstrated commercial production rates in the Wolfcamp A and B and the Lower Spraberry Shale, which represent three out of a total of seven identified horizontal target formations. As part of our longer term onshore strategy, we anticipate investing in some or all of these yet untested horizontal target formations. We are currently completing another Wolfcamp B well, with the next three wells targeting the Lower Spraberry Shale. We anticipate that we will test yet another horizontal target formation in the near term. Our horizontal wells are now contributing about 24% of the production output of the Yellow Rose Field."

Production, Revenues and Price: For the third quarter of 2014, total production volume was 4,295,000 Boe, an increase of 88,000 Boe, over the third quarter of 2013. Higher production came from increases from several fields, including Fairway and Powerplay, and from acquisitions that brought production from the deepwater Medusa and Neptune fields. Production volumes from certain other fields were deferred due to various pipeline, facilities and operations issues, which for the third quarter were estimated at 0.6 million Boe. For example, the Mississippi Canyon 506 "Wrigley" field that had been shut in since we have owned the field was brought on line in mid-September at 16.5 MMcfe per day.

Revenues for the third quarter of 2014 were $234.5 million compared to $244.6 million in the third quarter of 2013. During the third quarter of 2014, we sold approximately 1.76 million barrels of oil, 506,000 barrels of NGLs and 12.2 billion cubic feet ("Bcf") of natural gas, as compared to approximately 1.73 million barrels of oil, 494,000 barrels of NGLs and 11.9 Bcf of natural gas during the same period in 2013. Our average realized sales price was $95.10 per barrel for oil, $33.47 per barrel for NGLs and $3.97 per Mcf for natural gas in the third quarter of 2014. On a combined basis, we sold 46,700 Boe per day at an average realized sales price of $54.13 per Boe compared to 45,700 Boe per day sold at an average realized sales price of $58.04 per Boe in the third quarter of 2013.

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 third quarter of 2014 was $135.9 million compared to $151.8 million reported for the third quarter of 2013. Adjusted EBITDA was lower for the third quarter of 2014 primarily due to a $10.0 million decrease in revenues and a $5.8 million increase in operating expenses. For the nine months ended September 30, 2014, our Adjusted EBITDA was $479.6 million, an increase of $14.4 million over the first nine months of 2013. Our Adjusted EBITDA margin was 64% for the first nine months of 2014, up from 63% in the first nine months of 2013. Net cash provided by operating activities for the first nine months of 2014 was $424.9 million compared to $475.8 million from the same period in 2013.

At September 30, 2014, we had a cash balance of $17.2 million and $402.4 million of undrawn capacity available under our revolving bank credit facility, with a borrowing base of $750.0 million, as reaffirmed effective October 22, 2014.

In June 2014, the U.S. Court of Appeals for the Fifth Circuit ruled in favor of W&T as we sought recovery for our Removal of Wreck costs associated with damage resulting from Hurricane Ike in 2008. The underwriters subsequently requested a rehearing which was denied. The Company now expects to recover in excess of $35 million from the insurance underwriters with $5 million already collected from one of the insurance underwriters.

Lease Operating Expenses ("LOE"): LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $71.7 million for the third quarter of this year, up from $67.3 million reported in the third quarter of 2013. Base LOE increased $6.9 million primarily due to more downhole well work in our West Texas onshore operations, increased expenses due to acquisitions, and lower product handling, maintenance and operations fees charged out to a third party at Mississippi Canyon 243. Partially offsetting the increase in base lease operating expenses were decreases in facilities maintenance of $1.8 million, which was primarily due to the Yellowhammer plant turnaround performed in the third quarter of 2013. The changes in the other components were a decrease of $0.3 million in insurance premiums, a decrease of net expense of $0.3 million of hurricane related expenses and insurance reimbursements, and a decrease of $0.1 million of workovers expense.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for asset retirement obligation, was $29.96 per Boe for the third quarter of 2014 up from $24.76 per Boe in the third quarter last year. On a nominal basis, DD&A was $128.7 million for the third quarter of 2014 versus $104.1 million in the third quarter of 2013. The DD&A rate and DD&A expense increased in part due to increases in the full cost pool from capital expenditures and estimated future development costs. The focus on deepwater exploration and development necessarily increases costs before the corresponding increase in proved reserves, leading to an increase in the DD&A rate per produced equivalent barrel.

General and Administrative Expenses ("G&A"): G&A was $21.0 million in the third quarter of 2014, up from $20.0 million in the third quarter of 2013. The increase was primarily due to increases in salaries and other compensation related expenses.

Derivatives: For the third quarter of 2014, our net derivative gain was $13.8 million and consisted of a realized loss of $4.2 million and an unrealized gain of $18.0 million. The derivative gain relates to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices. Although the contracts relate to production for future periods, changes in the fair value for all open contracts are recorded at the end of each respective reporting period. The third quarter of 2013 had a net derivative loss of $15.7 million, comprised of a $4.5 million realized loss and an $11.1 million unrealized loss.

