Form 8-K W&T OFFSHORE INC For: Nov 04

HOUSTON, Nov. 4, 2015 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its third quarter 2015 operations and financial results, as well as its 2015 full year production and expense guidance. Some of the key items include:

• Production for the third quarter of 2015 averaged 46,757 barrels of oil equivalent ("Boe") per day (4.3 million Boe for the quarter), 54.9% of which was oil and liquids. Oil production increased 12.2% for the third quarter of 2015 compared to the third quarter of 2014, while natural gas production decreased 4.5% as we continue our focus on oil related projects.
• Our average realized sales price for the third quarter of 2015 was $43.85 per barrel for oil, $16.74 per barrel for NGLs and $2.69 per thousand cubic feet ("Mcf") for natural gas. On a combined basis, our average realized sales price for the third quarter was $28.92 per Boe compared to $54.13 per Boe in the third quarter of 2014.
• Revenues for the third quarter of 2015 were $126.2 million, 73.7% of which was from oil and NGLs.
• Lease operating expenses ("LOE") declined 37.2% for the third quarter of 2015 to $45.0 million compared to $71.7 million in the third quarter of 2014. In response to our cost control measures, base LOE declined $10.1 million, or 22.9%, compared to the third quarter of 2014.
• Adjusted EBITDA for the third quarter was $59.2 million and our Adjusted EBITDA margin was 47%. For the first nine months of 2015, Adjusted EBITDA was $187.3 million and our Adjusted EBITDA margin was 46%.

Highlights and activities after the quarter-end included:

• Production from "Big Bend" at Mississippi Canyon 698, that is part of the Rio Grande Loop project, was brought on-line towards the end of October 2015 and is ramping up. First production from the "Dantzler" wells at Mississippi Canyon 782 was brought on-line shortly thereafter. Stabilized production from the field is now expected sometime in December. Our estimate is still to achieve a peak rate of around 8,000 Boe per day (81% oil) net to our interest for Big Bend and Dantzler combined.
• On October 15, 2015, we closed on the sale of our interest in our Yellow Rose field for approximately $376.1 million and the assumption by the buyer of the asset retirement obligation ("ARO") associated with the field. The effective date of the sale was January 1, 2015 and the purchase price was and is subject to customary purchase price adjustments. Proceeds from the sale were used to pay off all borrowings outstanding under our revolving bank credit facility. The remaining balance of approximately $100 million was added to available cash balances. We also retained an overriding royalty interest ("ORRI") based on a sliding scale of one to four percent that is benchmarked to the monthly NYMEX WTI oil price.
• On October 30, 2015, we amended our revolving bank credit facility to change or eliminate various financial covenants and allow us to repurchase outstanding indebtedness if certain conditions are met. The amended bank credit facility set the borrowing base at $350 million. Our liquidity post the sale of the Yellow Rose field and the credit facility amendment is approximately $485 million.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "With our Rio Grande Loop project coming on-line in the fourth quarter, we anticipate that this will boost our ending 2015 production rates significantly. Big Bend was successfully brought on-line towards the end of October and will be ramping up to full rates over the next few weeks. The two wells at our Dantzler field were brought on-line shortly thereafter, which is earlier than we previously expected, and will generate variable production rates for the first several weeks as we test the dual completions of both wells. We expect that both the Big Bend and Dantzler fields will be at their full rates before the end of the year. It will be gratifying to finally see these world class deepwater fields transition into substantial cash generators. It is also a testament to everyone involved to see a major project like this completed on time and on budget.

"The closing of the sale of our Yellow Rose field in West Texas has allowed us to repay all outstanding borrowings under our revolving bank credit facility and boost our cash position by $100 million. Our focus over the near-term will be to continue to control our capital outlays and operating expenses. In the third quarter we reduced our LOE by 37% from last year and for the full year expect LOE to be down 25% year over year, with further reductions in 2016," he said.

Production, Revenues and Price: For the third quarter of 2015, our oil production was 2.0 million barrels, up 12.2% over the third quarter of 2014. NGL production was 389,000 barrels, down 23.1% from the third quarter of 2014. Natural gas production was 11.6 billion cubic feet ("Bcf") for the third quarter of 2015, down 4.5% from the third quarter of 2014. Our combined total production was 4.3 million Boe in the third quarter of 2015, flat with the third quarter of 2014.

Revenues for the third quarter of 2015 were $126.2 million compared to $234.5 million in the third quarter of 2014. Revenues decreased due to the steep decline in commodity prices. Crude oil prices were down $51.25 per barrel or 53.9% between the two quarters. NGLs prices declined 50.0%, or $16.73 per barrel, as a result of the decline in crude oil prices, continued weak natural gas prices and a significant oversupply of both ethane and propane, which comprise the majority of NGLs on a component basis. Natural gas prices were lower by $1.28 per Mcf, or 32.2% from the third quarter of 2014. During the third quarter of 2015, our average realized sales price for oil was $43.85 per barrel, $16.74 per barrel for NGLs and $2.69 per Mcf for natural gas. On a combined basis, we sold 46,757 Boe per day at an average realized sales price of $28.92 per Boe compared to 46,684 Boe per day sold at an average realized sales price of $54.13 per Boe in the third quarter of 2014.

Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA, Adjusted EBITDA, and Adjusted EBITDA margin are non-GAAP measures and are defined in the "Non-GAAP Financial Measures" section at the end of this news release.

Cash flows from operating activities, before changes in working capital and ARO settlements, were $125.8 million in the first nine months of 2015, compared to $414.9 million generated over the same time period in 2014. Cash flows declined as revenues were $348.8 million lower in the first nine months of 2015 compared to the first nine months of 2014. Payments to settle asset retirement obligations totaled $25.5 million in the first nine months of 2015. Adjusted EBITDA for the third quarter of 2015 was $59.2 million compared to $135.9 million reported for the third quarter of 2014. The $76.6 million decline in Adjusted EBITDA for the third quarter of 2015 was driven by a $108.3 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 nine months ended September 30, 2015, our Adjusted EBITDA was $187.3 million, down from the $479.6 million generated in the first nine months of 2014. Our Adjusted EBITDA margin was 47% for the third quarter of 2015, down from 58% in the third quarter of 2014, and 46% for the first nine months of 2015. Net cash provided by operating activities for the first nine months of 2015 was $134.8 million compared to $419.8 million from the same period in 2014.

Liquidity: At September 30, 2015, we had a cash balance of $7.5 million and $234.1 million of undrawn capacity available under our revolving bank credit facility, which had a borrowing base of $500.0 million.

On October 15, 2015, we closed on the sale of our interest in our Yellow Rose field for approximately $376.1 million and the assumption by the buyer of the ARO associated with the field. The effective date of the sale was January 1, 2015, and the purchase price was and is subject to customary purchase price adjustments. Proceeds from the sale were used to pay off all borrowings outstanding under our revolving bank credit facility with the remaining balance of approximately $100 million added to available cash balances. We also retained an ORRI based on a sliding scale of one to four percent that is benchmarked to monthly NYMEX WTI oil prices.

We have amended our bank facility to change or eliminate various financial covenants and allow for bond repurchases if certain conditions are satisfied. The borrowing base is now set at $350 million and our liquidity is currently about $485 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 $26.7 million, or 37.2%, to $45.0 million in the third quarter of 2015 compared to the third quarter of 2014. On a per Boe basis, lease operating expenses decreased to $10.47 per Boe in the third quarter of 2015, a 37.3% reduction compared to $16.70 per Boe in the third quarter of 2014. On a component basis, base LOE decreased $10.1 million primarily due to lower costs from service providers and less onshore downhole well work activities. Facilities maintenance expenses decreased $7.8 million due to reduced activity at multiple offshore locations and general cost reductions similar to those discussed above for base LOE.

Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for ARO, decreased to $22.62 per Boe for the third quarter of 2015 from $29.96 per Boe for the third quarter of 2014. On a nominal basis, DD&A decreased to $97.3 million for the third quarter of 2015 from $128.7 million for the third quarter of 2014 due to a decrease in the DD&A rate per Boe. The DD&A rate per Boe decreased primarily due to the ceiling test write-downs recorded in the first half 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 reduced future development costs associated therewith and lower costs for goods and services.

Ceiling test write-down of oil and natural gas properties: For the third quarter of 2015, we recorded a non-cash ceiling test write-down of $441.7 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The write-down resulted from a significant reduction in the market value of all three commodities we sell, which are crude oil, NGLs and natural gas. No ceiling test write-down was incurred or recorded during 2014.

General and Administrative Expenses ("G&A"): G&A decreased $4.5 million to $16.5 million for the third quarter of 2015 compared to the third quarter of 2014. The decrease was primarily due to lower compensation costs and reduced contractor usage, partially offset by higher medical claims, higher surety bond premium costs and lower billings to joint venture partners. G&A on a per Boe basis was $3.84 per Boe for the third quarter of 2015 compared to $4.89 per Boe for the third quarter of 2014.

Derivatives: For the third quarter of 2015, we recorded a $10.2 million derivative gain for open derivative contracts for crude oil and natural gas as of the end of the period. For the third quarter of 2014, derivative gains were $13.8 million related to derivative contracts for crude oil. No new contracts were entered into during the third quarter. The Company has hedges in place covering approximately 25% of estimated fourth-quarter production and 35% of estimated 2016 production. A schedule of our commodity derivative positions is posted to our website.

