HOUSTON, March 4, 2015 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its year-end 2014 proved reserves, fourth quarter and full year 2014 operations and financial results, 2015 capital budget and drilling plans, and 2015 production and expense guidance. Some of the highlights include:

• Our proved reserves at year-end 2014 were 120 million barrels of oil equivalent ("Boe") with a PV-10 value of $2.6 billion, excluding the effect of estimated asset retirement obligations.  Both the amount and value of our proved reserves have increased over the prior year even with our continued focus on longer-term projects.
• Extensions and discoveries of proved reserves for 2014 were 9.7 million Boe, or 58.1 billion cubic feet of natural gas equivalent ("Bcfe"), primarily associated with our Dantzler and Yellow Rose projects. 
• Achieved a 100% drilling success rate in 2014, including discoveries in the deepwater and shelf of the Gulf of Mexico ("GOM") and onshore in the Permian Basin of West Texas.
• Continued to make significant progress in the deepwater Gulf of Mexico with continued work on our Big Bend and Dantzler projects that are scheduled to come on line in the fourth quarter of 2015 and early 2016, respectively.
• Acquired additional properties in the deepwater including the Neptune field in Atwater Valley blocks 574, 575 and 618.  Participated in the drilling of a successful well in the Neptune field that was brought on line near the end of 2014.
• Acquired the remaining interest in the Yellowhammer facility and Fairway field at Mobile Bay area blocks 113 and 132; and have enhanced recovery from the existing wells in the field through productive well work.
• Continued expanding the Ship Shoal 349 Mahogany field on the GOM shelf throughout 2014 with the successful completion of two more oil wells and the recompletion of another one.  Drilled and completed another well at our East Cameron 321 field that is predominately oil.
• Continued development of our Yellow Rose field in the Permian Basin of West Texas with the completion of 32 wells for the year, 12 of which were exploration and 20 were development wells.  At the end of the year we had eight wells awaiting completion, five of which were horizontal wells.  Derisked two new horizontal benches during 2014 which included the Wolfcamp B and Lower Spraberry Shale.  A number of additional horizons are under evaluation.
• The UL Mason Unit No. 2, a Lower Spraberry shale well in Andrews County, achieved a peak rate of 1,709 Boe per day (91% oil) or 224 Boe per day per 1,000 feet of lateral.
• Production for the fourth quarter of 2014 averaged approximately 50,000 Boe per day (4.6 million Boe in total for the quarter), 52% of which was oil and liquids. Our average quarterly realized sales price was $70.72 per barrel for oil, $26.97 per barrel for natural gas liquids ("NGLs") and $3.81 per thousand cubic feet ("Mcf") for natural gas.  On a combined basis our average realized sales price was $42.46 per Boe.
• Production for the full year 2014 averaged 48,300 Boe per day (17.6 million Boe in total).  Our average annual realized sales price was $90.96 per barrel for oil, $34.49 per barrel for NGLs and $4.35 per Mcf for natural gas.  On a combined basis our average realized sales price was $53.49 per Boe.
• Revenues for the fourth quarter of 2014 were $196.7 million, 73.6% of which was from oil and NGLs.  Revenues for the full year of 2014 were $948.7 million, 76.5% of which were from oil and NGLs.
• Adjusted EBITDA for the fourth quarter and full-year of 2014 was $89.6 million and $569.2 million, respectively.  Our Adjusted EBITDA margin was 60% for the year.
• The 2015 capital expenditure budget is set at approximately $200 million, with approximately $169 million allocated to the deepwater Gulf of Mexico and the remainder dedicated to the Gulf of Mexico shelf and our Permian Basin operations.  The substantial majority of the budget is for the completion or development of previous discoveries. 

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "In 2014, we continued to focus our capital budget on projects designed to generate longer-term value. During the year, we built on our previous success in the deepwater by drilling a second Dantzler well at Mississippi Canyon 782 to expand the size of the field, and we made solid progress developing the earlier Dantzler and Big Bend discoveries. Thus far, the proved reserves on our books from these projects represent only a small portion of what we believe will ultimately be realized as probable and possible reserves become proved with the commencement of production in 2015 for Big Bend and 2016 for Dantzler. We also advanced our onshore program in the Permian Basin, which has allowed us to create a longer-life production profile.

