Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Mar. 03, 2015 | Jun. 30, 2014 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | WTI | ||
Entity Registrant Name | W&T OFFSHORE INC | ||
Entity Central Index Key | 1288403 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 75,899,415 | ||
Entity Public Float | $571,144,000 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $23,666 | $15,800 |
Receivables: | ||
Oil and natural gas sales | 67,242 | 96,752 |
Joint interest and other | 43,645 | 31,104 |
Total receivables | 110,887 | 127,856 |
Deferred income taxes | 11,662 | 584 |
Prepaid expenses and other assets | 36,347 | 29,362 |
Total current assets | 182,562 | 173,602 |
Property and equipment - at cost: | ||
Oil and natural gas properties and equipment (full cost method, of which $109,824 at December 31, 2014 and $116,612 at December 31, 2013 were excluded from amortization) | 8,045,666 | 7,339,097 |
Furniture, fixtures and other | 23,269 | 21,431 |
Total property and equipment | 8,068,935 | 7,360,528 |
Less accumulated depreciation, depletion and amortization | 5,575,078 | 5,084,704 |
Net property and equipment | 2,493,857 | 2,275,824 |
Restricted deposits for asset retirement obligations | 15,444 | 37,421 |
Other assets | 17,244 | 20,455 |
Total assets | 2,709,107 | 2,507,302 |
Current liabilities: | ||
Accounts payable | 194,109 | 145,212 |
Undistributed oil and natural gas proceeds | 37,009 | 42,107 |
Asset retirement obligations | 36,003 | 77,785 |
Accrued liabilities | 17,377 | 28,000 |
Total current liabilities | 284,498 | 293,104 |
Long-term debt, less current maturities | 1,360,057 | 1,205,421 |
Asset retirement obligations, less current portion | 354,565 | 276,637 |
Deferred income taxes | 186,988 | 178,142 |
Other liabilities | 13,691 | 13,388 |
Commitments and contingencies | ||
Shareholders' equity: | ||
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2014 and 2013 | ||
Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,768,588 issued and 75,899,415 outstanding at December 31, 2014; 78,460,872 issued and 75,591,699 outstanding at December 31, 2013 | 1 | 1 |
Additional paid-in capital | 414,580 | 403,564 |
Retained earnings | 118,894 | 161,212 |
Treasury stock, at cost | -24,167 | -24,167 |
Total shareholders' equity | 509,308 | 540,610 |
Total liabilities and shareholders' equity | $2,709,107 | $2,507,302 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Statement Of Financial Position [Abstract] | ||
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization | $109,824 | $116,612 |
Preferred stock, par value | $0.00 | $0.00 |
Preferred stock, shares authorized | 20,000,000 | 20,000,000 |
Preferred stock, issued | 0 | 0 |
Common stock, par value | $0.00 | $0.00 |
Common stock, shares authorized | 118,330,000 | 118,330,000 |
Common stock, issued | 78,768,588 | 78,460,872 |
Common stock, outstanding | 75,899,415 | 75,591,699 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Income Statement [Abstract] | |||||||||||||||||||
Revenues | $196,677 | $234,521 | $262,994 | $254,516 | $244,928 | [1],[2] | $244,555 | [1],[2] | $235,383 | [1],[2] | $259,222 | [1],[2] | $948,708 | $984,088 | $874,491 | ||||
Operating costs and expenses: | |||||||||||||||||||
Lease operating expenses | 264,751 | 270,839 | 232,260 | ||||||||||||||||
Production taxes | 7,932 | 7,135 | 5,840 | ||||||||||||||||
Gathering and transportation | 19,821 | 17,510 | 14,878 | ||||||||||||||||
Depreciation, depletion and amortization | 490,469 | 430,611 | 336,177 | ||||||||||||||||
Asset retirement obligations accretion | 20,633 | 20,918 | 20,055 | ||||||||||||||||
General and administrative expenses | 86,999 | 81,874 | 82,017 | ||||||||||||||||
Derivative (gain) loss | -3,965 | 8,470 | 13,954 | ||||||||||||||||
Total costs and expenses | 886,640 | 837,357 | 705,181 | ||||||||||||||||
Operating income | -30,543 | 20,983 | 34,403 | 37,225 | 622 | [1],[2] | 31,965 | [1],[2] | 53,823 | [1],[2] | 60,321 | [1],[2] | 62,068 | 146,731 | 169,310 | ||||
Interest expense: | |||||||||||||||||||
Incurred | 86,922 | 85,639 | 63,268 | ||||||||||||||||
Capitalized | -8,526 | -10,058 | -13,274 | ||||||||||||||||
Other income, net | 208 | 8,946 | 215 | ||||||||||||||||
Income (loss) before income tax expense (benefit) | -16,120 | 80,096 | 119,531 | ||||||||||||||||
Income tax expense (benefit) | -4,459 | 28,774 | 47,547 | ||||||||||||||||
Net income (loss) | ($33,371) | $684 | $9,837 | $11,189 | ($11,886) | [1],[2] | $14,194 | [1],[2] | $22,396 | [1],[2] | $26,618 | [1],[2] | ($11,661) | $51,322 | $71,984 | ||||
Basic and diluted earnings (loss) per common share | ($0.44) | [1] | $0.01 | [1] | $0.13 | [1] | $0.15 | [1] | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | ($0.16) | $0.68 | $0.95 |
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | ||||||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. |
Consolidated_Statement_of_Chan
Consolidated Statement of Changes In Shareholders' Equity (USD $) | Total | Common Stock, Regular | Common Stock, Special | Common Stock Outstanding | Additional Paid-In Capital | Retained Earnings | Retained Earnings | Retained Earnings | Treasury Stock |
In Thousands, except Share data | Common Stock, Regular | Common Stock, Special | |||||||
Beginning Balances at Dec. 31, 2011 | $544,574 | $1 | $386,920 | $181,820 | ($24,167) | ||||
Beginning Balances (in shares) at Dec. 31, 2011 | 74,352,000 | 2,869,000 | |||||||
Cash dividends | -23,798 | -59,034 | -23,798 | -59,034 | |||||
Share-based compensation | 12,398 | 12,398 | |||||||
Stock issued, net of forfeitures, shares | 898,000 | ||||||||
Shares, RSUs surrendered for payroll taxes, value | -5,329 | -5,329 | |||||||
Other | 392 | 2,197 | -1,805 | ||||||
Net income | 71,984 | 71,984 | |||||||
Ending Balances at Dec. 31, 2012 | 541,187 | 1 | 396,186 | 169,167 | -24,167 | ||||
Ending Balances (in shares) at Dec. 31, 2012 | 75,250,000 | 2,869,000 | |||||||
Cash dividends | -27,098 | -31,748 | -27,098 | -31,748 | |||||
Share-based compensation | 11,525 | 11,525 | |||||||
Stock issued, net of forfeitures, shares | 342,000 | ||||||||
Shares, RSUs surrendered for payroll taxes, value | -2,370 | -2,370 | |||||||
Other | -2,208 | -1,777 | -431 | ||||||
Net income | 51,322 | 51,322 | |||||||
Ending Balances at Dec. 31, 2013 | 540,610 | 1 | 403,564 | 161,212 | -24,167 | ||||
Ending Balances (in shares) at Dec. 31, 2013 | 75,591,699 | 75,592,000 | 2,869,000 | ||||||
Cash dividends | -30,260 | -30,260 | |||||||
Share-based compensation | 14,744 | 14,744 | |||||||
Stock issued, net of forfeitures, shares | 307,000 | ||||||||
Shares, RSUs surrendered for payroll taxes, value | -848 | -848 | |||||||
Other | -3,277 | -2,880 | -397 | ||||||
Net income | -11,661 | -11,661 | |||||||
Ending Balances at Dec. 31, 2014 | $509,308 | $1 | $414,580 | $118,894 | ($24,167) | ||||
Ending Balances (in shares) at Dec. 31, 2014 | 75,899,415 | 75,899,000 | 2,869,000 |
Consolidated_Statement_of_Chan1
Consolidated Statement of Changes In Shareholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Common Stock, Regular | |||
Paid cash dividends, per share | $0.40 | $0.36 | $0.32 |
Common Stock, Special | |||
Paid cash dividends, per share | $0.42 | $0.79 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating activities: | |||
Net income (loss) | ($11,661) | $51,322 | $71,984 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 511,102 | 451,529 | 356,232 |
Amortization of debt issuance costs and premium | 701 | 1,645 | 2,575 |
Share-based compensation | 14,744 | 11,525 | 12,398 |
Derivative (gain) loss | -3,965 | 8,470 | 13,954 |
Cash payments on derivative settlements, net | -5,318 | -8,589 | -7,664 |
Deferred income taxes | -4,760 | 30,920 | 88,109 |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | 29,510 | 980 | 818 |
Joint interest and other receivables | -4,255 | 34,257 | -28,823 |
Income taxes | 3,143 | 44,328 | -58,011 |
Prepaid expenses and other assets | 15,012 | -10,044 | 7,440 |
Asset retirement obligation settlements | -74,313 | -81,543 | -112,827 |
Accounts payable, accrued liabilities and other | 41,483 | 26,558 | 38,952 |
Net cash provided by operating activities | 511,423 | 561,358 | 385,137 |
Investing activities: | |||
Acquisition of property interest in oil and natural gas properties | -72,234 | -82,424 | -205,550 |
Investment in oil and natural gas properties and equipment | -554,378 | -551,954 | -479,313 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | |
Purchases of furniture, fixtures and other | -3,340 | -1,435 | -3,031 |
Net cash used in investing activities | -629,952 | -614,805 | -657,441 |
Financing activities: | |||
Issuance of 8.50% Senior Notes | 318,000 | ||
Borrowings of long-term debt - revolving bank credit facility | 556,000 | 563,000 | 732,000 |
Repayments of long-term debt - revolving bank credit facility | -399,000 | -443,000 | -679,000 |
Debt issuance costs | -3,892 | -8,510 | |
Dividends to shareholders | -30,260 | -58,846 | -82,832 |
Other | -345 | -260 | 379 |
Net cash provided by financing activities | 126,395 | 57,002 | 280,037 |
Increase in cash and cash equivalents | 7,866 | 3,555 | 7,733 |
Cash and cash equivalents, beginning of period | 15,800 | 12,245 | 4,512 |
Cash and cash equivalents, end of period | $23,666 | $15,800 | $12,245 |
Significant_Accounting_Policie
Significant Accounting Policies | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Significant Accounting Policies | ||||||||||||
1. Significant Accounting Policies | ||||||||||||
Operations | ||||||||||||
W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,”, “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-own subsidiary, W & T Energy VI, LLC (“Energy VI”). | ||||||||||||
Basis of Presentation | ||||||||||||
Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. | ||||||||||||
Reclassifications | ||||||||||||
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows: Income tax – receivables was combined with Joint interest and other – receivables on the Consolidated Balance Sheets. Loss on extinguishment of debt was combined with Other income, net on the Consolidated Statements of Operations. Insurance proceeds was combined with the changes in Joint interest and other receivables and changes in Other – operating assets and liabilities was combined with the changes in Accounts payable, accrued liabilities and other on the Consolidated Statements of Cash Flows. | ||||||||||||
Use of Estimates | ||||||||||||
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. | ||||||||||||
Recent Events | ||||||||||||
The price we receive for our oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth. The prices of these commodities began falling in June 2014 and were significantly lower in January and February of 2015 compared to the last few years. | ||||||||||||
We have taken several steps to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budget from the previous year; (ii) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend and (iv) implementing numerous cost reduction projects to reduce our operating costs. | ||||||||||||
Assuming continuing oil and gas prices are near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain of our financial ratio maintenance covenants under our Credit Agreement sometime during 2015. We intend to engage the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is redetermined in April 2015, but we can provide no assurance that we will be successful in obtaining such an amendment. While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing, and we may have to reduce our cash outlays further for capital expenditures and other activities until such time as market conditions recover. | ||||||||||||
We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2015; however, we cannot predict how an extended period of low commodity prices will affect our operations and liquidity levels. | ||||||||||||
Adjustment Related to Additional Volumes | ||||||||||||
In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe). The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. The effect of using this incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense. We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in 2013. The 2013 period reflects a one-time increase in natural gas production volumes of 1.9 billion cubic feet (“Bcf”) (with no corresponding increase in revenue) for the annual periods of 2011 and 2012, which increased depreciation, depletion, amortization and accretion (“DD&A”) by $5.0 million and decreased net income by $3.2 million. | ||||||||||||
Cash Equivalents | ||||||||||||
We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. | ||||||||||||
Revenue Recognition | ||||||||||||
We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company has taken less than its ownership share of production. At both December 31, 2014 and 2013, $6.4 million was included in current liabilities related to natural gas imbalances. | ||||||||||||
Concentration of Credit Risk | ||||||||||||
Our customers are primarily large integrated oil and natural gas companies and large financial institutions. Our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables except in rare circumstances. Accordingly, we do not maintain an allowance for doubtful accounts of any material amounts. | ||||||||||||
The following identifies customers from whom we derived 10% or more of receipts from sales of oil, NGLs and natural gas. | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Customer | ||||||||||||
Shell Trading (US) Co. | 47 | % | 48 | % | 35 | % | ||||||
ConocoPhillips (1) | ** | ** | 16 | % | ||||||||
** | less than 10% | |||||||||||
-1 | ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. | |||||||||||
We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. | ||||||||||||
Insurance Receivables | ||||||||||||
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 18 for information related to unpaid claims by certain underwriters. | ||||||||||||
Properties and Equipment | ||||||||||||
We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. | ||||||||||||
Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. | ||||||||||||
We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets. | ||||||||||||
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. | ||||||||||||
Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. | ||||||||||||
Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO), net of related deferred income taxes, exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is comprised of: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related tax effects. Estimated future net revenues used in the ceiling test for each year are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for that year. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. | ||||||||||||
Declines in the unweighted rolling average of first-day-of-the-month commodity prices in oil and natural gas prices after December 31, 2014 may require us to record ceiling-test impairments in the future. We did not have any write-downs related to ceiling-test impairments during 2014, 2013 and 2012, respectively. | ||||||||||||
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. | ||||||||||||
Asset Retirement Obligations | ||||||||||||
Pursuant to GAAP, we are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5. | ||||||||||||
Oil and Natural Gas Reserve Information | ||||||||||||
Pursuant to GAAP, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Another provision of the guidance is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years. Refer to Note 21 for additional information about our proved reserves. | ||||||||||||
Derivative Financial Instruments | ||||||||||||
Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. Our derivative instruments currently consist of commodity swap contracts for oil. We do not enter into derivative instruments for speculative trading purposes. | ||||||||||||
In accordance with GAAP, a derivative is recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. We have elected not to designate our commodity derivatives as hedging instruments, therefore all changes in fair value are recognized in earnings. | ||||||||||||
Fair Value of Financial Instruments | ||||||||||||
We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe the carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates. | ||||||||||||
Fair Value of Acquisitions | ||||||||||||
Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions are determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made. No goodwill was recorded for the acquisitions completed in 2014, 2013 or 2012. | ||||||||||||
Income Taxes | ||||||||||||
We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. 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. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. | ||||||||||||
Debt Issuance Costs | ||||||||||||
Debt issuance costs associated with our revolving loan facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. | ||||||||||||
Premiums Received on Debt Issuance | ||||||||||||
Premiums are recorded in long-term liabilities and are amortized over the term of the related debt using the effective interest method. | ||||||||||||
Share-Based Compensation | ||||||||||||
In accordance with GAAP, compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for more information. | ||||||||||||
Earnings Per Share | ||||||||||||
In accordance with GAAP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two-class method. For additional information, refer to Note 14. | ||||||||||||
Other Income, Net | ||||||||||||
For 2013, the amount reported consisted primarily of $9.2 million received in conjunction with a payment for an option exercised by a counterparty. Partially offsetting the proceeds were related third-party expenses of $0.1 million. The net amount was included in net cash flows from investing activities within the line, Proceeds from sales of assets and other, net in the consolidated statements of cash flows. | ||||||||||||
Recent Accounting Developments | ||||||||||||
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Topic 606). ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance. The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application. We have not determined the effect ASU 2014-09 will have on the recognition of our revenue, if any, nor have we determined the method we will utilize upon adoption, which would be in the first quarter of 2017. | ||||||||||||
In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. We do not expect the revised guidance to materially affect our evaluation as to being a going concern, or have an effect on our financial statements or related disclosures. |
Acquisitions_and_Divestitures
Acquisitions and Divestitures | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Combinations [Abstract] | |||||||||
Acquisitions and Divestitures | 2. Acquisitions and Divestitures | ||||||||
2014 Acquisitions | |||||||||
Fairway | |||||||||
On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 located offshore Alabama (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”). The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama. The effective date of the transaction was July 1, 2014. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. The purchase price was finalized during the fourth quarter of 2014. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. | |||||||||
The following table presents the preliminary purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 17,407 | |||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - non-current | 6,124 | ||||||||