Income Taxes: Income tax expense was $0.9 million for the third quarter of 2014 compared to $8.0 million for the third quarter of 2013, with the decrease primarily attributable to lower pre-tax income. Our effective tax rate for the third quarter of 2014 was not meaningful due to adjustments for a revised estimated effective tax rate computed on a year-to-date basis. The effective tax rate for the first nine months of 2014 was 37.1%. Our effective tax rate for the third quarter of 2013 was 36.1% and differed from the federal statutory rate of 35.0%, primarily as a result of state income taxes.

Net Income & EPS: Net income for the third quarter of 2014 was $0.7 million, or $0.01 per common share, compared to net income of $14.2 million, or $0.19 per common share, during the same period in 2013. Excluding special items (including derivative gains and losses), our net loss for the third quarter of 2014 was ($8.3) million, or a loss of ($0.11) per common share. This compares to third quarter 2013 net income, excluding special items, of $18.5 million, or $0.24 per common share. Earnings excluding special items were down primarily due to a $10.0 million decrease in revenues driven by lower realized prices, a $24.5 million increase in DD&A and a $4.4 million increase in LOE. 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.

Capital Expenditures Update: Our capital expenditures for the third quarter of 2014 were $189.9 million compared to $119.7 million for the same period in 2013. For the first nine months of 2014, our capital expenditures were $457.6 million, up from $424.4 million spent in the first nine months of 2013. So far this year, capital expenditures for oil and gas properties consisted of $103.6 million for offshore exploration activities, $162.4 million for offshore development activities and $76.5 million for acquisitions of offshore properties. Onshore capital expenditures have consisted of $43.2 million for exploration activities and $69.9 million for development activities. Our full year 2014 capital expenditure budget is $635 million, which is unchanged from last quarter.

OPERATIONS UPDATE

Offshore Gulf of Mexico: The Company currently has six rigs running offshore, of which three are operated and three are non-operated. Four of the six rigs are working in the deepwater, with one rig completing the Dantzler No. 2 well, one completing the SB03 well at Neptune, one drilling a well at Medusa and one mobilizing to spud the Ewing Bank 910 A-5 ST scheduled for December. On the shelf, two rigs are working: one just completed the A-16 well at Mahogany and is currently moving over to spud the A-17 well once other well and platform work has been completed at Mahogany, and one rig is completing the A-2 ST at East Cameron 321. Additional details are as follows.

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

In mid-August 2014, the Mississippi Canyon Block 782 "Dantzler" No. 2 well reached total depth and encountered an estimated 121 net feet of oil pay in two high-quality Miocene sands. Completion operations are underway and are to be followed by completion operations of Dantzler No. 1. The total gross resource of the field is estimated by the operator as between 65 and 100 MMBoe. Production from both Dantzler wells is expected to be placed on production in early 2016, immediately following the Big Bend well that is expected to be on line in late 2015.

Atwater Valley 574 "Neptune" Field (20% WI, non-operated) (Deepwater)

The SB-03 well at Neptune reached total vertical depth of 20,650 feet and encountered in excess of 300 feet of net pay. The well is currently being completed and is expected to be brought on line by year-end 2014. Total estimated drilling and completion costs are $174 million gross or $35 million net to W&T.

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

During September 2014, we commenced batch drilling operations on the Mississippi Canyon 538 SS No. 6 and SS No. 7 wells, which have target depths of approximately 12,500 feet in water depth of 2,222 feet. Both are exploratory wells targeting multi-target stacked oil sands. Drilling and completion costs are estimated to be $122 million to $137 million gross or $18 million to $21 million net to W&T. We are currently drilling the SS No. 6 well. Estimated timing of first oil delivery is a function of infrastructure installation on the Medusa Spar and is expected to be in the middle of 2015. We are discussing with the operator additional drilling locations and opportunities for the field.

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

A platform rig is currently mobilizing to spud the A-5 ST well at Ewing Bank 910 located in a water depth of 560 feet. This is the first well in a two well drilling program with the possibility for a third well in the program. Net drilling and completion cost for the A-5 ST is estimated at $20.7 million and the well should go online in the second quarter of 2015. The A-8 well that is expected to follow is estimated to cost $22.1 million net to W&T and targets a higher impact exploration reserve target than the A-5 ST well. If successful, this second well could be on line by the third quarter of 2015. Using improved seismic data and analysis, we have identified several additional drilling targets beyond our Phase I drilling program that we believe are prospective for recoverable resources from the field.