"Our capital expenditure budget for 2015, currently set at $200 million, is designed to provide flexibility to respond to market conditions and fund projects that are either underway or committed to with other operators. We entered 2015 with numerous substantial deepwater projects in development that will add considerable value to W&T Offshore. We are moving forward to bring these projects on-line as scheduled throughout 2015 and early 2016. As a result of our past investments in high quality projects, we expect that our 2015 production will remain steady or increase slightly over 2014 levels, despite our significant reduction in capital spending.

"While we wait for the cost of goods and services to adjust to a lower commodity price environment and for margins to improve, we plan to conserve capital and preserve liquidity. As in previous industry downturns, we will work to reduce costs and expenses and cautiously manage our balance sheet, which includes suspending our quarterly common stock dividend. We have a high-quality asset base, a substantial portion of which is held by production, giving us the flexibility to postpone spending until operating margins return to more normal levels," said Mr. Krohn.

Production, Revenues and Price: For the fourth quarter of 2014, our oil production was 1.8 million barrels, up 2.1% over the fourth quarter of 2013. NGL production was 567,000 barrels, down slightly from the fourth quarter of 2013. Natural gas production was 13.1 billion cubic feet ("Bcf") for the fourth quarter of 2014 compared to 16.8 Bcf in the fourth quarter of 2013. Natural gas production volumes for the fourth quarter of 2013 were affected by a cumulative volume adjustment associated with previous periods, which resulted in a one-time positive adjustment of 2.6 Bcf in the fourth quarter of 2013. In January of 2014, the Company identified an erroneous MMBtu conversion factor it had been receiving from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field ("Tahoe") since we acquired the field in 2011. This adjustment did not affect revenues or cash flows but did impact previously reported natural gas production volumes and the resultant calculation of depletion expense.

For the full year of 2014, our oil production was 7.2 million barrels, up 2.3% over calendar year 2013. NGL production was 2.1 million barrels, up 1.0% over 2013, and natural gas production was 50.1 Bcf, down 6.0% from 2013. The continued focus on increasing oil production over natural gas production was evident in 2014 with our successful exploration and development program focused on oil production and through acquisitions.

Revenues for the fourth quarter of 2014 were $196.7 million compared to $244.9 million in the fourth quarter of 2013. Revenues decreased on a steep decline in crude oil prices, which were down $23.39 per barrel between the two quarters. NGLs prices declined $12.81 per barrel as a result of the decline in crude oil prices. Natural gas prices were higher by $0.66 per Mcf. During the fourth quarter of 2014, our average realized sales price was $70.72 per barrel for oil, $26.97 per barrel for NGLs and $3.81 per Mcf for natural gas. On a combined basis, we sold approximately 50,000 Boe per day at an average realized sales price of $42.46 per Boe compared to 56,100 Boe per day sold at an average realized sales price of $47.33 per Boe in the fourth quarter of 2013.

Revenues for the full year of 2014 were $948.7 million compared to $984.1 million in calendar year 2013. Revenues were lower despite the increase in oil and NGL production on an 11.2% decline in crude oil prices to $90.96 per barrel. For the year 2014, we sold on average 48,300 Boe per day at an average realized sales price of $53.49 per Boe compared to 49,300 Boe per day sold at an average realized sales price of $54.58 per Boe in calendar year 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 fourth quarter of 2014 was $89.6 million compared to $141.5 million reported for the fourth quarter of 2013. Adjusted EBITDA was lower for the fourth quarter of 2014 primarily due to a $48.3 million decrease in revenues and a $3.7 million increase in operating expenses. For the twelve months ended December 31, 2014, our Adjusted EBITDA was $569.2 million, a decrease of $37.5 million from the full year of 2013. Our Adjusted EBITDA margin was 60% for the twelve months of 2014, down from 62% in the twelve months of 2013. Net cash provided by operating activities for the twelve months of 2014 was $511.4 million compared to $561.4 million from the same period in 2013. Capital expenditures in 2014 were $630.0 million compared to $635.8 million in 2013.

At December 31, 2014, we had a cash balance of $23.7 million and $302.4 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.