Total consideration | $ | 23,531 | |||||||
The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway. | |||||||||
Woodside Properties | |||||||||
On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”). The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. All of the Woodside Properties are located in the Gulf of Mexico. The effective date of the transaction was November 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. | |||||||||
The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 52,167 | |||||||
Unevaluated properties | 2,660 | ||||||||
Sub-total cash consideration | 54,827 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - current | 782 | ||||||||
Asset retirement obligations - non-current | 10,543 | ||||||||
Sub-total non-cash consideration | 11,325 | ||||||||
Total consideration | $ | 66,152 | |||||||
The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the Woodside Properties acquisition. | |||||||||
2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited | |||||||||
The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014. Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013. | |||||||||
The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014. For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income. The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. | |||||||||
In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013. The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods. | |||||||||
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013. Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, natural gas liquids (“NGLs”) and natural gas may have been different; and the costs of operating the Woodside Properties may have been different. | |||||||||
The following table presents a summary of our pro forma financial information (in thousands, except earnings per share): | |||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | ||||||||
Revenue | $ | 971,595 | $ | 1,047,037 | |||||
Net income (loss) | (5,495 | ) | 71,432 | ||||||
Basic and diluted earnings (loss) per common share | (0.08 | ) | 0.94 | ||||||
For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated. | |||||||||
The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): | |||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2014 (a) | 2013 | ||||||||
Revenues (b) | $ | 22,887 | $ | 62,949 | |||||
Direct operating expenses (b) | 4,417 | 9,583 | |||||||
DD&A (c) | 8,374 | 20,476 | |||||||
G&A (d) | 300 | 800 | |||||||
Interest expense (e) | 329 | 987 | |||||||
Capitalized interest (f) | (19 | ) | 164 | ||||||
Income tax expense (g) | 3,320 | 10,829 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014. | ||||||||
(b) | Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside. | ||||||||
(c) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(d) | Estimated insurance costs related to the Woodside Properties. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $54.8 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(f) | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. | ||||||||
(g) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures. | |||||||||
2013 Acquisition | |||||||||
On October 17, 2013, W&T Offshore, Inc. entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Callon Petroleum Operating Company (“Callon”). Pursuant to the purchase and sale agreement, transfers of certain properties that had no preferential rights were consummated on November 5, 2013 and transfers of certain properties subject to preferential rights, of which third-parties declined to exercise their preferential rights, were consummated on December 4, 2013. The properties acquired from Callon (the “Callon Properties”) consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. All of the Callon Properties are located in the Gulf of Mexico. The effective date of the transaction was July 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and we assumed the related ARO. An upward net purchase price adjustment of $0.6 million was recorded during 2014. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. | |||||||||
The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Callon Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 73,752 | |||||||
Unevaluated properties | 9,248 | ||||||||
Sub-total cash consideration | 83,000 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - current | 90 | ||||||||
Asset retirement obligations - non-current | 4,143 | ||||||||
Sub-total non-cash consideration | 4,233 | ||||||||
Total consideration | $ | 87,233 | |||||||
The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of the Callon Properties. | |||||||||
2013 Acquisition — Revenues, Net Income and Pro Forma Financial Information — Unaudited | |||||||||
The Callon Properties were not included in our consolidated results until the respective property transfer dates, which occurred during the fourth quarter of 2013. In 2014, the Callon Properties accounted for $32.5 million of revenue, $6.6 million of direct operating expenses, $16.4 million of DD&A and $3.3 million of income taxes, resulting in $6.2 million of net income. In the fourth quarter of 2013, the Callon Properties accounted for $5.8 million of revenues, $1.3 million of direct operating expenses, $2.4 million of DD&A and $0.7 million of income taxes, resulting in $1.4 million of net income. The net income attributable to these properties does not reflect certain expenses, such as G&A and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Callon Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. | |||||||||
The unaudited pro forma financial information presented below was computed as if the acquisition of the Callon Properties had been completed on January 1, 2012. The financial information was derived from W&T’s audited historical consolidated financial statements, the Callon Properties’ audited historical financial statement, and the Callon Properties’ unaudited historical financial statement for the periods presented. | |||||||||
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Callon Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2012. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Callon; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Callon Properties may have been different. | |||||||||
The following table presents a summary of our pro forma financial information (in thousands except earnings per share): | |||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | ||||||||
Revenue | $ | 1,018,118 | $ | 923,050 | |||||
Net income | 59,015 | 85,310 | |||||||
Basic and diluted earnings per common share | 0.78 | 1.12 | |||||||
For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Callon Properties (in thousands): | |||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2013 (a) | 2012 | ||||||||
Revenues (b) | $ | 34,030 | $ | 48,559 | |||||
Direct operating expenses (b) | 6,405 | 8,525 | |||||||
DD&A (c) | 14,931 | 17,578 | |||||||
G&A (d) | (361 | ) | — | ||||||
Interest expense (e) | 1,383 | 1,660 | |||||||
Capitalized interest (f) | (164 | ) | 295 | ||||||
Income tax expense (g) | 4,143 | 7,175 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013. | ||||||||
(b) | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | ||||||||
(c) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(d) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(f) | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses. | ||||||||
(g) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures. | |||||||||
2013 Divestitures | |||||||||
On July 11, 2013, we sold our non-operated working interest in two offshore fields located in the Gulf of Mexico; the Green Canyon 60 field and the Green Canyon 19 field. The effective date was October 1, 2011 and we retained the deep rights in both fields. Due to the length of time from the effective date, we paid $4.3 million to sell the properties as revenues exceeded operating expenses and the purchase price for the period between the effective date and the close date. In connection with the sale, we reversed $15.6 million of our ARO. | |||||||||
On September 26, 2013, we sold our working interests in the West Delta area block 29 with an effective date of January 1, 2013. The property is located in the Gulf of Mexico. Including adjustments for the effective date, the net proceeds were $14.7 million, which includes a $1.7 million post-effective-date repayment that occurred during 2014. The transaction was structured as a like-kind exchange under the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases are made. Replacement purchases were made in 2013, which were within the replacement periods as defined under the IRC. In connection with this sale, we reversed $3.9 million of ARO. | |||||||||
2012 Acquisitions | |||||||||
On October 5, 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consist of leases covering 78 offshore blocks on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. The effective date was July 1, 2012. The transaction included customary adjustments for the effective date, certain closing adjustments and we assumed the related ARO. The consideration and the purchase price allocation are set forth in the table below. The purchase price was finalized during 2013. A net purchase price increase of $0.2 million was recorded during 2013. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of long-term debt in October 2012. See Note 7 for information on long-term debt. | |||||||||
The following table presents the purchase price allocation, including adjustments, for the acquisition of the Newfield Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 192,723 | |||||||
Unevaluated properties | 13,065 | ||||||||
Sub-total cash consideration | 205,788 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations – current | 7,250 | ||||||||
Asset retirement obligations - non-current | 24,414 | ||||||||
Sub-total non-cash consideration | 31,664 | ||||||||
Total consideration | $ | 237,452 | |||||||
The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded for the Newfield Properties. | |||||||||
2012 Acquisitions — Revenue, Net Income and Pro Forma Financial Information — Unaudited | |||||||||
The Newfield Properties were not included in our consolidated results until the closing date of October 5, 2012. In 2014, the Newfield Properties accounted for $121.1 million of revenue, $23.5 million of direct operating expenses, $60.5 million of DD&A and $13.0 million of income taxes, resulting in $24.1 million of net income. In 2013, the Newfield Properties accounted for $127.1 million of revenue, $26.7 million of direct operating expenses, $57.6 million of DD&A and $15.0 million of income taxes, resulting in $27.8 million of net income. In the fourth quarter of 2012, the Newfield Properties accounted for $29.6 million of revenue, $5.4 million of direct operating expenses, $11.9 million of DD&A and $4.3 million of income taxes, resulting in $8.0 million of net income. The net income attributable to these properties does not reflect certain expenses, such as G&A expense and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Newfield Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. | |||||||||
Consistent with the computation of pro forma financial information presented in Item 8, Financial Statements and Supplementary Data, in the Annual Report on Form 10-K for the year end December 31, 2012, the unaudited pro forma financial information was computed as if the acquisition of the Newfield Properties had been completed on January 1, 2011. The financial information was derived from W&T’s audited historical consolidated financial statements, the Newfield Properties’ audited historical financial statement for 2011 and the Newfield Properties’ unaudited historical financial statements for the 2012 interim period. | |||||||||
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Newfield Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2011. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Newfield; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Newfield Properties may have been different. | |||||||||
The following table presents a summary of our pro forma financial information (in thousands except earnings per share): | |||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
31-Dec-12 | |||||||||
Revenue | $ | 980,196 | |||||||
Net income | 77,036 | ||||||||
Basic and diluted earnings per common share | 1.01 | ||||||||
For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Newfield Properties (in thousands): | |||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
December 31, 2012 (a) | |||||||||
Revenues (b) | $ | 105,705 | |||||||
Direct operating expenses (b) | 33,186 | ||||||||
Insurance costs (c) | 475 | ||||||||
DD&A (d) | 53,408 | ||||||||
G&A (e) | (553 | ) | |||||||
Interest expense (f) | 12,060 | ||||||||
Capitalized interest (g) | (643 | ) | |||||||
Income tax expense (h) | 2,720 | ||||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) The adjustments are for the period from January 1, 2012 to October 5, 2012. | |||||||||
(b) | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | ||||||||
(c) | Incremental costs for insurance were estimated from the incremental costs to add the Newfield Properties to W&T’s insurance programs. The direct operating costs for the Newfield Properties described above excluded insurance costs. | ||||||||
(d) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(e) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | ||||||||
(f) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.8 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. | ||||||||
(g) | Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. | ||||||||
(h) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not included adjustments related to any other acquisitions or divestitures. | |||||||||
2012 Divestiture | |||||||||
On May 15, 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million, net, with an effective date of April 1, 2012. The transaction was structured as a like-kind exchange under the IRC Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases could be executed. Replacement purchases were consummated during 2012, which were within the replacement periods as defined under the IRC. In connection with this sale, we reversed $4.0 million of ARO. |
Hurricane_Remediation_and_Insu
Hurricane Remediation and Insurance Claims | 12 Months Ended |
Dec. 31, 2014 | |
Insurance [Abstract] | |
Hurricane Remediation and Insurance Claims | 3. Hurricane Remediation and Insurance Claims |
During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority. | |
For 2014, 2013 and 2012, we have received insurance proceeds of $12.2 million, $6.7 million and $2.9 million, respectively. These amounts are included within Net cash provided by operating activities in the Consolidated Statement of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with minor amounts recorded as reductions in Lease operating expense in the Consolidated Statements of Operations. From the third quarter of 2008 through December 31, 2014, we have received $161.2 million cumulative from our insurance underwriters related to Hurricane Ike. See Note 18 for information regarding legal actions involving certain insurers and the Company concerning claims related to Hurricane Ike damages. |
Restricted_Deposits
Restricted Deposits | 12 Months Ended |
Dec. 31, 2014 | |
Receivables [Abstract] | |
Restricted Deposits | 4. Restricted Deposits |
Restricted deposits as of December 31, 2014 and 2013 consisted of funds escrowed for the future plugging and abandonment of certain oil and natural gas properties. | |
Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. We were in compliance with the security requirements as of December 31, 2014. See Note 16 for potential future security requirements. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||
Asset Retirement Obligations | 5. Asset Retirement Obligations | |||||||
Pursuant to GAAP, an asset retirement obligation associated with the retirement of a tangible long-lived asset is required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. | ||||||||
The following is a reconciliation of our ARO liability (in thousands): | ||||||||
2014 | 2013 | |||||||
Asset retirement obligations, beginning of period | $ | 354,422 | $ | 384,053 | ||||
Liabilities settled | (74,313 | ) | (81,543 | ) | ||||
Accretion of discount | 20,633 | 20,918 | ||||||
Disposition of properties | — | (19,564 | ) | |||||
Liabilities assumed through acquisition | 21,820 | 4,233 | ||||||
Liabilities incurred | 3,258 | 1,745 | ||||||
Revisions of estimated liabilities | 64,748 | 44,580 | ||||||
Asset retirement obligations, end of period | 390,568 | 354,422 | ||||||
Less current portion | 36,003 | 77,785 | ||||||
Long-term | $ | 354,565 | $ | 276,637 | ||||
During 2014, we increased our ARO on an overall basis primarily due to revisions, acquisitions and accretion of discount. Revisions increased ARO on a net basis primarily attributable to: a) increases at certain non-operated properties, b) regulation interpretations issued by the Bureau of Safety and Environmental Enforcement (“BSEE”), which increased the amount of work involved, c) revisions to third-party contractor estimated prices for certain work on wells and structures, d) revisions accelerating the timing of planned work for certain wells and e) revisions for certain wells that are taking longer to complete the plugging and abandonment work than previously estimated due to operational issues. Increases related to acquisitions include the increase in our ownership interest at Fairway, the acquisition of the Woodside Properties and other minor acquisitions. Partially offsetting these were decreases for the plug and abandonment work performed during the year and the disposition of certain properties. | ||||||||
During 2013, we reduced our ARO on an overall basis primarily due to the plug and abandonment work performed during the year. In addition, the disposition of certain properties, as described in Note 2, reduced our ARO. The acquisition of the Callon Properties and drilling activity caused ARO to increase. Revisions that increased ARO on a net basis primarily attributable to: a) regulation interpretations issued by the BSEE, which increased the amount of work involved, b) revisions to third-party contractor estimated prices for certain work on wells and structures, c) revisions accelerating the timing of planned work for certain wells and d) revisions for certain wells that took longer to complete the plugging and abandonment work than previously estimated due to operational issues. In addition, increases were made for certain locations affected by Hurricane Ike and increases in estimates were made for certain non-operated properties. |
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||
Derivative Financial Instruments | 6. Derivative Financial Instruments | |||||||||||
Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of our oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders and we do not require collateral from our derivative counterparties. | ||||||||||||
In accordance with GAAP, we record each derivative contract on the balance sheet as an asset or a liability at its fair value. We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts are recognized currently in earnings. The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows. | ||||||||||||
For information about fair value measurements, refer to Note 8. | ||||||||||||
Commodity Derivatives | ||||||||||||