Ship Shoal 349 "Mahogany" Field (100% WI, operated) (Shelf)

The A-16 development well at our Mahogany Field was brought on production in late October 2014 and is producing 2,500 Boe per day gross (2,080 Boe per day net) from the "P" sand. The well also logged oil pay in the "M", "N", and "O" sands, which are scheduled to be produced at a later date. The A-17 well is planned as the next Mahogany drilling location, but the platform rig is being positioned to allow for other well and field optimization work to be completed before we commence the drilling of the A-17 well. The A-17 well will target an up dip "P" sand location.

East Cameron 321 Field (100% WI, operated) (Shelf)

The A-2 ST exploration well at East Cameron 321 has been logged with over 140 net feet of potential pay in five zones and is currently being completed in the exploratory Lentic 1 sand. We currently anticipate that the well will be brought on line during November of this year.

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

During the third quarter, we completed six wells at our Yellow Rose Field, three of which were vertical and three of which were horizontal. As of the end of the third quarter of 2014, we had five wells awaiting completion, two of which were vertical wells and three of which were horizontal wells. For the month of September 2014, production from the field averaged 4,850 Boe per day gross (3,785 Boe per day net to our interest), which was our highest rate from the field during 2014. Horizontal wells contributed 24% of total field output in September 2014.

We are currently running two rigs in this field, with one dedicated to our horizontal program and one to our vertical program. During the third quarter we brought three additional horizontal wells on production, two from the Wolfcamp "B" formation and one from the Lower Spraberry Shale formation, using optimized completion techniques. The Chablis 10-H reached a normalized peak rate of 968 Boe per day, and the Chablis 13-H reached a normalized peak rate of 1,125 Boe per day, both of which are in the Wolfcamp B formation (i.e. normalized for laterals with a length of 7,500 feet). The Pinot 65 #15H reached a normalized peak rate of 965 Boe per day in the Lower Spraberry Shale and represents our first Lower Spraberry shale horizontal completion and sets the stage for reserve additions in 2014 from this formation.

Our latest Yellow Rose horizontal wells are benefitting from improved completion techniques focused on longer laterals, more frac stages and higher use of proppant per stage as well as efficiency and cost saving strategies such as multi-well pad drilling. Across our acreage position, W&T has demonstrated commercial production rates in three out of a total of seven identified horizontal formations thus far, with the Lower Spraberry Shale formation being our most recent success. Currently, the company has only booked "proved" reserves in the Wolfcamp A and B horizontal formations. We expect that our recent Lower Spraberry Shale success could result in another formation with proved reserves at year end 2014. Looking forward, the potential production characteristics of the remaining and currently un-tested horizontal target formations are equally attractive to the horizontal formations invested in so far. As such, we anticipate that we will continue to pursue additional investments into at least one of these additional formations over the next several months. We are further encouraged by the potential of these formations as many offset operators are making similar investments in these formations as well, allowing us to capitalize on that information with offset well results increasing our acreage value. Currently, the Beaujolais A 1302 H well drilled to the Wolfcamp "B" formation is waiting to be completed, and a non-operated joint venture well to the Lower Spraberry Shale is also waiting to be completed. We are currently drilling the University Land ("UL") 7-10 6H in Andrews County targeting the Lower Spraberry Shale and next plan to move to the UL 6-2 4H in Gaines County, also targeting the Lower Spraberry Shale. In the fourth quarter, we expect to drill or commence drilling two horizontal wells and five vertical wells at our Yellow Rose Field.

We continue to expand and capitalize on adding value through joint operating and sharing arrangements with offset lease holders to synergistically optimize our collective holdings and to leverage capital efficiencies. We expect to continue our trend of using such arrangements through 2014 and into 2015, depending on the opportunities that arise. Some of those expected arrangements may also target newer horizontal benches as well.

Fourth Quarter and Full Year 2014 Outlook

Our guidance for the fourth quarter and full year 2014 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." Our fourth quarter of 2014 expense guidance reflects an increase in LOE with planned workovers at three different offshore fields and new offshore facilities.

Conference Call Information: W&T will hold a conference call to discuss our financial and operational results on Thursday, November 6, 2014, at 9:30 a.m. Eastern Time. To participate, dial 201-689-8349 a few minutes before the call begins. The call will also be broadcast live over the Internet from the Company's website at www.wtoffshore.com. A replay of the conference call will be available approximately two hours after the end of the call until November 13, 2014, and may be accessed by calling 201-612-7415 and using the passcode 13593502.

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 66 offshore fields in federal and state waters (62 producing and four 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 0.6 million gross acres in the deepwater and approximately 50,000 gross acres onshore 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, 2013 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.

(1) MMcfe and MBoe are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2) Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

(1) MMcfe and MBoe are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2) Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

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 Excluding Special Items" does not include the derivative (gain) loss, contract option fee 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 contracts and contract option fee. 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.