Lease Operating Expenses ("LOE"): LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $75.6 million for the fourth quarter of 2014, down slightly from $75.9 million reported in the fourth quarter of 2013. Base LOE was $41.5 million in the fourth quarter of 2014, down $0.7 million from the fourth quarter of 2013. Workovers increased to $23.0 million from $20.1 million, and facilities costs decreased $3.3 million to $5.6 million. Base LOE decreased with lower down-hole well work at our Yellow Rose field and a true-up adjustment to our property taxes, partially offset by an increase in operating expenses from certain of our outside operated properties. Workover costs increased with the completion of two rig workovers at HI 111 and HI 129, more workovers at our Permian properties (with less classified as down-hole well work) due to the increase in our number of wells, partially offset by a workover performed on the A-12 well at SS 349 in the 2013 period. Facilities costs were lower as certain offshore projects that were completed in 2013 did not reoccur in the 2014 period.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for asset retirement obligations, was $28.53 per Boe for the fourth quarter of 2014, up from $26.88 per Boe in the fourth quarter of 2013. On a nominal basis, DD&A was $130.9 million for the fourth quarter of 2014 versus $138.6 million in the fourth quarter of 2013. The DD&A rate increased in part due to increases in the full cost pool from capital expenditures and future development costs growing at a rate faster than the addition of proved reserves. The focus on deepwater exploration and development necessarily increases costs before the corresponding increase in proved reserves, leading to an overall increase in the DD&A rate per produced equivalent barrel. DD&A decreased nominally due to lower production volumes. As mentioned earlier, the fourth quarter of 2013 included a 2.6 Bcf cumulative volume adjustment associated with previous periods that only impacted natural gas volumes and the calculation of depletion expense but not revenues.

General and Administrative Expenses ("G&A"): G&A was $22.7 million in the fourth quarter of 2014, up $1.8 million from the fourth quarter of 2013 on higher contract services and employee costs.

Derivatives: For the fourth quarter of 2014, our net derivative gain was $10.8 million and consisted of a realized gain of $13.2 million and an unrealized loss of $2.4 million. The net derivative gain relates to the change in the fair value of our crude oil commodity derivatives as a result of the rather dramatic decline in crude oil prices. The fourth quarter of 2013 had a net derivative loss of $2.3 million, comprised of a $1.7 million realized loss and a $0.6 million unrealized loss.

Income Taxes: For the fourth quarter of 2014, our Federal income tax benefit was $17.3 million compared to a tax benefit of $6.6 million for the fourth quarter of 2013. The increase between periods is primarily attributable to a higher pre-tax loss in 2014. Our effective tax rate for the fourth quarter of 2014 was 34.1%, which is below the statutory rate of 35% due to state income taxes and certain permanent differences not deductible for federal income tax purposes. The effective tax rate for the full year of 2014 was 27.7% and differs from the statutory rate for the same reasons enumerated above. Our effective tax rate for the fourth quarter of 2013 was 35.6% and differed from the federal statutory rate of 35.0%, primarily as a result of state income taxes and minor adjustments to reconcile the quarterly rate to the rate for the full year of 2013 of 35.9%.

Net Loss & EPS: Our net loss for the fourth quarter of 2014 was ($33.4) million, or ($0.44) per common share, compared to a net loss of ($11.9) million, or ($0.16) per common share, during the same period in 2013. Excluding special items (including derivative gains and losses), our net loss for the fourth quarter of 2014 was ($40.4) million, or a loss of ($0.53) per common share. This compares to a fourth quarter 2013 net loss, excluding special items, of ($5.7) million, or ($0.08) per common share. Earnings excluding special items were down primarily due to a $48.3 million decrease in revenues driven by a 10% decline in our realized prices, lower production volumes, and a $3.7 million increase in operating expenses ($2.2 million increase in gathering, transportation cost and production taxes, $1.8 million in G&A, offset by a $0.3 million decrease 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.

2014 Capital Expenditures Update: Our capital expenditures for the fourth quarter of 2014 were $172.3 million compared to $211.4 million for the same period in 2013. For the full year of 2014, our capital expenditures were $630.0 million, down slightly from $635.8 million spent in calendar year 2013. In 2014, capital expenditures for oil and gas properties consisted of $132.2 million for offshore exploration activities, $263.0 million for offshore development activities, $77.2 million for acquisitions of offshore properties, and $3.4 million for seismic and other. Onshore capital expenditures consisted of $52.5 million for exploration activities and $101.7 million for development activities.

2015 Capital Budget

The Company's capital expenditure budget for 2015 is currently set at $200 million and is designed to provide us with the flexibility to respond to market conditions and fund projects that are either underway or committed to with other operators. Approximately $169 million is allocated to the deepwater Gulf of Mexico, a substantial majority of which is for the completion or development of previous discoveries. The remainder of the budget is dedicated to the Gulf of Mexico shelf and our Permian Basin operations.

Dividends

In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.