As of December 31, 2014, we did not have any open commodity contracts. During the years ended December 31, 2014, 2013 and 2012, we entered into derivative contracts and these contracts consisted entirely of crude oil swap contracts. While these contracts were intended to reduce the effects of price volatility, they may have limited income from favorable price movements. The crude oil swap contracts were comprised of a portion based on Brent crude oil prices, a portion based on West Texas Intermediate (“WTI”) crude oil prices and a portion based on Light Louisiana Sweet (“LLS”) crude oil prices. The Brent based swap contracts were priced off the Brent crude oil price quoted on the Intercontinental Exchange, known as ICE. The WTI based swap contracts were priced off the New York Mercantile Exchange, known as NYMEX. The LLS based swap contracts were priced from data provided by Argus, an independent media organization. Although our Gulf of Mexico crude oil price is based off the WTI crude oil price plus a premium, the realized prices received for our Gulf of Mexico crude oil, up until October 2013, had been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which was based off the Brent crude oil price. Therefore, a portion of the swap oil contracts were priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production. | ||||||||||||
The following balance sheet line items included amounts related to the estimated fair value of our open derivative contracts as indicated in the following table (in thousands): | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid and other assets | $ | — | $ | 141 | ||||||||
Accrued liabilities | — | 9,423 | ||||||||||
Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows (in thousands): | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Derivative (gain) loss: | $ | (3,965 | ) | $ | 8,470 | $ | 13,954 | |||||
Cash payments on derivative settlements, net, are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands): | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash payments on derivative settlements, net | $ | 5,318 | $ | 8,589 | $ | 7,664 | ||||||
Offsetting Commodity Derivatives | ||||||||||||
During 2014, 2013 and 2012, all of our derivative agreements allowed for netting of derivative gains and losses upon settlement. In general, the terms of the agreements provided for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments. If we were required to settle all of our open derivative instruments, we would have been able to net payments and receipts per counterparty pursuant to the derivative agreements. Although our derivative agreements allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability. | ||||||||||||
There were no open derivative contracts as of December 31, 2014. The following table provides a reconciliation of the gross assets and liabilities reflected in the balance sheet and the potential effects of master netting agreements on the fair value of open derivative contracts as of December 31, 2013 (in thousands): | ||||||||||||
31-Dec-13 | ||||||||||||
Derivative | Derivative | |||||||||||
Assets | Liabilities | |||||||||||
Gross amounts presented in the balance sheet | $ | 141 | $ | 9,423 | ||||||||
Amounts not offset in the balance sheet | (141 | ) | (141 | ) | ||||||||
Net Amounts | $ | — | $ | 9,282 | ||||||||
LongTerm_Debt
Long-Term Debt | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Debt Disclosure [Abstract] | ||||||||
Long-Term Debt | 7. Long-Term Debt | |||||||
As of December 31, 2014 and 2013, our long-term debt was as follows (in thousands): | ||||||||
December 31, | ||||||||
2014 | 2013 | |||||||
8.50% Senior Notes | $ | 900,000 | $ | 900,000 | ||||
Debt premiums, net of amortization | 13,057 | 15,421 | ||||||
Revolving bank credit facility | 447,000 | 290,000 | ||||||
Total long-term debt | 1,360,057 | 1,205,421 | ||||||
Current maturities of long-term debt | — | — | ||||||
Long term debt, less current maturities | $ | 1,360,057 | $ | 1,205,421 | ||||
-1 | Aggregate annual maturities of long-term debt as of December 31, 2014 are as follows (in millions): 2015–$0.0; 2016–$0.0; 2017–$0.0; 2018–$447.0; thereafter–$900.0. | |||||||
Senior Notes | ||||||||
On October 24, 2012, we issued $300.0 million of Senior Notes at a premium of 106% par value with an interest rate of 8.50% (7.7% effective interest rate) and maturity date of June 15, 2019, which have identical terms to the Senior Notes issued in June 2011 (collectively, the “8.50% Senior Notes”). The net proceeds after fees and expenses were approximately $312.0 million. The funds were used to repay all of our outstanding indebtedness under our revolving bank credit facility, a portion of which was incurred to partially fund our acquisition of the Newfield Properties described in Note 2, and for general corporate purposes. In February 2013, holders of the 8.50% Senior Notes issued in October 2012 exchanged their 8.50% Senior Notes for registered notes with the same terms. | ||||||||
On June 10, 2011, we issued $600.0 million of Senior Notes at par with an interest rate of 8.50% and maturity date of June 15, 2019. The net proceeds after fees and expenses were approximately $593.5 million. In January 2012, holders of the Senior Notes issued in June 2011 exchanged their Senior Notes for registered notes with the same terms. | ||||||||
Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15 of each year and all of the 8.50% Senior Notes are subject to the same indenture. The 8.50% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries. At December 31, 2014 and 2013, the outstanding balance of our 8.50% Senior Notes was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4% for 2014, which includes amortization of debt issuance costs and premiums. At December 31, 2014 and 2013, the estimated fair value of the 8.50% Senior Notes was approximately $594.0 million and $962.5 million, respectively. | ||||||||
We and our restricted subsidiaries are subject to certain covenants under the indenture governing the 8.50% Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries. We were in compliance with all applicable covenants of the indenture governing the 8.50% Senior Notes as of December 31, 2014. | ||||||||
Credit Agreement | ||||||||
On November 8, 2013, we entered into the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”), which provides a revolving bank credit facility of up to $1.2 billion. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders, and the Company and the lenders may each request one additional determination per year. The borrowing base as of December 31, 2014 was $750.0 million. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. Letters of credit may be issued in amounts up to $300.0 million, provided availability under the revolving bank credit facility exists. The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018 and replaced the prior Fourth Amended and Restated Credit Agreement (the “Prior Credit Agreement”). | ||||||||
The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends in excess of $60.0 million per year; (ii) repurchase our common stock or outstanding senior notes in excess of $100.0 million in the aggregate, provided that such limitation will not apply to the repurchase of our existing senior notes in an aggregate principal amount equal to the aggregate principal amount of any new issuance of notes; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders. We are permitted to issue additional unsecured indebtedness above our current level of $900.0 million as long as no event of default occurs, we are in compliance with the financial covenants after giving pro forma effect to the additional unsecured indebtedness, and such additional unsecured indebtedness matures after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement. If we issue additional unsecured indebtedness in excess of the current $900.0 million in aggregate principal amount, the borrowing base then in effect will be reduced by $0.25 for each dollar of such excess until the borrowing base is redetermined by our lenders. | ||||||||
Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 1.75% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1.0%, plus applicable margin ranging from 0.75% to 1.75%. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.5%. The estimated annual effective interest rate was 2.9% for 2014 for borrowings under the Credit Agreement. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. | ||||||||
The Credit Agreement contains various customary covenants, customary events of default and certain financial tests, as of the end of each quarter, including a maximum consolidated leverage ratio, as defined in the Credit Agreement, of 3.5 to 1.0, and a minimum current ratio, as defined in the Credit Agreement, of 1.0 to 1.0. The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2014. | ||||||||
As it applies to debt issuance costs, we applied accounting guidance under the FASB codification 470-50-40-21 that relates to line-of-credit arrangements. The Credit Agreement had an initial borrowing base equal to the borrowing base under the Prior Credit Agreement. One of the 20 banks in the syndication under the Prior Credit Agreement was replaced with a different bank under the Credit Agreement and the other 19 banks were unchanged. Accordingly, we apportioned the unamortized debt issuance cost related to the Prior Credit Agreement and expensed the portion related to the bank whose debt was extinguished and did not participate in the Credit Agreement. The remaining unamortized debt issuance costs related to the Prior Credit Agreement was combined with the debt issuance costs related to the Credit Agreement and is being amortized over the term of the Credit Agreement on a straight line basis. | ||||||||
At December 31, 2014, we had $447.0 million in borrowings and $0.6 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2013, we had $290.0 million in borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility. | ||||||||
For information about fair value measurements, refer to Note 8. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||
Fair Value Measurements | 8. Fair Value Measurements | |||||||||||||||||
Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk. | ||||||||||||||||||
Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: | ||||||||||||||||||
· | Level 1 – quoted prices in active markets for identical assets or liabilities. | |||||||||||||||||
· | Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). | |||||||||||||||||
· | Level 3 – unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. | |||||||||||||||||
The following table presents the fair value of our derivative financial instruments, our 8.50% Senior Notes and our revolving bank credit facility (in thousands): | ||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||
Hierarchy | Assets | Liabilities | Assets | Liabilities | ||||||||||||||
Derivatives | Level 2 | $ | — | $ | — | $ | 141 | $ | 9,423 | |||||||||
8.50% Senior Notes | Level 2 | — | 594,000 | — | 962,460 | |||||||||||||
Revolving bank credit facility | Level 2 | — | 447,000 | — | 290,000 | |||||||||||||
We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. The fair value of our 8.50% Senior Notes is based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2. The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates. | ||||||||||||||||||
Derivatives are reported in the statement of financial position at fair value. The 8.50% Senior Notes are reported in the statement of financial position at their carrying value, which was $900.0 million at December 31, 2014 and 2013. The revolving bank credit facility debt is reported in the statement of financial position at its carrying value, which was $447.0 million and $290.0 million at December 31, 2014 and 2013, respectively. | ||||||||||||||||||
For additional information about our derivative financial instruments refer to Note 6 and for additional information on our 8.50% Senior Notes and revolving bank credit facility refer to Note 7. |
Equity_Structure_and_Transacti
Equity Structure and Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Equity [Abstract] | |
Equity Structure and Transactions | 9. Equity Structure and Transactions |
As of December 31, 2014 and 2013, the Company was authorized to issue 20 million shares of preferred stock with a par value of $0.00001 per share; however, no preferred shares have been issued or were outstanding as of the respective dates. | |
During 2014, 2013 and 2012, we paid regular cash dividends of $0.40, $0.36 and $0.32 common share per year, respectively. In December 2013, we paid a special dividend of $0.42 per share or $31.8 million. In December 2012, we paid two special dividends totaling $0.79 per share or $59.0 million. Dividends are subject to periodic reviews of the Company’s performance and current economic environment and applicable debt agreement restrictions. In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend. |
Incentive_Compensation_Plan_an
Incentive Compensation Plan and Directors Compensation Plan | 12 Months Ended |
Dec. 31, 2014 | |
Compensation Related Costs [Abstract] | |
Incentive Compensation Plan and Directors Compensation Plan | 10. Incentive Compensation Plan and Directors Compensation Plan |
Incentive Compensation Plan | |
In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders and amendments to the Plan were approved by our shareholders in 2013. The Plan covers the Company’s eligible employees and consultants. In addition to other cash and share-based compensation awards, the Plan is designed to grant awards that qualify as performance-based compensation within the meaning of section 162(m) of the IRC. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and Chief Executive Officer with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”). | |
Pursuant to the terms of the Plan, the Committee establishes the performance criteria and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will be paid within 90 days following the applicable year end. | |
Share-based Awards: Restricted Stock Units | |
For 2014, 2013 and 2012, performance awards under the Plan were granted in the form of restricted stock units (“RSUs”). As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria. Vesting occurs upon completion of the specified vesting period applicable to each grant. Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. | |
During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which is comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2014 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2014. Adjustments range from 0% to 100% dependent upon actual results compared against pre-defined performance levels. For 2014, the Company was above target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin. | |
During 2013, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2013; (ii) Adjusted EBITDA Margin for 2013; and (iii) the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for 2013, 2014 and January 1, 2015 to October 31, 2015. TSR is determined based upon the change in the entity’s stock price plus dividends for the applicable performance period. Adjustments range from 0% to 150% for portions subject to Adjusted EBITDA and Adjusted EBITDA Margin measurements and adjustments range from 0% to 200% for the portion subject to TSR measurement. For 2013, the Company exceeded the target for Adjusted EBITDA and was approximately at target for 2013 Adjusted EBITDA Margin. For 2014 and 2013, the Company was below target for the TSR rankings for each period. In addition, RSUs were granted during 2013 which were not subject to performance criteria and were less than 3% of total grants. | |
During 2012, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) earnings per share (“EPS”) for 2012; and (ii) the Company’s TSR ranking against peer companies’ TSR for 2012, 2013 and January 1, 2014 to October 31, 2014. Adjustments range from 0% to 100% for the portion subject to EPS measurement and adjustments range from 0% to 150% for the portion subject to TSR measurement. Pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which reduced the forfeitures that would have occurred through application of the pre-defined performance measurement. | |
All RSUs granted to date are subject to employment-based criteria in addition to performance criteria. Vesting occurs in December of the third year after the grant. For example, the RSUs granted during 2012 (after adjustment for performance) vested in December 2014 to eligible employees. | |
Cash-based Awards | |
For 2014, 2013 and 2012, cash-based awards were granted under the Plan to substantially all eligible employees. The cash-based awards, which are a short-term component of the Plan, were determined based on multiple performance measures, such as Adjusted EBITDA, reserve and production growth, cost containment and individual performance measures. With respect to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. With respect to the 2013 cash-based awards, most of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. With respect to the 2012 cash-based awards, some of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. In addition, pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which increased cash-based award amounts in 2012. Eligible employees are paid their cash-based awards within 75 days following year end. | |
Share-based Awards: Common Stock | |
The 2014 annual incentive plan award for the Chief Executive Officer (“CEO”) was settled in shares of common stock based on a pre-determined price of $14.66 per share, subject to pre-defined performance measures and approval of the Compensation Committee. As the number of shares could not be determined until the full-year 2014 results were determined and approved by the Committee, the CEO’s 2014 award was accounted for as a liability award during 2014 and adjusted to fair value using the Company’s closing price at the end of each reporting period. The grant was made in the first quarter of 2015 once the number of shares could be determined and approved by the Committee. The 2013 annual incentive plan award for the CEO was settled in shares of common stock based using the price of the stock immediately preceding the day the award was settled and the grant was made in the first quarter of 2014. Adjustments were made to both grants to satisfy withholding tax requirements. The performance measures for the CEO’s awards were the same as the cash-based-awards performance measures established for the other eligible Company employees for 2014 and 2013, respectively. | |
Directors Compensation Plan Share-Based Awards | |
Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2014, 2013 and 2012 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period. | |
For additional information concerning share-based awards and cash-based awards, including expense recognition, see Note 11. |
ShareBased_and_CashBased_Incen
Share-Based and Cash-Based Incentive Compensation | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ||||||||||||||||||||||||
Share-Based and Cash-Based Incentive Compensation | 11. Share-Based and Cash-Based Incentive Compensation | |||||||||||||||||||||||
As allowed by the Plan, in 2014, 2013 and 2012, the Company granted RSUs to certain of its employees. In 2014, 2013 and 2012, restricted stock was granted to the Company’s non-employee directors under the Directors Compensation Plan. In addition to share-based compensation, the Company granted cash-based incentive awards to substantially all eligible employees in 2014, 2013 and 2012. | ||||||||||||||||||||||||