Income Taxes: Our income tax benefit for the three months and nine months ended September 30, 2015 was $18.5 million and $166.2 million, respectively. The income tax benefit is partially attributable to recording a ceiling test write-down of $441.7 million and $954.9 million in the third quarter and first nine months of 2015, respectively. Our effective tax rate for the third quarter of 2015 was 3.7%, and our effective tax rate for the nine months ended September 30, 2015 was 14.3%. 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 $0.9 million and $12.8 million for the three and nine months ended September 30, 2014, respectively. Our effective tax rates for the three and nine months ended September 30, 2014 were 56.9% and 37.1%, respectively. Our effective tax rate for the three months ended September 30, 2014 was not meaningful due to adjustments for a revised estimated effective tax rate computed on a year-to-date basis.

During the three months and nine months ended September 30, 2015, we recorded a valuation allowance of $156.2 million and $241.6 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. We have $292 million of Federal net operating loss carryforwards (tax basis) available to offset future federal taxable income in 2015 and forward.

Net Income (Loss) & Earnings (Loss) Per Share: We reported a net loss for the third quarter of 2015 of ($477.6) million, or ($6.29) per common share, compared to net income of $0.7 million, or $0.01 per common share, during the same period in 2014. Excluding special items (including the ceiling test write-down of oil and natural gas properties, and derivative gain in 2014 and 2015, net of applicable federal income tax at the effective tax rate for the periods presented), our net loss for the third quarter of 2015 was ($62.1) million, or a loss of ($0.82) per common share, compared to third quarter 2014 net loss of ($5.3) million, or ($0.07) per common share. Operating results for the third quarter of 2015, excluding special items, were down primarily due to a $108.3 million decrease in revenues driven by a 46.6% decline in our realized prices, partially offset by a $26.7 million decrease in LOE and a $31.3 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 on an accrual basis for oil and gas properties for the first nine months of 2015 were $192.8 million compared to $455.5 million in the first nine months of 2014. For the first nine months of 2015, capital expenditures for oil and gas properties consisted of $44.7 million for exploration activities, $130.4 million for development activities and $13.2 million for seismic, capitalized interest, and other. The majority of the capital has been dedicated to offshore, primarily the deepwater, with only $14.0 million dedicated to onshore. The Company's capital expenditure budget for 2015 was set at $200 million, of which approximately half was for the Big Bend and Dantzler project. Our capital expenditures for the fourth quarter of 2015 are currently expected to be $29 million to complete the Big Bend and Dantzler projects and the drilling program at EW 910.

During the first nine months of 2015, we completed five deepwater wells with two wells at Dantzler, two wells at Medusa and one well at the Ewing Bank 910 field. Also during the first nine months of 2015 we completed five wells onshore.

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:

Rio Grande Loop project: Mississippi Canyon 782 "Dantzler" Field & Mississippi Canyon 698 "Big Bend" Field (20% WI, non-operated, deepwater)

The co-development of the Big Bend and Dantzler fields is in final stages with first production having commenced at Big Bend in late October and first production for Dantzler in early November. Production at Big Bend is expected to be ramped up over the next several weeks.

First oil at the Dantzler field commenced production earlier than we expected and will be at variable rates throughout November as the four completions from the two dually completed wells are tested, evaluated and ultimately placed on long-term production. The anticipated combined rate from both Dantzler and Big Bend is expected to reach in excess of 8,000 Boe per day (81% oil), net to our interest.

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. We expect to reach total target depth of 23,200 feet by the end of November and complete the well and place it on production by year-end. The A-8 well is targeting a deeper exploratory sand from the first well in the program, and based on seismic data has the potential for a much larger impact on reserves.

The first exploration well in the EW 910 program was the ST 320 A-5 ST well, which was completed in June 2015, and logged approximately 160 feet of net pay in two zones in the GA-15 target sand. The A-5 ST well is currently flowing at a gross rate of 2,200 Boe per day or 920 Boe per day net to our interest.

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

During the third quarter, no additional wells were completed or brought on production in our Yellow Rose field. For the month of September 2015, net production from the field averaged over 2,375 Boe per day. On October 15, 2015, we completed the previously announced sale of all of our interests in the Yellow Rose field and were assigned an ORRI for the life of the field based on a sliding scale from one percent for each month that the prompt month NYMEX trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel. The value of the ORRI therefore increases as oil prices increase and as production volumes increase.

Fourth Quarter and Full Year 2015 Outlook

Our guidance for the fourth 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. Lower full-year production guidance is due primarily to the sale of our Yellow Rose field, while the lower guidance for operating expenses is due to reduced activity, lower cost of goods and services and the sale of Yellow Rose. Guidance could be affected by the factors described below in "Forward-Looking Statements."

Conference Call Information: W&T will hold a conference call to discuss our financial and operational results on Thursday, November 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 November 12, 2015 and may be accessed by calling 201-612-7415 and using the passcode 13622343.

About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 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. 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, 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 (gain) 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.