Year-End 2014 Proved Reserves

Proved reserves as of December 31, 2014 increased to 120.0 MMBoe, or 720.0 Bcfe, with 65% comprised of liquids (52% crude oil and 13% NGLs) and 35% natural gas. This compares to 117.7 MMBoe, or 705.9 Bcfe, with 63% comprised of liquids (50% crude oil and 13% NGLs) and 37% natural gas at year-end 2013.

The PV-10 value of our proved reserves at year-end 2014 was $2.6 billion compared to $2.5 billion at year-end 2013, excluding the effect of estimated asset retirement obligations.

Our proved reserves as of December 31, 2014 are summarized below:

Successful exploration and development drilling, both offshore and onshore, as well as joint interest activity resulted in proved reserve extensions and discoveries of 9.7 MMBoe (58.1 Bcfe). Extensions and discoveries occurred primarily at our West Texas Permian Basin Yellow Rose field and Dantzler deepwater field, with some additions included from the Medusa and Neptune fields in the deepwater Gulf of Mexico and the Mahogany and East Cameron 321 fields on the shelf of the Gulf of Mexico.

We also added 6.1 MMBoe of proved reserves from acquisitions completed in 2014, including interests in Neptune, Ewing Banks 910, High Island 129 and Fairway fields. Upward revisions of previous estimates from numerous offshore fields accounted for 3.9 MMBoe of proved reserves, with our Fairway and East Cameron fields making the largest contribution and partially offset by reductions from certain Spraberry wells in our Yellow Rose field.

At our Dantzler field, in 2014 we booked only a small portion of the total proved reserves that we would expect this field to yield in the future. Like our discovery at Big Bend in 2012, we expect to begin converting probable and possible reserves into proved reserves once the wells are brought on production, which is anticipated to be in 2015 for Big Bend and in 2016 for Dantzler.

OPERATIONS UPDATE

Offshore Gulf of Mexico: The Company currently has three rigs running offshore (all in the deepwater), one of which is operated and two are non-operated. The operated rig is drilling a well at our Ewing Bank 910 field; one non-operated rig is drilling a well at our Medusa field, while the other non-operated rig is completing a well at our Dantzler 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 if economics are favorable and, if drilled, could be on-line by the third quarter of 2015.

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

In January 2015, we reached total depth of 12,500 feet on the Mississippi Canyon 538 SS No. 6 well encountering pay in both our primary target zones. The well logged in excess of 180' of net pay and will be completed after the SS No. 7 well, which is currently drilling, has been completed, assuming success. These exploratory wells are targeting multiple stacked oil sands. Completion operations for both wells are expected to immediately follow the drilling operations. Oil production from both wells is expected to be brought on-line in mid-2015.

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

We recently completed the Dantzler #2 well, and the rig has moved and commenced completion operations on the Dantzler #1. Production from these two high-impact oil wells is expected in late 2015 or early 2016.

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

Development at Big Bend continues, and first production from this 2012 discovery is still expected in late 2015. The expected 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).

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

The A-18 development well targeting an up-dip "P" sand location at our Mahogany Field had commenced drilling, but operations were suspended at an intermediate casing point and will not be continued until economic conditions improve.

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

The A-2 ST exploration well at East Cameron 321 was completed and ready to flow in December 2014. However, a third-party owned export gas pipeline from the platform was damaged by a barge during the fourth quarter of 2014 and subsequently restricted our oil production from the field to approximately 1,000 barrels per day.

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

During the fourth quarter, we completed six vertical wells at our Yellow Rose Field. As of the end of January 2015, we have 10 wells awaiting completion in our Yellow Rose field, four of which are vertical and six 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 recently achieved a peak rate of 1,709 Boe per day (91% oil) or 224 Boe per day per 1,000' of lateral. We drilled the University Land ("UL") 7-10 6H in Andrews County targeting the Lower Spraberry Shale and the UL 6-2 4H in Gaines County, also targeting the Lower Spraberry Shale. The UL 7-10 6H is waiting on completion and the UL 6-2 4H is in flowback operations. We drilled the Chenin 8H and the Chenin 10H wells, from the same drilling pad and both wells are prepared for and awaiting completion as horizontal Wolfcamp "B" formation wells. The rig has since been released. For the month of December 2014, production from the field averaged 4,800 Boe per day gross (3,700 Boe per day net to our interest).

First Quarter and Full Year 2015 Outlook

Our guidance for the first 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, March 5, 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 March 12, 2015 and may be accessed by calling 201-612-7415 and using the passcode 13599736.

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, 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, 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.

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, contract option fee, loss on extinguishment of debt, depletion expense related to out of period adjustments 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, contract option fee and loss on extinguishment of debt. 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.