On May 7, 2013, after receiving shareholder approval, 4,000,000 shares of common stock were added to the amount available for issuance under the Plan. As of December 31, 2014, there were 4,790,082 shares of common stock available for issuance in satisfaction of awards under the Plan and 500,564 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. The shares available for both plans are reduced when restricted stock is granted. RSUs reduce the shares available in the Plan only when RSUs are settled in shares of common stock, net of withholding tax. Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date. | ||||||||||||||||||||||||
Restricted Stock | ||||||||||||||||||||||||
Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2014, 2013 and 2012 to the Company’s non-employee directors. See Note 10 for additional information concerning Restricted Shares. A summary of activity related to Restricted Shares is as follows: | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Restricted Shares | Weighted Average Grant Date Fair Value Per Share | Restricted Shares | Weighted Average Grant Date Fair Value Per Share | Restricted Shares | Weighted Average Grant Date Fair Value Per Share | |||||||||||||||||||
Nonvested, beginning of period | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | |||||||||||||||
Granted | 18,815 | 18.6 | 27,450 | 12.75 | 21,954 | 19.13 | ||||||||||||||||||
Vested | (19,445 | ) | 18 | (27,297 | ) | 17.09 | (27,475 | ) | 13.59 | |||||||||||||||
Forfeited | — | — | — | — | (2,662 | ) | 18.78 | |||||||||||||||||
Nonvested, end of period | 43,210 | $ | 16.2 | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | |||||||||||||||
Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2014 are expected to vest as follows: | ||||||||||||||||||||||||
Restricted Shares | ||||||||||||||||||||||||
2015 | 21,520 | |||||||||||||||||||||||
2016 | 15,420 | |||||||||||||||||||||||
2017 | 6,270 | |||||||||||||||||||||||
Total | 43,210 | |||||||||||||||||||||||
Restricted stock fair value at grant date and vested date: The grant date fair value of restricted stock granted during 2014, 2013 and 2012 was $0.3 million, $0.3 million and $0.4 million, respectively, based on the Company’s closing price on the date of grant. The fair value of the restricted stock that vested during 2014, 2013 and 2012 was $0.3 million, $0.4 million and $0.5 million, respectively, based on the Company’s closing price on the date of vesting. | ||||||||||||||||||||||||
Restricted Stock Units | ||||||||||||||||||||||||
During 2014, 2013 and 2012, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements. The grants are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria. See Note 10 for additional information concerning RSUs. | ||||||||||||||||||||||||
The fair value of the RSUs granted in 2014 was determined using the Company’s closing price on the grant dates as the performance measures were all company-specific performance measures comprised of Adjusted EBITDA and Adjusted EBITDA Margin. | ||||||||||||||||||||||||
The fair value of the RSUs granted in 2013 was determined separately for each component. For the components related to the company-specific performance measures (Adjusted EBITDA and Adjusted EBITDA Margin), the fair value was determined using the Company’s closing price on the grant date. The components related to Adjusted EBITDA and Adjusted EBITDA Margin comprised 40% and 30%, respectively, of the amount granted. For the component related to TSR ranking, the fair value was determined using a Monte Carlo simulation probabilistic model. The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods. The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2013; risk-free interest rates using the LIBOR ranging from 0.27% to 0.91% over the service period; expected volatilities ranging from 30% to 63%; expected dividend yields ranging from 0.0% to 3.1%; and correlation factors ranging from a negative 84% to a positive 95%. The expected volatilities, expected dividends and correlation factors were developed using historical data. For the RSUs granted in 2013 that were not subject to performance measures, the fair value was determined using the closing price on the date of grant. | ||||||||||||||||||||||||
The fair value of the RSUs granted in 2012 was determined separately for the two components. For the component related to the company-specific performance measure, which was comprised of only EPS, the fair value was determined using the Company’s closing price on the grant date. The component related to EPS comprised 70% of the amount granted. For the component related to TSR ranking, the fair value was determined by using a Monte Carlo simulation probabilistic model. The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods. The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the LIBOR ranging from 0.15% to 0.72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from a negative 67% to a positive 94%. The expected volatilities, expected dividends and correlation factors were developed using historical data. | ||||||||||||||||||||||||
A summary of activity related to RSUs is as follows: | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | |||||||||||||||||||
Nonvested, beginning of period | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | |||||||||||||||
Granted | 1,195,388 | 16.84 | 969,919 | 13.23 | 764,654 | 18.64 | ||||||||||||||||||
Vested | (354,692 | ) | 18.59 | (468,925 | ) | 26.93 | (1,198,208 | ) | 9.36 | |||||||||||||||
Forfeited | (195,114 | ) | 16.53 | (139,061 | ) | 16.5 | (329,329 | ) | 19.56 | |||||||||||||||
Nonvested, end of period | 1,977,335 | $ | 15.29 | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | |||||||||||||||
Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2014 are eligible to vest in the year indicated in the table below: | ||||||||||||||||||||||||
Restricted Stock Units | ||||||||||||||||||||||||
2015 - subject to service requirements | 759,234 | |||||||||||||||||||||||
2015 - subject to service and other requirements (1) | 90,105 | |||||||||||||||||||||||
2016 - subject to service requirements | 1,127,996 | |||||||||||||||||||||||
Total | 1,977,335 | |||||||||||||||||||||||
-1 | In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted. | |||||||||||||||||||||||
RSUs fair value at grant date: During 2014, 2013 and 2012, the grant date fair value of RSUs granted was $20.1 million, $12.8 million and $14.3 million, respectively. | ||||||||||||||||||||||||
RSUs fair value at vested date: The fair value of the RSUs that vested during 2014, 2013 and 2012 was $2.0 million, $7.2 million and $20.0 million, respectively, based on the Company’s closing price on the vesting date. | ||||||||||||||||||||||||
Common Stock | ||||||||||||||||||||||||
A grant and issuance of 42,547 shares of common stock was made in March 2014 to the CEO pursuant to the terms of his 2013 annual incentive compensation award. The number of shares was determined after deductions for withholding and payroll taxes and the shares were valued at the Company’s closing price as of the date of grant. The grant and issuance of shares of common stock pursuant to the terms of the CEO’s 2014 annual incentive compensation award will be made during the first quarter of 2015. See Note 10 for additional information concerning the CEO annual incentive compensation award. | ||||||||||||||||||||||||
Share-Based Compensation | ||||||||||||||||||||||||
A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): | ||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Share-based compensation expense from: | ||||||||||||||||||||||||
Restricted stock | $ | 369 | $ | 397 | $ | 399 | ||||||||||||||||||
Restricted stock units | 13,150 | 11,128 | 11,999 | |||||||||||||||||||||
Common shares | 1,225 | — | — | |||||||||||||||||||||
Total | $ | 14,744 | $ | 11,525 | $ | 12,398 | ||||||||||||||||||
Share-based compensation tax benefit: | ||||||||||||||||||||||||
Tax benefit computed at the statutory rate | $ | 5,160 | $ | 4,034 | $ | 4,339 | ||||||||||||||||||
As of December 31, 2014, unrecognized share-based compensation expense related to our awards of Restricted Shares, RSUs and common stock was $0.5 million, $16.5 million and $0.1 million, respectively. Unrecognized compensation expense will be recognized through April 2017 for restricted shares, November 2016 for RSUs and February 2015 for common stock. | ||||||||||||||||||||||||
Cash-based Incentive Compensation | ||||||||||||||||||||||||
As defined by the Plan, annual incentive awards payable in cash may be granted to eligible employees. These awards are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year. | ||||||||||||||||||||||||
Share-Based Compensation and Cash-Based Incentive Compensation Expense | ||||||||||||||||||||||||
A summary of incentive compensation expense is as follows (in thousands): | ||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Share-based compensation included in: | ||||||||||||||||||||||||
General and administrative (1) | $ | 14,744 | $ | 11,525 | $ | 12,398 | ||||||||||||||||||
Cash-based incentive compensation included in: | ||||||||||||||||||||||||
Lease operating expense | 3,285 | 3,482 | 3,787 | |||||||||||||||||||||
General and administrative (1) | 6,950 | 8,817 | 6,558 | |||||||||||||||||||||
Total charged to operating income | $ | 24,979 | $ | 23,824 | $ | 22,743 | ||||||||||||||||||
-1 | Reclassified $0.7 million from cash-based incentive compensation expense to share-based compensation expense in 2014 related to the CEO’s 2013 award. |
Employee_Benefit_Plan
Employee Benefit Plan | 12 Months Ended |
Dec. 31, 2014 | |
Compensation And Retirement Disclosure [Abstract] | |
Employee Benefit Plan | 12. Employee Benefit Plan |
We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. During 2014, 2013 and 2012, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% for 2014, 2013 and 2012 of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Our expenses relating to the 401(k) Plan were $2.4 million, $2.1 million and $2.1 million for 2014, 2013 and 2012, respectively. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||
Income Taxes | 13. Income Taxes | |||||||||||||||||||||||
Income Tax Expense (Benefit) | ||||||||||||||||||||||||
Components of income tax expense (benefit) were as follows (in thousands): | ||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Current | $ | 301 | $ | (2,146 | ) | $ | (40,562 | ) | ||||||||||||||||
Deferred | (4,760 | ) | 30,920 | 88,109 | ||||||||||||||||||||
$ | (4,459 | ) | $ | 28,774 | $ | 47,547 | ||||||||||||||||||
Effective Tax Rate Reconciliation | ||||||||||||||||||||||||
The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands): | ||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Income tax expense (benefit) at the federal | $ | (5,642 | ) | 35 | % | $ | 28,033 | 35 | % | $ | 41,836 | 35 | % | |||||||||||
statutory rate | ||||||||||||||||||||||||
Qualified domestic production activities | — | — | — | — | 4,256 | 3.5 | ||||||||||||||||||
State income taxes | 263 | (1.6 | ) | 343 | 0.4 | 750 | 0.7 | |||||||||||||||||
Other | 920 | (5.7 | ) | 398 | 0.5 | 705 | 0.6 | |||||||||||||||||
$ | (4,459 | ) | 27.7 | % | $ | 28,774 | 35.9 | % | $ | 47,547 | 39.8 | % | ||||||||||||
Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate. Our effective tax rate for the year 2013 differed from the federal statutory rate primarily as a result of state income taxes. Our effective tax rate for the year 2012 differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years and the impact of state income taxes. | ||||||||||||||||||||||||
Deferred Tax Assets and Liabilities | ||||||||||||||||||||||||
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): | ||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Deferred tax liabilities: | ||||||||||||||||||||||||
Property and equipment | $ | 518,566 | $ | 422,805 | ||||||||||||||||||||
Other | 5,019 | 3,602 | ||||||||||||||||||||||
Total deferred tax liabilities | 523,585 | 426,407 | ||||||||||||||||||||||
Deferred tax assets: | ||||||||||||||||||||||||
Alternative minimum tax credit | 20,486 | 20,486 | ||||||||||||||||||||||
Asset retirement obligations | 137,597 | 124,863 | ||||||||||||||||||||||
Federal net operating losses | 180,024 | 91,472 | ||||||||||||||||||||||
State net operating losses | 5,008 | 5,028 | ||||||||||||||||||||||
Derivatives | — | 3,270 | ||||||||||||||||||||||
Valuation allowance (state) | (4,255 | ) | (4,490 | ) | ||||||||||||||||||||
Accrued cash-based bonus | 3,559 | 3,873 | ||||||||||||||||||||||
Stock-based compensation | 5,042 | 3,703 | ||||||||||||||||||||||
Other | 798 | 643 | ||||||||||||||||||||||
Total deferred tax assets | 348,259 | 248,848 | ||||||||||||||||||||||
Net deferred tax liabilities | $ | 175,326 | $ | 177,559 | ||||||||||||||||||||
During 2014, we made did not make any payments for federal and state income taxes and we received refunds of $3.0 million. During 2013, we made payments primarily for federal and state income taxes of approximately $3.0 million. During 2013, we received refunds of $59.1 million, of which $9.5 million have been accounted for as unrecognized tax benefits. The refunds were primarily attributable to tax loss carrybacks to 2010 and 2011, and refunds of estimated tax payments. During 2012, we made payments primarily for federal and state income taxes of $16.1 million and we received refunds related to prior years of $0.5 million. | ||||||||||||||||||||||||
At December 31, 2014, we did not have a federal income tax receivable. At December 31, 2013, we had a federal income tax receivable of $3.1 million. This amount is comprised principally of refunds related to estimated taxes paid during 2013. | ||||||||||||||||||||||||
Net Operating Loss and Tax Credit Carryovers | ||||||||||||||||||||||||
The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2014 (in thousands): | ||||||||||||||||||||||||
Amount | Expiration Year | |||||||||||||||||||||||
Federal net operating loss | $ | 516,393 | 2032-2034 | |||||||||||||||||||||
State net operating losses | 99,656 | 2021-2029 | ||||||||||||||||||||||
Alternative minimum tax credit | 12,091 | Indefinite | ||||||||||||||||||||||
General business credit | 406 | 2027-2028 | ||||||||||||||||||||||
The federal net operating loss and alternative minimum tax credit amounts presented in the table, Deferred Tax Assets and Liabilities, reflect adjustments for unrecognized excess tax benefits and uncertain tax positions, as applicable, to the amounts presented above. | ||||||||||||||||||||||||
Valuation Allowance | ||||||||||||||||||||||||
As of December 31, 2014 and 2013, we had a valuation allowance related to Louisiana state net operating losses. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. 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. As part of our assessment, we consider future reversals of existing taxable temporary differences. | ||||||||||||||||||||||||
Uncertain Tax Positions | ||||||||||||||||||||||||
The table below sets forth the reconciliation of the beginning and ending balances of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change in the next 12 months, we do not anticipate it having a material impact on our financial statements. | ||||||||||||||||||||||||
Balances and changes in the uncertain tax positions are as follows (in thousands): | ||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Balance, beginning of period | $ | 9,482 | $ | — | ||||||||||||||||||||
Increases related to carryback positions | — | 9,482 | ||||||||||||||||||||||
Balance, end of period | $ | 9,482 | $ | 9,482 | ||||||||||||||||||||
We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2014, 2013 and 2012, the amounts recognized in income tax expense were immaterial. | ||||||||||||||||||||||||
Years open to examination | ||||||||||||||||||||||||
The tax years from 2010 through 2014 remain open to examination by the tax jurisdictions to which we are subject. |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Earnings Per Share | 14. Earnings Per Share | |||||||||||
In accordance with GAAP, the Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method. | ||||||||||||
The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 51,322 | $ | 71,984 | |||||
Less portion allocated to nonvested shares | 269 | 303 | 983 | |||||||||
Net income (loss) allocated to common shares | $ | (11,930 | ) | $ | 51,019 | $ | 71,001 | |||||
Weighted average common shares outstanding | 75,609 | 75,239 | 74,354 | |||||||||
Basic and diluted earnings (loss) per common share | $ | (0.16 | ) | $ | 0.68 | $ | 0.95 | |||||
Shares excluded due to being anti-dilutive (weighted-average) | 29 | — | 1,923 | |||||||||
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Supplemental Cash Flow Elements [Abstract] | ||||||||||||
Supplemental Cash Flow Information | 15. Supplemental Cash Flow Information | |||||||||||
The following reflects our supplemental cash flow information (in thousands): | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash paid for interest, net of interest capitalized of $8,526 in 2014, | $ | 77,607 | $ | 73,909 | $ | 46,247 | ||||||
$10,058 in 2013 and $13,274 in 2012 | ||||||||||||
Cash paid for income taxes | — | 3,000 | 16,056 | |||||||||
Cash refunds received for income taxes | 3,000 | 59,126 | 479 | |||||||||
Cash paid for share-based compensation (1) | 431 | 466 | 1,531 | |||||||||
Cash tax benefit related to share-based compensation (2) | — | — | 5,962 | |||||||||
-1 | The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements. | |||||||||||
-2 | The cash tax benefit for share-based compensation is attributable to tax deductions for vested restricted shares, vested RSUs, dividends paid on unvested restricted stock and dividend equivalents paid on RSUs. For 2014 and 2013, no cash tax benefit was realized as the Company had a tax loss for that year and all carrybacks had previously been utilized. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2014 | |
Leases [Abstract] | |
Commitments | 16. Commitments |
We have operating lease agreements for office space and office equipment. The lease for the majority of our office space terminates in December 2022. Minimum future lease payments due under noncancelable operating leases with terms in excess of one year as of December 31, 2014 are as follows: 2015–$1.5 million; 2016–$1.6 million; 2017–$1.6 million; 2018–$1.7 million thereafter–$7.5 million. Total rent expense was approximately $3.2 million, $2.6 million and $1.7 million during 2014, 2013 and 2012, respectively. | |
Pursuant to the Purchase and Sale Agreement with Total E&P, we are required to fulfill security requirements related to ARO for certain properties through bonds or making payments to an escrow account or a combination. As of December 31, 2014, we were in compliance with the security amount requirement of $64.0 million. Additional security requirements are $9.0 million in 2015, $6.0 million in 2016, $4.0 million in 2017, $5.0 million in 2018 and $15.0 million in the 2019 to 2023 time period to a total security requirement of $103.0 million by 2023. | |
Pursuant to the Purchase and Sale agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal in the 2015. The current security requirement of $74.0 million could be increased up to $94.0 million depending on certain conditions and circumstances. | |
We have bonding requirements related to properties owned by our subsidiary, W & T Energy VI, LLC, which require bonds in compliance with requirements set by the Bureau of Ocean Energy Management (“BOEM”). These bonds are required as long as W & T Energy VI, LLC owns the properties, including completion of plugging and abandonment activities. | |
Total expenses related to bonds, inclusive of the bonds in connection with Total E&P and Shell described above, were $4.1 million, $5.0 million and $2.9 million during 2014, 2013 and 2012, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future expenses related to bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2030. Future costs are estimated as follows: 2015–$5.8 million; 2016–$5.8 million; 2017–$5.4 million; 2018–$5.2 million; thereafter–$32.9 million. | |
Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments to have access to certain equipment to respond to a subsea spill should a spill occur at a property we operate. As of December 31, 2014, future payments due are $2.1 million in 2015 and $2.1 million in 2016. These payments may increase or decrease depending on whether the number of companies participating in the consortium changes. | |
We have no drilling rig commitments with a term that exceeded one year as of December 31, 2014 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2014 were $12.6 million. |
Related_Parties
Related Parties | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Related Parties | 17. Related Parties |
During 2014, 2013 and 2012, there were certain transactions between us and other companies our majority shareholder either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our majority shareholder. Our majority shareholder owns an aircraft that the Company used and reimbursed him for such use and for his use. Airplane services were charged to us at rates that were either equal to or below rates charged by non-related, third-party companies. Airplane services transactions were approximately $0.9 million, $1.2 million and $1.0 million for the years 2014, 2013 and 2012, respectively. Our majority shareholder has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed. W&T hired the services of a directional drilling services company, in which our majority shareholder owns a minority ownership interest and serves on its board of directors, and W&T paid $0.2 million, $0.2 million and $0.7 million for drilling related services during 2014, 2013 and 2012, respectively. A company that provides marine transportation and logistics services to W&T employs the spouse of our majority shareholder. The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2014, 2013 and 2012. All these transactions were determined to be priced at competitive rates and were reviewed by the Audit Committee for compliance with our policies and procedures. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments And Contingencies Disclosure [Abstract] | |
Contingencies | 18. Contingencies |
Notification by ONRR of Fine for Non-compliance | |
In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment. In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment. We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment. On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the notice. We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years. As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance. However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter. | |
Apache Lawsuit | |
On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement (“JOA”) related to deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. That lawsuit, styled Apache Corporation v. W&T Offshore, Inc., is currently pending in the United States District Court for the Southern District of Texas. Apache contends that W&T has failed to pay its proportional share of the costs associated with plugging and abandoning three wells that are subject to the JOA. We contend that the costs incurred by Apache are excessive and unreasonable. Apache seeks an award of unspecified actual damages, interest, court costs, and attorneys’ fees. In February 2015, we made a payment to Apache for our net share of the amounts that we believe are reasonable to plug and abandon the three wells, all of which was originally recorded as an asset retirement obligation and was accrued on our balance sheet as of December 31, 2014. Our estimate of the potential exposure ranges from zero to $32 million related to this matter. | |
Insurance Claims | |
During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (“Excess Policies”) (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company, National Liability & Fire Insurance Company (“Starr Marine”) and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas (the “District Court”) seeking a determination that our Excess Policies do not cover removal-of-wreck and debris claims arising from Hurricane Ike except to the extent we have first exhausted the limits of our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm coverage) with only removal-of-wreck and debris claims. The court consolidated the various suits filed by the underwriters. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such Excess Policies do not require us to exhaust the limits of our Energy Package policies with only removal-of-wreck and debris claims. In July 2013, the District Court ruled in favor of the underwriters, adopting their position that the Excess Policies cover removal-of-wreck and debris claims only to the extent the limits of our Energy Package policies have been exhausted with removal-of-wreck and debris claims. We appealed the decision in the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and, in June 2014, the Fifth Circuit reversed the District Court’s ruling and ruled in our favor. The underwriters filed three separate briefs requesting a rehearing or a certification to the Texas Supreme Court, all of which the Court denied. A brief was subsequently filed by one underwriter requesting a rehearing to the District Court of the Fifth Circuit’s decision, which the District Court denied. Claims of approximately $43 million were filed, of which approximately $1 million was paid under the Energy Package and of which approximately $1 million was paid under our Comprehensive General Liability policy. One of the underwriters, Liberty Mutual Insurance Co., has paid their portion of the first excess liability policy (approximately $5 million), including interest, although the commencement date of the interest calculation is under discussion. The other underwriters have not paid in accordance with the Fifth Circuit ruling, and we filed a lawsuit in September 2014 against these underwriters for amounts owed, interest, attorney fees and damages. Subsequent to the filing of that lawsuit, Starr Marine has paid their portion ($5 million) of the first excess liability policy without interest. The revised estimate of potential reimbursement is approximately $31 million, plus interest, attorney fees and damages, if any. Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Consolidated Balance Sheets and recoveries from claims made on these Excess Policies will be recorded as reductions in this line item, which will reduce our future DD&A rate. | |
Royalties | |
In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Board of Land Appeals (the “BLA”) under the Department of the Interior. W&T’s brief was filed in November 2014 and we expect the briefing before BLA to be completed in the first half of 2015. | |
Other Claims | |
We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity. | |
Contingent Liability Recorded | |
We recognized expenses related to accrued and settled claims, complaints and fines of $0.4 million, $0.5 million and $9.3 million for the years 2014, 2013 and 2012, respectively. These expenses are reported within Operating costs and expenses on the statements of operations and reflect the items noted above and other various claims, complaints and fines. As of December 31, 2014 and 2013, we have recorded a liability of $0.1 million and $0.2 million, respectively, which is included in Accrued liabilities on the Consolidated Balance Sheets, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business. |
Selected_Quarterly_Financial_D
Selected Quarterly Financial Data | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Selected Quarterly Financial Data | 19. Selected Quarterly Financial Data—UNAUDITED | |||||||||||||||
Unaudited quarterly financial data are as follows (in thousands, except per share amounts): | ||||||||||||||||
1st | 2nd | 3rd | 4th | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||
Revenues | $ | 254,516 | $ | 262,994 | $ | 234,521 | $ | 196,677 | ||||||||
Operating income (loss) | 37,225 | 34,403 | 20,983 | (30,543 | ) | |||||||||||
Net income (loss) | 11,189 | 9,837 | 684 | (33,371 | ) | |||||||||||
Basic and diluted earnings (loss) per common share (1) | 0.15 | 0.13 | 0.01 | (0.44 | ) | |||||||||||
Year Ended December 31, 2013 (2) | ||||||||||||||||
Revenues | $ | 259,222 | $ | 235,383 | $ | 244,555 | $ | 244,928 | ||||||||
Operating income | 60,321 | 53,823 | 31,965 | 622 | ||||||||||||
Net income (loss) | 26,618 | 22,396 | 14,194 | (11,886 | ) | |||||||||||
Basic and diluted earnings (loss) per common share (1) | 0.35 | 0.29 | 0.19 | (0.16 | ) | |||||||||||
-1 | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | |||||||||||||||
-2 | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe). The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense. We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. | |||||||||||||||
The fourth quarter of 2013 reflects a one-time increase in natural gas production volumes of 2.6 Bcf (with no corresponding increase in revenue) by using the correct conversion factor for the annual periods of 2011 and 2012, and the first three quarters of 2013, which increased DD&A by $7.1 million and decreased net income by $4.6 million. | ||||||||||||||||
Supplemental_Guarantor_Informa
Supplemental Guarantor Information | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Supplemental Guarantor Information [Abstract] | ||||||||||||||||
Supplemental Guarantor Information | W&T OFFSHORE, INC. AND SUBSIDIARIES | |||||||||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | ||||||||||||||||
20. Supplemental Guarantor Information | ||||||||||||||||
Our payment obligations under the 8.50% Senior Notes and the Credit Agreement (see Note 7) are fully and unconditionally guaranteed by our 100%-owned subsidiaries, W & T Energy VI, LLC and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or contain any assets. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including: | ||||||||||||||||
-1 | in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as such term is defined in the indenture governing the 8.50% Senior Notes) of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture; | |||||||||||||||
-2 | in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition; | |||||||||||||||
-3 | if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; | |||||||||||||||
-4 | upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the indenture) or upon satisfaction and discharge of the indenture; | |||||||||||||||
-5 | upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or | |||||||||||||||
-6 | at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary of the 8.50% Senior Notes as described in the indenture, provided no event of default has occurred and is continuing. | |||||||||||||||
The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Transfers of property, including related ARO and deferred income tax liabilities, were made from the Parent Company to the Guarantor Subsidiaries to assist the Parent Company to continue to qualify for a waiver of certain supplemental bonding requirements from the BOEM. As these transfers were transactions between entities under common control, the prior period financial information has been retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance. The condensed consolidating financial information for current and prior periods was adjusted as if all transfers occurred at the beginning of the period presented. None of the above adjustments had any effect on the consolidated results for the current or prior periods presented. | ||||||||||||||||
Condensed Consolidating Balance Sheet as of December 31, 2014 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 23,666 | $ | — | $ | — | $ | 23,666 | ||||||||
Receivables: | ||||||||||||||||
Oil and natural gas sales | 41,820 | 25,422 | — | 67,242 | ||||||||||||
Joint interest and other | 142,885 | — | (99,240 | ) | 43,645 | |||||||||||
Total receivables | 184,705 | 25,422 | (99,240 | ) | 110,887 | |||||||||||
Deferred income taxes | 9,797 | 1,865 | — | 11,662 | ||||||||||||
Prepaid expenses and other assets | 28,728 | 7,619 | — | 36,347 | ||||||||||||
Total current assets | 246,896 | 34,906 | (99,240 | ) | 182,562 | |||||||||||
Property and equipment – at cost: | ||||||||||||||||
Oil and natural gas properties and equipment | 6,038,915 | 2,006,751 | — | 8,045,666 | ||||||||||||
Furniture, fixtures and other | 23,269 | — | — | 23,269 | ||||||||||||
Total property and equipment | 6,062,184 | 2,006,751 | — | 8,068,935 | ||||||||||||
Less accumulated depreciation, depletion and amortization | 4,442,899 | 1,132,179 | — | 5,575,078 | ||||||||||||
Net property and equipment | 1,619,285 | 874,572 | — | 2,493,857 | ||||||||||||
Restricted deposits for asset retirement obligations | 15,444 | — | — | 15,444 | ||||||||||||
Other assets | 974,049 | 349,912 | (1,306,717 | ) | 17,244 | |||||||||||
Total assets | $ | 2,855,674 | $ | 1,259,390 | $ | (1,405,957 | ) | $ | 2,709,107 | |||||||
Liabilities and Shareholders’ Equity | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 188,654 | $ | 5,455 | $ | — | $ | 194,109 | ||||||||
Undistributed oil and natural gas proceeds | 36,130 | 879 | — | 37,009 | ||||||||||||
Asset retirement obligations | 30,711 | 5,292 | — | 36,003 | ||||||||||||
Accrued liabilities | 17,437 | 99,180 | (99,240 | ) | 17,377 | |||||||||||
Total current liabilities | 272,932 | 110,806 | (99,240 | ) | 284,498 | |||||||||||
Long-term debt, less current maturities | 1,360,057 | — | — | 1,360,057 | ||||||||||||
Asset retirement obligations, less current portion | 235,876 | 118,689 | — | 354,565 | ||||||||||||
Deferred income taxes | 59,616 | 127,372 | — | 186,988 | ||||||||||||
Other liabilities | 417,885 | — | (404,194 | ) | 13,691 | |||||||||||
Shareholders’ equity: | ||||||||||||||||
Common stock | 1 | — | — | 1 | ||||||||||||
Additional paid-in capital | 414,580 | 703,440 | (703,440 | ) | 414,580 | |||||||||||
Retained earnings | 118,894 | 199,083 | (199,083 | ) | 118,894 | |||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | ||||||||||
Total shareholders’ equity | 509,308 | 902,523 | (902,523 | ) | 509,308 | |||||||||||
Total liabilities and shareholders’ equity | $ | 2,855,674 | $ | 1,259,390 | $ | (1,405,957 | ) | $ | 2,709,107 | |||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 15,800 | $ | — | $ | — | $ | 15,800 | ||||||||
Receivables: | ||||||||||||||||
Oil and natural gas sales | 61,373 | 35,379 | — | 96,752 | ||||||||||||
Joint interest and other | 123,595 | — | (92,491 | ) | 31,104 | |||||||||||
Total receivables | 184,968 | 35,379 | (92,491 | ) | 127,856 | |||||||||||
Deferred income taxes | 584 | - | — | 584 | ||||||||||||
Prepaid expenses and other assets | 23,090 | 6,272 | — | 29,362 | ||||||||||||
Total current assets | 224,442 | 41,651 | (92,491 | ) | 173,602 | |||||||||||
Property and equipment – at cost: | ||||||||||||||||
Oil and natural gas properties and equipment | 5,667,389 | 1,671,708 | — | 7,339,097 | ||||||||||||
Furniture, fixtures and other | 21,431 | — | — | 21,431 | ||||||||||||
Total property and equipment | 5,688,820 | 1,671,708 | — | 7,360,528 | ||||||||||||
Less accumulated depreciation, depletion and amortization | 4,166,359 | 918,345 | — | 5,084,704 | ||||||||||||
Net property and equipment | 1,522,461 | 753,363 | — | 2,275,824 | ||||||||||||
Restricted deposits for asset retirement obligations | 37,421 | — | — | 37,421 | ||||||||||||
Other assets | 951,203 | 479,820 | (1,410,568 | ) | 20,455 | |||||||||||
Total assets | $ | 2,735,527 | $ | 1,274,834 | $ | (1,503,059 | ) | $ | 2,507,302 | |||||||
Liabilities and Shareholders’ Equity | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 144,492 | $ | 720 | $ | — | $ | 145,212 | ||||||||
Undistributed oil and natural gas proceeds | 41,735 | 372 | — | 42,107 | ||||||||||||
Asset retirement obligations | 65,329 | 12,456 | — | 77,785 | ||||||||||||
Accrued liabilities | 28,000 | 92,491 | (92,491 | ) | 28,000 | |||||||||||
Total current liabilities | 279,556 | 106,039 | (92,491 | ) | 293,104 | |||||||||||
Long-term debt, less current maturities | 1,205,421 | — | — | 1,205,421 | ||||||||||||
Asset retirement obligations, less current portion | 189,507 | 87,130 | — | 276,637 | ||||||||||||
Deferred income taxes | 79,424 | 98,718 | — | 178,142 | ||||||||||||
Other liabilities | 441,009 | — | (427,621 | ) | 13,388 | |||||||||||
Shareholders’ equity: | ||||||||||||||||
Common stock | 1 | — | — | 1 | ||||||||||||
Additional paid-in capital | 403,564 | 784,104 | (784,104 | ) | 403,564 | |||||||||||
Retained earnings | 161,212 | 198,843 | (198,843 | ) | 161,212 | |||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | ||||||||||
Total shareholders’ equity | 540,610 | 982,947 | (982,947 | ) | 540,610 | |||||||||||
Total liabilities and shareholders’ equity | $ | 2,735,527 | $ | 1,274,834 | $ | (1,503,059 | ) | $ | 2,507,302 | |||||||
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2014 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 592,460 | $ | 356,248 | $ | — | $ | 948,708 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 179,344 | 85,407 | — | 264,751 | ||||||||||||
Production taxes | 7,932 | — | — | 7,932 | ||||||||||||
Gathering and transportation | 11,712 | 8,109 | — | 19,821 | ||||||||||||
Depreciation, depletion, amortization and accretion | 276,636 | 213,833 | — | 490,469 | ||||||||||||
Asset retirement obligations accretion | 10,981 | 9,652 | — | 20,633 | ||||||||||||
General and administrative expenses | 48,084 | 38,915 | — | 86,999 | ||||||||||||
Derivative gain | (3,965 | ) | — | — | (3,965 | ) | ||||||||||
Total costs and expenses | 530,724 | 355,916 | — | 886,640 | ||||||||||||
Operating income | 61,736 | 332 | — | 62,068 | ||||||||||||
Earnings of affiliates | 240 | — | (240 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 84,460 | 2,462 | — | 86,922 | ||||||||||||
Capitalized | (6,064 | ) | (2,462 | ) | — | (8,526 | ) | |||||||||
Other income, net | 208 | — | — | 208 | ||||||||||||
Income (loss) before income tax expense (benefit) | (16,212 | ) | 332 | (240 | ) | (16,120 | ) | |||||||||
Income tax expense (benefit) | (4,551 | ) | 92 | — | (4,459 | ) | ||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 240 | $ | (240 | ) | $ | (11,661 | ) | |||||
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 631,267 | $ | 352,821 | $ | — | $ | 984,088 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 202,096 | 68,743 | — | 270,839 | ||||||||||||
Production taxes | 7,135 | — | — | 7,135 | ||||||||||||
Gathering and transportation | 9,248 | 8,262 | — | 17,510 | ||||||||||||
Depreciation, depletion, amortization and accretion | 236,600 | 194,011 | — | 430,611 | ||||||||||||
Asset retirement obligations accretion | 14,218 | 6,700 | 20,918 | |||||||||||||
General and administrative expenses | 44,040 | 37,834 | — | 81,874 | ||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | ||||||||||||
Total costs and expenses | 521,807 | 315,550 | — | 837,357 | ||||||||||||
Operating income | 109,460 | 37,271 | — | 146,731 | ||||||||||||
Earnings of affiliates | 24,400 | — | (24,400 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 82,570 | 3,069 | — | 85,639 | ||||||||||||
Capitalized | (6,989 | ) | (3,069 | ) | — | (10,058 | ) | |||||||||
Other income, net | 8,946 | — | — | 8,946 | ||||||||||||
Income before income tax expense | 67,225 | 37,271 | (24,400 | ) | 80,096 | |||||||||||
Income tax expense | 15,903 | 12,871 | — | 28,774 | ||||||||||||
Net income | $ | 51,322 | $ | 24,400 | $ | (24,400 | ) | $ | 51,322 | |||||||
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2012 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 539,958 | $ | 334,533 | $ | — | $ | 874,491 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 168,033 | 64,227 | — | 232,260 | ||||||||||||
Production taxes | 5,840 | — | — | 5,840 | ||||||||||||
Gathering and transportation | 10,197 | 4,681 | — | 14,878 | ||||||||||||
Depreciation, depletion, amortization and accretion | 187,039 | 149,138 | — | 336,177 | ||||||||||||
Asset retirement obligations accretion | 14,979 | 5,076 | 20,055 | |||||||||||||
General and administrative expenses | 45,260 | 36,757 | — | 82,017 | ||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | ||||||||||||
Total costs and expenses | 445,302 | 259,879 | — | 705,181 | ||||||||||||
Operating income | 94,656 | 74,654 | — | 169,310 | ||||||||||||
Earnings of affiliates | 49,799 | — | (49,799 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 60,778 | 2,490 | — | 63,268 | ||||||||||||
Capitalized | (10,784 | ) | (2,490 | ) | — | (13,274 | ) | |||||||||
Other income, net | 215 | — | — | 215 | ||||||||||||
Income before income tax expense | 94,676 | 74,654 | (49,799 | ) | 119,531 | |||||||||||
Income tax expense | 22,692 | 24,855 | — | 47,547 | ||||||||||||
Net income | $ | 71,984 | $ | 49,799 | $ | (49,799 | ) | $ | 71,984 | |||||||
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2014 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 240 | $ | (240 | ) | $ | (11,661 | ) | |||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 287,617 | 223,485 | — | 511,102 | ||||||||||||
Amortization of debt issuance costs and premium | 701 | — | — | 701 | ||||||||||||
Share-based compensation | 14,744 | — | — | 14,744 | ||||||||||||
Derivative gain | (3,965 | ) | — | — | (3,965 | ) | ||||||||||
Cash payments on derivative settlements, net | (5,318 | ) | — | — | (5,318 | ) | ||||||||||
Deferred income taxes | (32,456 | ) | 27,696 | — | (4,760 | ) | ||||||||||
Earnings of affiliates | (240 | ) | — | 240 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | 19,553 | 9,957 | — | 29,510 | ||||||||||||
Joint interest and other receivables | (4,255 | ) | — | — | (4,255 | ) | ||||||||||
Income taxes | 30,747 | (27,604 | ) | — | 3,143 | |||||||||||
Prepaid expenses and other assets | 25,555 | 12,882 | (23,425 | ) | 15,012 | |||||||||||
Asset retirement obligation settlements | (57,253 | ) | (17,060 | ) | — | (74,313 | ) | |||||||||
Accounts payable, accrued liabilities and other | 12,816 | 5,242 | 23,425 | 41,483 | ||||||||||||
Net cash provided by operating activities | 276,585 | 234,838 | — | 511,423 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (17,407 | ) | (54,827 | ) | — | (72,234 | ) | |||||||||
Investment in oil and natural gas properties and equipment | (312,044 | ) | (242,334 | ) | — | (554,378 | ) | |||||||||
Investment in subsidiary | (62,323 | ) | — | 62,323 | — | |||||||||||
Purchases of furniture, fixtures and other | (3,340 | ) | — | — | (3,340 | ) | ||||||||||
Net cash used in investing activities | (395,114 | ) | (297,161 | ) | 62,323 | (629,952 | ) | |||||||||
Financing activities: | ||||||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 556,000 | — | — | 556,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (399,000 | ) | — | — | (399,000 | ) | ||||||||||
Dividends to shareholders | (30,260 | ) | — | — | (30,260 | ) | ||||||||||
Other | (345 | ) | — | — | (345 | ) | ||||||||||
Investment from parent | — | 62,323 | (62,323 | ) | — | |||||||||||
Net cash provided in financing activities | 126,395 | 62,323 | (62,323 | ) | 126,395 | |||||||||||
Increase in cash and cash equivalents | 7,866 | — | — | 7,866 | ||||||||||||
Cash and cash equivalents, beginning of period | 15,800 | — | — | 15,800 | ||||||||||||
Cash and cash equivalents, end of period | $ | 23,666 | $ | — | $ | — | $ | 23,666 | ||||||||
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 51,322 | $ | 24,400 | $ | (24,400 | ) | $ | 51,322 | |||||||
Adjustments to reconcile net income to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 250,818 | 200,711 | — | 451,529 | ||||||||||||
Amortization of debt issuance costs and premium | 1,645 | — | — | 1,645 | ||||||||||||
Share-based compensation | 11,525 | — | — | 11,525 | ||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | ||||||||||||
Cash payments on derivative settlements | (8,589 | ) | — | — | (8,589 | ) | ||||||||||
Deferred income taxes | 7,564 | 23,356 | — | 30,920 | ||||||||||||
Earnings of affiliates | (24,400 | ) | — | 24,400 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | 6,182 | (5,202 | ) | — | 980 | |||||||||||
Joint interest and other receivables | 34,257 | — | — | 34,257 | ||||||||||||
Income taxes | 54,813 | (10,485 | ) | — | 44,328 | |||||||||||
Prepaid expenses and other assets | (25,329 | ) | (18,835 | ) | 34,120 | (10,044 | ) | |||||||||
Asset retirement obligations | (65,438 | ) | (16,105 | ) | — | (81,543 | ) | |||||||||
Accounts payable, accrued liabilities and other | 59,961 | 717 | (34,120 | ) | 26,558 | |||||||||||
Net cash provided by operating activities | 362,801 | 198,557 | — | 561,358 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | — | (82,424 | ) | — | (82,424 | ) | ||||||||||
Investment in oil and natural gas properties and equipment | (349,804 | ) | (202,150 | ) | — | (551,954 | ) | |||||||||
Investment in subsidiary | (86,017 | ) | — | 86,017 | — | |||||||||||
Proceeds from sales of assets and other, net | 21,008 | — | — | 21,008 | ||||||||||||
Purchases of furniture, fixtures and other | (1,435 | ) | — | — | (1,435 | ) | ||||||||||
Net cash used in investing activities | (416,248 | ) | (284,574 | ) | 86,017 | (614,805 | ) | |||||||||
Financing activities: | ||||||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 563,000 | — | — | 563,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (443,000 | ) | — | — | (443,000 | ) | ||||||||||
Debt issuance costs | (3,892 | ) | — | — | (3,892 | ) | ||||||||||
Dividends to shareholders | (58,846 | ) | — | — | (58,846 | ) | ||||||||||
Investment from parent | — | 86,017 | (86,017 | ) | — | |||||||||||
Other | (260 | ) | — | — | (260 | ) | ||||||||||
Net cash used in financing activities | 57,002 | 86,017 | (86,017 | ) | 57,002 | |||||||||||
Increase in cash and cash equivalents | 3,555 | — | — | 3,555 | ||||||||||||
Cash and cash equivalents, beginning of period | 12,245 | — | — | 12,245 | ||||||||||||
Cash and cash equivalents, end of period | $ | 15,800 | $ | — | $ | — | $ | 15,800 | ||||||||
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2012 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 71,984 | $ | 49,799 | $ | (49,799 | ) | $ | 71,984 | |||||||
Adjustments to reconcile net income to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 202,018 | 154,214 | — | 356,232 | ||||||||||||
Amortization of debt issuance costs and premium | 2,575 | — | — | 2,575 | ||||||||||||
Share-based compensation | 12,398 | — | — | 12,398 | ||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | ||||||||||||
Cash payments on derivative settlements | (7,664 | ) | — | — | (7,664 | ) | ||||||||||
Deferred income taxes | 81,653 | 6,456 | — | 88,109 | ||||||||||||
Earnings of affiliates | (49,799 | ) | — | 49,799 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | (3,783 | ) | 4,601 | — | 818 | |||||||||||
Joint interest and other receivables | (28,823 | ) | — | — | (28,823 | ) | ||||||||||
Income taxes | (76,411 | ) | 18,400 | — | (58,011 | ) | ||||||||||
Prepaid expenses and other assets | 9,017 | (119,895 | ) | 118,318 | 7,440 | |||||||||||
Asset retirement obligations | (105,773 | ) | (7,054 | ) | — | (112,827 | ) | |||||||||
Accounts payable, accrued liabilities and other | 159,774 | (2,504 | ) | (118,318 | ) | 38,952 | ||||||||||
Net cash provided by operating activities | 281,120 | 104,017 | — | 385,137 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (151,429 | ) | (54,121 | ) | — | (205,550 | ) | |||||||||
Investment in oil and natural gas properties and equipment | (375,296 | ) | (104,017 | ) | — | (479,313 | ) | |||||||||
Investment in subsidiary | (54,121 | ) | — | 54,121 | — | |||||||||||
Proceeds from sales of assets and other, net | 30,453 | — | — | 30,453 | ||||||||||||
Purchases of furniture, fixtures and other | (3,031 | ) | — | — | (3,031 | ) | ||||||||||
Net cash used in investing activities | (553,424 | ) | (158,138 | ) | 54,121 | (657,441 | ) | |||||||||
Financing activities: | ||||||||||||||||
Issuance of 8.50% Senior Notes | 318,000 | — | — | 318,000 | ||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 732,000 | — | — | 732,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (679,000 | ) | — | — | (679,000 | ) | ||||||||||
Debt issuance costs | (8,510 | ) | — | — | (8,510 | ) | ||||||||||
Dividends to shareholders | (82,832 | ) | — | — | (82,832 | ) | ||||||||||
Investment from parent | — | 54,121 | (54,121 | ) | — | |||||||||||
Other | 379 | — | — | 379 | ||||||||||||
Net cash used in financing activities | 280,037 | 54,121 | (54,121 | ) | 280,037 | |||||||||||
Increase in cash and cash equivalents | 7,733 | — | — | 7,733 | ||||||||||||
Cash and cash equivalents, beginning of period | 4,512 | — | — | 4,512 | ||||||||||||
Cash and cash equivalents, end of period | $ | 12,245 | $ | — | $ | — | $ | 12,245 | ||||||||
Supplemental_Oil_and_Gas_Discl
Supplemental Oil and Gas Disclosures-unaudited | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Extractive Industries [Abstract] | ||||||||||||||||||||
Supplemental Oil and Gas Disclosures-unaudited | ||||||||||||||||||||
21. Supplemental Oil and Gas Disclosures—UNAUDITED | ||||||||||||||||||||
Geographic Area of Operation | ||||||||||||||||||||
All of our proved reserves are located within the United States, with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis. | ||||||||||||||||||||
Capitalized Costs | ||||||||||||||||||||
Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Net capitalized cost: | ||||||||||||||||||||
Proved oil and natural gas properties and equipment | $ | 7,924.20 | $ | 7,207.10 | $ | 6,551.50 | ||||||||||||||
Unproved oil and natural gas properties and equipment | 121.5 | 132 | 143 | |||||||||||||||||
Accumulated depreciation, depletion and amortization | (5,557.6 | ) | (5,069.2 | ) | (4,640.8 | ) | ||||||||||||||
related to oil, NGLs and natural gas activities | ||||||||||||||||||||
Net capitalized costs related to producing activities | $ | 2,488.10 | $ | 2,269.90 | $ | 2,053.70 | ||||||||||||||
Costs Not Subject To Amortization | ||||||||||||||||||||
Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2014, by the year in which the costs were incurred (in millions): | ||||||||||||||||||||
Total | 2014 | 2013 | 2012 | Prior to | ||||||||||||||||
2012 | ||||||||||||||||||||
Costs excluded by year incurred: | ||||||||||||||||||||
Acquisition costs | $ | 75.5 | $ | 2.6 | $ | 5.7 | $ | 7 | $ | 60.2 | ||||||||||
Capitalized interest not subject to amortization | 34.3 | 7.5 | 7.3 | 6.4 | 13.1 | |||||||||||||||
Total costs not subject to amortization | $ | 109.8 | $ | 10.1 | $ | 13 | $ | 13.4 | $ | 73.3 | ||||||||||
Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities | ||||||||||||||||||||
The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Costs incurred: (1) | ||||||||||||||||||||
Proved properties acquisitions | $ | 111.5 | $ | 96.9 | $ | 239.8 | ||||||||||||||
Exploration (2) (3) | 411.1 | 215.3 | 151.3 | |||||||||||||||||
Development | 198.7 | 352.9 | 363.7 | |||||||||||||||||
Unproved properties acquisitions (4) | 3.1 | 26.3 | 26.5 | |||||||||||||||||
Total costs incurred in oil and gas property acquisition, | $ | 724.4 | $ | 691.4 | $ | 781.3 | ||||||||||||||
exploration and development activities | ||||||||||||||||||||
-1 | Includes net additions from capitalized ARO of $88.0 million, $50.6 million and $86.9 million during 2014, 2013 and 2012, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. | |||||||||||||||||||
-2 | Includes seismic costs of $9.0 million, $8.9 million and $6.2 million incurred during 2014, 2013 and 2012, respectively. | |||||||||||||||||||
-3 | Includes geological and geophysical costs charged to expense of $7.3 million, $5.9 million and $6.2 million during 2014, 2013 and 2012, respectively. | |||||||||||||||||||
-4 | The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period. | |||||||||||||||||||
Depreciation, depletion, amortization and accretion expense | ||||||||||||||||||||
The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold. | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Depreciation, depletion, amortization and accretion per Boe | $ | 28.98 | $ | 25.1 | $ | 20.79 | ||||||||||||||
Oil and Natural Gas Reserve Information | ||||||||||||||||||||
There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 11% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities. | ||||||||||||||||||||
The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with 69% located in the Gulf of Mexico and the remainder located in the West Texas Permian Basin. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economically viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”. | ||||||||||||||||||||
Total Energy Equivalent Reserves (1) | ||||||||||||||||||||
Oil | NGLs | Natural Gas | Oil | Natural Gas | ||||||||||||||||
(MMBbls) | (MMBbls) | (Bcf) | Equivalent | Equivalent | ||||||||||||||||
(MMBoe) | (Bcfe) | |||||||||||||||||||
Proved reserves as of Dec. 31, 2011 | 51.4 | 17.1 | 289.7 | 116.9 | 701.1 | |||||||||||||||
Revisions of previous estimates (2) | (1.1 | ) | (2.6 | ) | (4.8 | ) | (4.6 | ) | (27.5 | ) | ||||||||||
Extensions and discoveries (3) | 8.2 | 2.6 | 29.6 | 15.7 | 94.5 | |||||||||||||||
Purchase of minerals in place (4) | 2.5 | 0.2 | 25.5 | 7 | 42 | |||||||||||||||
Sales of reserves (5) | (0.2 | ) | — | (1.1 | ) | (0.4 | ) | (2.2 | ) | |||||||||||
Production | (6.0 | ) | (2.1 | ) | (53.8 | ) | (17.1 | ) | (102.8 | ) | ||||||||||
Proved reserves as of Dec. 31, 2012 | 54.8 | 15.2 | 285.1 | 117.5 | 705.1 | |||||||||||||||
Revisions of previous estimates (6) | (4.3 | ) | 0.2 | 2.1 | (3.8 | ) | (22.8 | ) | ||||||||||||
Extensions and discoveries (7) | 13.9 | 2.6 | 22 | 20.2 | 121 | |||||||||||||||
Purchase of minerals in place (8) | 1.5 | — | 4.4 | 2.3 | 13.7 | |||||||||||||||
Sales of reserves (9) | (0.4 | ) | — | (0.4 | ) | (0.5 | ) | (3.2 | ) | |||||||||||
Production | (7.0 | ) | (2.1 | ) | (53.3 | ) | (18.0 | ) | (107.9 | ) | ||||||||||
Proved reserves as of Dec. 31, 2013 | 58.5 | 15.9 | 259.9 | 117.7 | 705.9 | |||||||||||||||
Revisions of previous estimates (10) | 1.6 | 0.1 | 14.3 | 4.1 | 25.3 | |||||||||||||||
Extensions and discoveries (11) | 7.3 | 0.7 | 10.1 | 9.7 | 58.1 | |||||||||||||||
Purchase of minerals in place (12) | 1.5 | 1.2 | 20.7 | 6.1 | 36.5 | |||||||||||||||
Production | (7.2 | ) | (2.1 | ) | (50.1 | ) | (17.6 | ) | (105.8 | ) | ||||||||||
Proved reserves as of Dec. 31, 2014 | 61.7 | 15.8 | 254.9 | 120 | 720 | |||||||||||||||
Year-end proved developed reserves: | ||||||||||||||||||||
2014 | 35.7 | 10.7 | 221.1 | 83.3 | 499.7 | |||||||||||||||
2013 | 36.2 | 11.1 | 232.7 | 86.1 | 516.1 | |||||||||||||||
2012 | 35.3 | 11 | 243.5 | 86.9 | 521.2 | |||||||||||||||
Year-end proved undeveloped reserves: | ||||||||||||||||||||
2014 (13) | 26 | 5.1 | 33.8 | 36.7 | 220.3 | |||||||||||||||
2013 | 22.3 | 4.8 | 27.2 | 31.6 | 189.8 | |||||||||||||||
2012 | 19.5 | 4.2 | 41.6 | 30.6 | 183.9 | |||||||||||||||
Volume measurements: | ||||||||||||||||||||
Bbl – barrel | Mcf – thousand cubic feet | |||||||||||||||||||
MMBbls – million barrels for crude oil, condensate or NGLs | Bcf – billion cubic feet | |||||||||||||||||||
MMBoe – million barrels of oil equivalent | Bcfe – billion cubic feet of gas equivalent | |||||||||||||||||||
-1 | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. | |||||||||||||||||||
-2 | Includes downward revisions due to price of 1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field. | |||||||||||||||||||
-3 | Includes extensions and discoveries of 11.6 MMBoe at our Spraberry field and extensions and discoveries of 2.7 MMBoe at our High Island 21/22 field. | |||||||||||||||||||
-4 | Due to the acquisition of the Newfield Properties. | |||||||||||||||||||
-5 | Due to the sale of our interest in the South Timbalier 41 field. | |||||||||||||||||||
-6 | Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Spraberry field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. | |||||||||||||||||||
-7 | Includes extensions and discoveries of 12.6 MMBoe at our Spraberry field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. | |||||||||||||||||||
-8 | Primarily due to the acquisition of the Callon Properties. | |||||||||||||||||||
-9 | Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. | |||||||||||||||||||
-10 | Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Spraberry field and 2.4 MMBoe at various other fields. | |||||||||||||||||||
-11 | Includes extensions and discoveries of 4.1 MMBoe at our Spraberry field and 4.1 MMBoe at our Mississippi Canyon 782 field. | |||||||||||||||||||
-12 | Primarily due to acquiring additional ownership in the Fairway field and acquisition of the Woodside Properties. | |||||||||||||||||||
-13 | We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. These PUDs were originally recorded in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020. | |||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | ||||||||||||||||||||
The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio is applied to the oil price using FASB/SEC guidance. The average commodity prices weighted by field production related to the proved reserves are as follows: | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | |||||||||||||||||
Oil - per barrel | $ | 91.12 | $ | 99.65 | $ | 98.13 | $ | 97.36 | ||||||||||||
NGLs per barrel | 34.63 | 35.21 | 47.3 | 51.3 | ||||||||||||||||
Natural gas - per Mcf | 4.27 | 3.8 | 2.77 | 4.11 | ||||||||||||||||
Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate. | ||||||||||||||||||||
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2014 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | ||||||||||||||||||||
Future cash inflows | $ | 7,258.50 | $ | 7,376.70 | $ | 6,888.40 | ||||||||||||||
Future costs: | ||||||||||||||||||||
Production | (2,224.5 | ) | (2,142.8 | ) | (1,858.3 | ) | ||||||||||||||
Development | (922.0 | ) | (1,001.4 | ) | (655.4 | ) | ||||||||||||||
Dismantlement and abandonment | (475.4 | ) | (441.6 | ) | (508.0 | ) | ||||||||||||||
Income taxes | (948.4 | ) | (986.9 | ) | (1,002.1 | ) | ||||||||||||||
Future net cash inflows before 10% discount | 2,688.20 | 2,804.00 | 2,864.60 | |||||||||||||||||
10% annual discount factor | (985.4 | ) | (1,129.4 | ) | (1,018.2 | ) | ||||||||||||||
Total | $ | 1,702.80 | $ | 1,674.60 | $ | 1,846.40 | ||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Changes in Standardized Measure | ||||||||||||||||||||
Standardized measure, beginning of year | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | ||||||||||||||
Increases (decreases): | ||||||||||||||||||||
Sales and transfers of oil and gas produced, net of production | (650.9 | ) | (686.1 | ) | (620.4 | ) | ||||||||||||||
costs | ||||||||||||||||||||
Net changes in price, net of future production costs | (278.6 | ) | (65.2 | ) | (224.3 | ) | ||||||||||||||
Extensions and discoveries, net of future production and | 309.6 | 393.8 | 181.9 | |||||||||||||||||
development costs | ||||||||||||||||||||
Changes in estimated future development costs | (56.4 | ) | (91.1 | ) | (103.3 | ) | ||||||||||||||
Previously estimated development costs incurred | 263.1 | 262.1 | 332.9 | |||||||||||||||||
Revisions of quantity estimates | 118.6 | (91.6 | ) | (128.1 | ) | |||||||||||||||
Accretion of discount | 180.6 | 202.2 | 231.1 | |||||||||||||||||
Net change in income taxes | (11.4 | ) | 56.6 | 99.7 | ||||||||||||||||
Purchases of reserves in-place | 86.7 | 79.6 | 270.2 | |||||||||||||||||
Sales of reserves in-place | — | (53.1 | ) | (16.1 | ) | |||||||||||||||
Changes in production rates due to timing and other | 66.9 | (179.0 | ) | (183.6 | ) | |||||||||||||||
Net increase (decrease) in standardized measure | 28.2 | (171.8 | ) | (160.0 | ) | |||||||||||||||
Standardized measure, end of year | $ | 1,702.80 | $ | 1,674.60 | $ | 1,846.40 | ||||||||||||||
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Operations | Operations | |||||||||||
W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,”, “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-own subsidiary, W & T Energy VI, LLC (“Energy VI”). | ||||||||||||
Basis of Presentation | Basis of Presentation | |||||||||||
Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. | ||||||||||||
Reclassifications | Reclassifications | |||||||||||
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows: Income tax – receivables was combined with Joint interest and other – receivables on the Consolidated Balance Sheets. Loss on extinguishment of debt was combined with Other income, net on the Consolidated Statements of Operations. Insurance proceeds was combined with the changes in Joint interest and other receivables and changes in Other – operating assets and liabilities was combined with the changes in Accounts payable, accrued liabilities and other on the Consolidated Statements of Cash Flows. | ||||||||||||
Use of Estimates | Use of Estimates | |||||||||||
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. | ||||||||||||
Recent Events | Recent Events | |||||||||||
The price we receive for our oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth. The prices of these commodities began falling in June 2014 and were significantly lower in January and February of 2015 compared to the last few years. | ||||||||||||
We have taken several steps to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budget from the previous year; (ii) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend and (iv) implementing numerous cost reduction projects to reduce our operating costs. | ||||||||||||
Assuming continuing oil and gas prices are near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain of our financial ratio maintenance covenants under our Credit Agreement sometime during 2015. We intend to engage the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is redetermined in April 2015, but we can provide no assurance that we will be successful in obtaining such an amendment. While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing, and we may have to reduce our cash outlays further for capital expenditures and other activities until such time as market conditions recover. | ||||||||||||
We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2015; however, we cannot predict how an extended period of low commodity prices will affect our operations and liquidity levels. | ||||||||||||
Adjustment Related to Additional Volumes | Adjustment Related to Additional Volumes | |||||||||||
In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe). The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. The effect of using this incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense. We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in 2013. The 2013 period reflects a one-time increase in natural gas production volumes of 1.9 billion cubic feet (“Bcf”) (with no corresponding increase in revenue) for the annual periods of 2011 and 2012, which increased depreciation, depletion, amortization and accretion (“DD&A”) by $5.0 million and decreased net income by $3.2 million. | ||||||||||||
Cash Equivalents | Cash Equivalents | |||||||||||
We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. | ||||||||||||
Revenue Recognition | Revenue Recognition | |||||||||||
We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company has taken less than its ownership share of production. At both December 31, 2014 and 2013, $6.4 million was included in current liabilities related to natural gas imbalances. | ||||||||||||
Concentration of Credit Risk | Concentration of Credit Risk | |||||||||||
Our customers are primarily large integrated oil and natural gas companies and large financial institutions. Our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables except in rare circumstances. Accordingly, we do not maintain an allowance for doubtful accounts of any material amounts. | ||||||||||||
The following identifies customers from whom we derived 10% or more of receipts from sales of oil, NGLs and natural gas. | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Customer | ||||||||||||
Shell Trading (US) Co. | 47 | % | 48 | % | 35 | % | ||||||
ConocoPhillips (1) | ** | ** | 16 | % | ||||||||
** | less than 10% | |||||||||||
· | ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. | |||||||||||
We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. | ||||||||||||
Insurance Receivables | Insurance Receivables | |||||||||||
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 18 for information related to unpaid claims by certain underwriters. | ||||||||||||
Properties and Equipment | Properties and Equipment | |||||||||||
We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. | ||||||||||||
Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. | ||||||||||||
We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets. | ||||||||||||
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. | ||||||||||||
Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. | ||||||||||||
Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO), net of related deferred income taxes, exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is comprised of: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related tax effects. Estimated future net revenues used in the ceiling test for each year are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for that year. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. | ||||||||||||
Declines in the unweighted rolling average of first-day-of-the-month commodity prices in oil and natural gas prices after December 31, 2014 may require us to record ceiling-test impairments in the future. We did not have any write-downs related to ceiling-test impairments during 2014, 2013 and 2012, respectively. | ||||||||||||
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. | ||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations | |||||||||||
Pursuant to GAAP, we are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5. | ||||||||||||
Oil and Natural Gas Reserve Information | Oil and Natural Gas Reserve Information | |||||||||||
Pursuant to GAAP, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Another provision of the guidance is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years. Refer to Note 21 for additional information about our proved reserves. | ||||||||||||
Derivative Financial Instruments | Derivative Financial Instruments | |||||||||||
Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. Our derivative instruments currently consist of commodity swap contracts for oil. We do not enter into derivative instruments for speculative trading purposes. | ||||||||||||
In accordance with GAAP, a derivative is recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. We have elected not to designate our commodity derivatives as hedging instruments, therefore all changes in fair value are recognized in earnings. | ||||||||||||
Fair Value of Financial Instruments | Fair Value of Financial Instruments | |||||||||||
We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe the carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates. | ||||||||||||
Fair Value of Acquisitions | Fair Value of Acquisitions | |||||||||||
Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions are determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made. No goodwill was recorded for the acquisitions completed in 2014, 2013 or 2012. | ||||||||||||
Income Taxes | Income Taxes | |||||||||||
We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. 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. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. | ||||||||||||
Debt Issuance Costs | Debt Issuance Costs | |||||||||||
Debt issuance costs associated with our revolving loan facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. | ||||||||||||
Premiums Received on Debt Issuance | Premiums Received on Debt Issuance | |||||||||||
Premiums are recorded in long-term liabilities and are amortized over the term of the related debt using the effective interest method. | ||||||||||||
Share-Based Compensation | Share-Based Compensation | |||||||||||
In accordance with GAAP, compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for more information. | ||||||||||||
Earnings Per Share | Earnings Per Share | |||||||||||
In accordance with GAAP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two-class method. For additional information, refer to Note 14. | ||||||||||||
Other Income, Net | Other Income, Net | |||||||||||
For 2013, the amount reported consisted primarily of $9.2 million received in conjunction with a payment for an option exercised by a counterparty. Partially offsetting the proceeds were related third-party expenses of $0.1 million. The net amount was included in net cash flows from investing activities within the line, Proceeds from sales of assets and other, net in the consolidated statements of cash flows. | ||||||||||||
Recent Accounting Developments | Recent Accounting Developments | |||||||||||
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Topic 606). ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance. The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application. We have not determined the effect ASU 2014-09 will have on the recognition of our revenue, if any, nor have we determined the method we will utilize upon adoption, which would be in the first quarter of 2017. | ||||||||||||
In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. We do not expect the revised guidance to materially affect our evaluation as to being a going concern, or have an effect on our financial statements or related disclosures. |
Significant_Accounting_Policie2
Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Percentage of Revenue by Major Customers | The following identifies customers from whom we derived 10% or more of receipts from sales of oil, NGLs and natural gas. | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Customer | ||||||||||||
Shell Trading (US) Co. | 47 | % | 48 | % | 35 | % | ||||||
ConocoPhillips (1) | ** | ** | 16 | % | ||||||||
** | less than 10% | |||||||||||
· | ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. |
Acquisitions_and_Divestitures_
Acquisitions and Divestitures (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Fairway | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase Price Allocation for Acquisition | The following table presents the preliminary purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands): | ||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 17,407 | |||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - non-current | 6,124 | ||||||||
Total consideration | $ | 23,531 | |||||||
Woodside Properties | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase Price Allocation for Acquisition | The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands): | ||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 52,167 | |||||||
Unevaluated properties | 2,660 | ||||||||
Sub-total cash consideration | 54,827 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - current | 782 | ||||||||
Asset retirement obligations - non-current | 10,543 | ||||||||
Sub-total non-cash consideration | 11,325 | ||||||||
Total consideration | $ | 66,152 | |||||||
Summary of Proforma Financial Information for Acquisition | The following table presents a summary of our pro forma financial information (in thousands, except earnings per share): | ||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | ||||||||
Revenue | $ | 971,595 | $ | 1,047,037 | |||||
Net income (loss) | (5,495 | ) | 71,432 | ||||||
Basic and diluted earnings (loss) per common share | (0.08 | ) | 0.94 | ||||||
Business Acquisition Pro Forma Information Incremental Item | The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): | ||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2014 (a) | 2013 | ||||||||
Revenues (b) | $ | 22,887 | $ | 62,949 | |||||
Direct operating expenses (b) | 4,417 | 9,583 | |||||||
DD&A (c) | 8,374 | 20,476 | |||||||
G&A (d) | 300 | 800 | |||||||
Interest expense (e) | 329 | 987 | |||||||
Capitalized interest (f) | (19 | ) | 164 | ||||||
Income tax expense (g) | 3,320 | 10,829 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014. | ||||||||
(b) | Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside. | ||||||||
(c) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(d) | Estimated insurance costs related to the Woodside Properties. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $54.8 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(f) | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. | ||||||||
(g) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures. | |||||||||
Callon Properties | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase Price Allocation for Acquisition | The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Callon Properties (in thousands): | ||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 73,752 | |||||||
Unevaluated properties | 9,248 | ||||||||
Sub-total cash consideration | 83,000 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations - current | 90 | ||||||||
Asset retirement obligations - non-current | 4,143 | ||||||||
Sub-total non-cash consideration | 4,233 | ||||||||
Total consideration | $ | 87,233 | |||||||
Summary of Proforma Financial Information for Acquisition | The following table presents a summary of our pro forma financial information (in thousands except earnings per share): | ||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | ||||||||
Revenue | $ | 1,018,118 | $ | 923,050 | |||||
Net income | 59,015 | 85,310 | |||||||
Basic and diluted earnings per common share | 0.78 | 1.12 | |||||||
Business Acquisition Pro Forma Information Incremental Item | For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Callon Properties (in thousands): | ||||||||
(unaudited) | |||||||||
Year Ended December 31, | |||||||||
2013 (a) | 2012 | ||||||||
Revenues (b) | $ | 34,030 | $ | 48,559 | |||||
Direct operating expenses (b) | 6,405 | 8,525 | |||||||
DD&A (c) | 14,931 | 17,578 | |||||||
G&A (d) | (361 | ) | — | ||||||
Interest expense (e) | 1,383 | 1,660 | |||||||
Capitalized interest (f) | (164 | ) | 295 | ||||||
Income tax expense (g) | 4,143 | 7,175 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013. | ||||||||
(b) | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | ||||||||
(c) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(d) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(f) | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses. | ||||||||
(g) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures. | |||||||||
Newfield Properties | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase Price Allocation for Acquisition | The following table presents the purchase price allocation, including adjustments, for the acquisition of the Newfield Properties (in thousands): | ||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 192,723 | |||||||
Unevaluated properties | 13,065 | ||||||||
Sub-total cash consideration | 205,788 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligations – current | 7,250 | ||||||||
Asset retirement obligations - non-current | 24,414 | ||||||||
Sub-total non-cash consideration | 31,664 | ||||||||
Total consideration | $ | 237,452 | |||||||
Summary of Proforma Financial Information for Acquisition | The following table presents a summary of our pro forma financial information (in thousands except earnings per share): | ||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
31-Dec-12 | |||||||||
Revenue | $ | 980,196 | |||||||
Net income | 77,036 | ||||||||
Basic and diluted earnings per common share | 1.01 | ||||||||
Business Acquisition Pro Forma Information Incremental Item | For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Newfield Properties (in thousands): | ||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
December 31, 2012 (a) | |||||||||
Revenues (b) | $ | 105,705 | |||||||
Direct operating expenses (b) | 33,186 | ||||||||
Insurance costs (c) | 475 | ||||||||
DD&A (d) | 53,408 | ||||||||
G&A (e) | (553 | ) | |||||||
Interest expense (f) | 12,060 | ||||||||
Capitalized interest (g) | (643 | ) | |||||||
Income tax expense (h) | 2,720 | ||||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) The adjustments are for the period from January 1, 2012 to October 5, 2012. | |||||||||
(b) | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | ||||||||
(c) | Incremental costs for insurance were estimated from the incremental costs to add the Newfield Properties to W&T’s insurance programs. The direct operating costs for the Newfield Properties described above excluded insurance costs. | ||||||||
(d) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | ||||||||
(e) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | ||||||||
(f) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.8 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. | ||||||||
(g) | Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. | ||||||||
(h) | Income tax expense was computed using the 35% federal statutory rate. | ||||||||
The pro forma adjustments do not included adjustments related to any other acquisitions or divestitures. |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||
Reconciliation of Asset Retirement Obligations Liability | The following is a reconciliation of our ARO liability (in thousands): | |||||||
2014 | 2013 | |||||||
Asset retirement obligations, beginning of period | $ | 354,422 | $ | 384,053 | ||||
Liabilities settled | (74,313 | ) | (81,543 | ) | ||||
Accretion of discount | 20,633 | 20,918 | ||||||
Disposition of properties | — | (19,564 | ) | |||||
Liabilities assumed through acquisition | 21,820 | 4,233 | ||||||
Liabilities incurred | 3,258 | 1,745 | ||||||
Revisions of estimated liabilities | 64,748 | 44,580 | ||||||
Asset retirement obligations, end of period | 390,568 | 354,422 | ||||||
Less current portion | 36,003 | 77,785 | ||||||
Long-term | $ | 354,565 | $ | 276,637 | ||||
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||
Estimated Fair Value of Derivative Contracts | The following balance sheet line items included amounts related to the estimated fair value of our open derivative contracts as indicated in the following table (in thousands): | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid and other assets | $ | — | $ | 141 | ||||||||
Accrued liabilities | — | 9,423 | ||||||||||
Changes in Fair Value of Commodity Derivative Contracts Recognized in Earnings | Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows (in thousands): | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Derivative (gain) loss: | $ | (3,965 | ) | $ | 8,470 | $ | 13,954 | |||||
Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities | Cash payments on derivative settlements, net, are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands): | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash payments on derivative settlements, net | $ | 5,318 | $ | 8,589 | $ | 7,664 | ||||||
Reconciliation of Gross Assets and Liabilities and Netting Agreements on Fair Value of Open Derivative Contracts | There were no open derivative contracts as of December 31, 2014. The following table provides a reconciliation of the gross assets and liabilities reflected in the balance sheet and the potential effects of master netting agreements on the fair value of open derivative contracts as of December 31, 2013 (in thousands): | |||||||||||
31-Dec-13 | ||||||||||||
Derivative | Derivative | |||||||||||
Assets | Liabilities | |||||||||||
Gross amounts presented in the balance sheet | $ | 141 | $ | 9,423 | ||||||||
Amounts not offset in the balance sheet | (141 | ) | (141 | ) | ||||||||
Net Amounts | $ | — | $ | 9,282 | ||||||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Debt Disclosure [Abstract] | ||||||||
Long-Term Debt | As of December 31, 2014 and 2013, our long-term debt was as follows (in thousands): | |||||||
December 31, | ||||||||
2014 | 2013 | |||||||
8.50% Senior Notes | $ | 900,000 | $ | 900,000 | ||||
Debt premiums, net of amortization | 13,057 | 15,421 | ||||||
Revolving bank credit facility | 447,000 | 290,000 | ||||||
Total long-term debt | 1,360,057 | 1,205,421 | ||||||
Current maturities of long-term debt | — | — | ||||||
Long term debt, less current maturities | $ | 1,360,057 | $ | 1,205,421 | ||||
-1 | Aggregate annual maturities of long-term debt as of December 31, 2014 are as follows (in millions): 2015–$0.0; 2016–$0.0; 2017–$0.0; 2018–$447.0; thereafter–$900.0. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||
Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Senior Notes | The following table presents the fair value of our derivative financial instruments, our 8.50% Senior Notes and our revolving bank credit facility (in thousands): | |||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||
Hierarchy | Assets | Liabilities | Assets | Liabilities | ||||||||||||||
Derivatives | Level 2 | $ | — | $ | — | $ | 141 | $ | 9,423 | |||||||||
8.50% Senior Notes | Level 2 | — | 594,000 | — | 962,460 | |||||||||||||
Revolving bank credit facility | Level 2 | — | 447,000 | — | 290,000 | |||||||||||||
ShareBased_and_CashBased_Incen1
Share-Based and Cash-Based Incentive Compensation (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ||||||||||||||||||||||||
Schedule of Restricted Stock Activity | A summary of activity related to Restricted Shares is as follows: | |||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Restricted Shares | Weighted Average Grant Date Fair Value Per Share | Restricted Shares | Weighted Average Grant Date Fair Value Per Share | Restricted Shares | Weighted Average Grant Date Fair Value Per Share | |||||||||||||||||||
Nonvested, beginning of period | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | |||||||||||||||
Granted | 18,815 | 18.6 | 27,450 | 12.75 | 21,954 | 19.13 | ||||||||||||||||||
Vested | (19,445 | ) | 18 | (27,297 | ) | 17.09 | (27,475 | ) | 13.59 | |||||||||||||||
Forfeited | — | — | — | — | (2,662 | ) | 18.78 | |||||||||||||||||
Nonvested, end of period | 43,210 | $ | 16.2 | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | |||||||||||||||
Schedule of Restricted Stock Awards Outstanding | Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2014 are expected to vest as follows: | |||||||||||||||||||||||
Restricted Shares | ||||||||||||||||||||||||
2015 | 21,520 | |||||||||||||||||||||||
2016 | 15,420 | |||||||||||||||||||||||
2017 | 6,270 | |||||||||||||||||||||||
Total | 43,210 | |||||||||||||||||||||||
Summary of Share Activity Related to Restricted Stock Units | A summary of activity related to RSUs is as follows: | |||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | Restricted Stock Units | Weighted Average Grant Date Fair Value Per Share | |||||||||||||||||||
Nonvested, beginning of period | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | |||||||||||||||
Granted | 1,195,388 | 16.84 | 969,919 | 13.23 | 764,654 | 18.64 | ||||||||||||||||||
Vested | (354,692 | ) | 18.59 | (468,925 | ) | 26.93 | (1,198,208 | ) | 9.36 | |||||||||||||||
Forfeited | (195,114 | ) | 16.53 | (139,061 | ) | 16.5 | (329,329 | ) | 19.56 | |||||||||||||||
Nonvested, end of period | 1,977,335 | $ | 15.29 | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | |||||||||||||||
Schedule of Restricted Stock Units Outstanding | Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2014 are eligible to vest in the year indicated in the table below: | |||||||||||||||||||||||
Restricted Stock Units | ||||||||||||||||||||||||
2015 - subject to service requirements | 759,234 | |||||||||||||||||||||||
2015 - subject to service and other requirements (1) | 90,105 | |||||||||||||||||||||||
2016 - subject to service requirements | 1,127,996 | |||||||||||||||||||||||
Total | 1,977,335 | |||||||||||||||||||||||
-1 | In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted. | |||||||||||||||||||||||
Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit | A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): | |||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Share-based compensation expense from: | ||||||||||||||||||||||||
Restricted stock | $ | 369 | $ | 397 | $ | 399 | ||||||||||||||||||
Restricted stock units | 13,150 | 11,128 | 11,999 | |||||||||||||||||||||
Common shares | 1,225 | — | — | |||||||||||||||||||||
Total | $ | 14,744 | $ | 11,525 | $ | 12,398 | ||||||||||||||||||
Share-based compensation tax benefit: | ||||||||||||||||||||||||
Tax benefit computed at the statutory rate | $ | 5,160 | $ | 4,034 | $ | 4,339 | ||||||||||||||||||
Summary of Incentive Compensation Expense | A summary of incentive compensation expense is as follows (in thousands): | |||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Share-based compensation included in: | ||||||||||||||||||||||||
General and administrative (1) | $ | 14,744 | $ | 11,525 | $ | 12,398 | ||||||||||||||||||
Cash-based incentive compensation included in: | ||||||||||||||||||||||||
Lease operating expense | 3,285 | 3,482 | 3,787 | |||||||||||||||||||||
General and administrative (1) | 6,950 | 8,817 | 6,558 | |||||||||||||||||||||
Total charged to operating income | $ | 24,979 | $ | 23,824 | $ | 22,743 | ||||||||||||||||||
· | Reclassified $0.7 million from cash-based incentive compensation expense to share-based compensation expense in 2014 related to the CEO’s 2013 award. |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||
Components of Income Tax Expense (Benefit) | Components of income tax expense (benefit) were as follows (in thousands): | |||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Current | $ | 301 | $ | (2,146 | ) | $ | (40,562 | ) | ||||||||||||||||
Deferred | (4,760 | ) | 30,920 | 88,109 | ||||||||||||||||||||
$ | (4,459 | ) | $ | 28,774 | $ | 47,547 | ||||||||||||||||||
Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) | The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands): | |||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Income tax expense (benefit) at the federal | $ | (5,642 | ) | 35 | % | $ | 28,033 | 35 | % | $ | 41,836 | 35 | % | |||||||||||
statutory rate | ||||||||||||||||||||||||
Qualified domestic production activities | — | — | — | — | 4,256 | 3.5 | ||||||||||||||||||
State income taxes | 263 | (1.6 | ) | 343 | 0.4 | 750 | 0.7 | |||||||||||||||||
Other | 920 | (5.7 | ) | 398 | 0.5 | 705 | 0.6 | |||||||||||||||||
$ | (4,459 | ) | 27.7 | % | $ | 28,774 | 35.9 | % | $ | 47,547 | 39.8 | % | ||||||||||||
Significant Components of Deferred Tax Assets and Liabilities | Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): | |||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Deferred tax liabilities: | ||||||||||||||||||||||||
Property and equipment | $ | 518,566 | $ | 422,805 | ||||||||||||||||||||
Other | 5,019 | 3,602 | ||||||||||||||||||||||
Total deferred tax liabilities | 523,585 | 426,407 | ||||||||||||||||||||||
Deferred tax assets: | ||||||||||||||||||||||||
Alternative minimum tax credit | 20,486 | 20,486 | ||||||||||||||||||||||
Asset retirement obligations | 137,597 | 124,863 | ||||||||||||||||||||||
Federal net operating losses | 180,024 | 91,472 | ||||||||||||||||||||||
State net operating losses | 5,008 | 5,028 | ||||||||||||||||||||||
Derivatives | — | 3,270 | ||||||||||||||||||||||
Valuation allowance (state) | (4,255 | ) | (4,490 | ) | ||||||||||||||||||||
Accrued cash-based bonus | 3,559 | 3,873 | ||||||||||||||||||||||
Stock-based compensation | 5,042 | 3,703 | ||||||||||||||||||||||
Other | 798 | 643 | ||||||||||||||||||||||
Total deferred tax assets | 348,259 | 248,848 | ||||||||||||||||||||||
Net deferred tax liabilities | $ | 175,326 | $ | 177,559 | ||||||||||||||||||||
Net Operating Loss and Tax Credit Carryovers | The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2014 (in thousands): | |||||||||||||||||||||||
Amount | Expiration Year | |||||||||||||||||||||||
Federal net operating loss | $ | 516,393 | 2032-2034 | |||||||||||||||||||||
State net operating losses | 99,656 | 2021-2029 | ||||||||||||||||||||||
Alternative minimum tax credit | 12,091 | Indefinite | ||||||||||||||||||||||
General business credit | 406 | 2027-2028 | ||||||||||||||||||||||
Balances and Changes in Uncertain Tax Positions | Balances and changes in the uncertain tax positions are as follows (in thousands): | |||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Balance, beginning of period | $ | 9,482 | $ | — | ||||||||||||||||||||
Increases related to carryback positions | — | 9,482 | ||||||||||||||||||||||
Balance, end of period | $ | 9,482 | $ | 9,482 | ||||||||||||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Schedule of Calculation of Basic and Diluted Earnings Per Common Share | The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 51,322 | $ | 71,984 | |||||
Less portion allocated to nonvested shares | 269 | 303 | 983 | |||||||||
Net income (loss) allocated to common shares | $ | (11,930 | ) | $ | 51,019 | $ | 71,001 | |||||
Weighted average common shares outstanding | 75,609 | 75,239 | 74,354 | |||||||||
Basic and diluted earnings (loss) per common share | $ | (0.16 | ) | $ | 0.68 | $ | 0.95 | |||||
Shares excluded due to being anti-dilutive (weighted-average) | 29 | — | 1,923 | |||||||||
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Supplemental Cash Flow Elements [Abstract] | ||||||||||||
Supplemental Cash Flow Information | The following reflects our supplemental cash flow information (in thousands): | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash paid for interest, net of interest capitalized of $8,526 in 2014, | $ | 77,607 | $ | 73,909 | $ | 46,247 | ||||||
$10,058 in 2013 and $13,274 in 2012 | ||||||||||||
Cash paid for income taxes | — | 3,000 | 16,056 | |||||||||
Cash refunds received for income taxes | 3,000 | 59,126 | 479 | |||||||||
Cash paid for share-based compensation (1) | 431 | 466 | 1,531 | |||||||||
Cash tax benefit related to share-based compensation (2) | — | — | 5,962 | |||||||||
-1 | The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements. | |||||||||||
-2 | The cash tax benefit for share-based compensation is attributable to tax deductions for vested restricted shares, vested RSUs, dividends paid on unvested restricted stock and dividend equivalents paid on RSUs. For 2014 and 2013, no cash tax benefit was realized as the Company had a tax loss for that year and all carrybacks had previously been utilized. |
Selected_Quarterly_Financial_D1
Selected Quarterly Financial Data (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Quarterly Financial Data | Unaudited quarterly financial data are as follows (in thousands, except per share amounts): | |||||||||||||||
1st | 2nd | 3rd | 4th | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||
Revenues | $ | 254,516 | $ | 262,994 | $ | 234,521 | $ | 196,677 | ||||||||
Operating income (loss) | 37,225 | 34,403 | 20,983 | (30,543 | ) | |||||||||||
Net income (loss) | 11,189 | 9,837 | 684 | (33,371 | ) | |||||||||||
Basic and diluted earnings (loss) per common share (1) | 0.15 | 0.13 | 0.01 | (0.44 | ) | |||||||||||
Year Ended December 31, 2013 (2) | ||||||||||||||||
Revenues | $ | 259,222 | $ | 235,383 | $ | 244,555 | $ | 244,928 | ||||||||
Operating income | 60,321 | 53,823 | 31,965 | 622 | ||||||||||||
Net income (loss) | 26,618 | 22,396 | 14,194 | (11,886 | ) | |||||||||||
Basic and diluted earnings (loss) per common share (1) | 0.35 | 0.29 | 0.19 | (0.16 | ) | |||||||||||
-1 | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | |||||||||||||||
-2 | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe). The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense. We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. | |||||||||||||||
The fourth quarter of 2013 reflects a one-time increase in natural gas production volumes of 2.6 Bcf (with no corresponding increase in revenue) by using the correct conversion factor for the annual periods of 2011 and 2012, and the first three quarters of 2013, which increased DD&A by $7.1 million and decreased net income by $4.6 million. | ||||||||||||||||
Supplemental_Guarantor_Informa1
Supplemental Guarantor Information (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Supplemental Guarantor Information [Abstract] | ||||||||||||||||
Condensed Consolidating Balance Sheet | The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Transfers of property, including related ARO and deferred income tax liabilities, were made from the Parent Company to the Guarantor Subsidiaries to assist the Parent Company to continue to qualify for a waiver of certain supplemental bonding requirements from the BOEM. As these transfers were transactions between entities under common control, the prior period financial information has been retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance. The condensed consolidating financial information for current and prior periods was adjusted as if all transfers occurred at the beginning of the period presented. None of the above adjustments had any effect on the consolidated results for the current or prior periods presented. | |||||||||||||||
Condensed Consolidating Balance Sheet as of December 31, 2014 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 23,666 | $ | — | $ | — | $ | 23,666 | ||||||||
Receivables: | ||||||||||||||||
Oil and natural gas sales | 41,820 | 25,422 | — | 67,242 | ||||||||||||
Joint interest and other | 142,885 | — | (99,240 | ) | 43,645 | |||||||||||
Total receivables | 184,705 | 25,422 | (99,240 | ) | 110,887 | |||||||||||
Deferred income taxes | 9,797 | 1,865 | — | 11,662 | ||||||||||||
Prepaid expenses and other assets | 28,728 | 7,619 | — | 36,347 | ||||||||||||
Total current assets | 246,896 | 34,906 | (99,240 | ) | 182,562 | |||||||||||
Property and equipment – at cost: | ||||||||||||||||
Oil and natural gas properties and equipment | 6,038,915 | 2,006,751 | — | 8,045,666 | ||||||||||||
Furniture, fixtures and other | 23,269 | — | — | 23,269 | ||||||||||||
Total property and equipment | 6,062,184 | 2,006,751 | — | 8,068,935 | ||||||||||||
Less accumulated depreciation, depletion and amortization | 4,442,899 | 1,132,179 | — | 5,575,078 | ||||||||||||
Net property and equipment | 1,619,285 | 874,572 | — | 2,493,857 | ||||||||||||
Restricted deposits for asset retirement obligations | 15,444 | — | — | 15,444 | ||||||||||||
Other assets | 974,049 | 349,912 | (1,306,717 | ) | 17,244 | |||||||||||
Total assets | $ | 2,855,674 | $ | 1,259,390 | $ | (1,405,957 | ) | $ | 2,709,107 | |||||||
Liabilities and Shareholders’ Equity | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 188,654 | $ | 5,455 | $ | — | $ | 194,109 | ||||||||
Undistributed oil and natural gas proceeds | 36,130 | 879 | — | 37,009 | ||||||||||||
Asset retirement obligations | 30,711 | 5,292 | — | 36,003 | ||||||||||||
Accrued liabilities | 17,437 | 99,180 | (99,240 | ) | 17,377 | |||||||||||
Total current liabilities | 272,932 | 110,806 | (99,240 | ) | 284,498 | |||||||||||
Long-term debt, less current maturities | 1,360,057 | — | — | 1,360,057 | ||||||||||||
Asset retirement obligations, less current portion | 235,876 | 118,689 | — | 354,565 | ||||||||||||
Deferred income taxes | 59,616 | 127,372 | — | 186,988 | ||||||||||||
Other liabilities | 417,885 | — | (404,194 | ) | 13,691 | |||||||||||
Shareholders’ equity: | ||||||||||||||||
Common stock | 1 | — | — | 1 | ||||||||||||
Additional paid-in capital | 414,580 | 703,440 | (703,440 | ) | 414,580 | |||||||||||
Retained earnings | 118,894 | 199,083 | (199,083 | ) | 118,894 | |||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | ||||||||||
Total shareholders’ equity | 509,308 | 902,523 | (902,523 | ) | 509,308 | |||||||||||
Total liabilities and shareholders’ equity | $ | 2,855,674 | $ | 1,259,390 | $ | (1,405,957 | ) | $ | 2,709,107 | |||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Assets | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 15,800 | $ | — | $ | — | $ | 15,800 | ||||||||
Receivables: | ||||||||||||||||
Oil and natural gas sales | 61,373 | 35,379 | — | 96,752 | ||||||||||||
Joint interest and other | 123,595 | — | (92,491 | ) | 31,104 | |||||||||||
Total receivables | 184,968 | 35,379 | (92,491 | ) | 127,856 | |||||||||||
Deferred income taxes | 584 | - | — | 584 | ||||||||||||
Prepaid expenses and other assets | 23,090 | 6,272 | — | 29,362 | ||||||||||||
Total current assets | 224,442 | 41,651 | (92,491 | ) | 173,602 | |||||||||||
Property and equipment – at cost: | ||||||||||||||||
Oil and natural gas properties and equipment | 5,667,389 | 1,671,708 | — | 7,339,097 | ||||||||||||
Furniture, fixtures and other | 21,431 | — | — | 21,431 | ||||||||||||
Total property and equipment | 5,688,820 | 1,671,708 | — | 7,360,528 | ||||||||||||
Less accumulated depreciation, depletion and amortization | 4,166,359 | 918,345 | — | 5,084,704 | ||||||||||||
Net property and equipment | 1,522,461 | 753,363 | — | 2,275,824 | ||||||||||||
Restricted deposits for asset retirement obligations | 37,421 | — | — | 37,421 | ||||||||||||
Other assets | 951,203 | 479,820 | (1,410,568 | ) | 20,455 | |||||||||||
Total assets | $ | 2,735,527 | $ | 1,274,834 | $ | (1,503,059 | ) | $ | 2,507,302 | |||||||
Liabilities and Shareholders’ Equity | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 144,492 | $ | 720 | $ | — | $ | 145,212 | ||||||||
Undistributed oil and natural gas proceeds | 41,735 | 372 | — | 42,107 | ||||||||||||
Asset retirement obligations | 65,329 | 12,456 | — | 77,785 | ||||||||||||
Accrued liabilities | 28,000 | 92,491 | (92,491 | ) | 28,000 | |||||||||||
Total current liabilities | 279,556 | 106,039 | (92,491 | ) | 293,104 | |||||||||||
Long-term debt, less current maturities | 1,205,421 | — | — | 1,205,421 | ||||||||||||
Asset retirement obligations, less current portion | 189,507 | 87,130 | — | 276,637 | ||||||||||||
Deferred income taxes | 79,424 | 98,718 | — | 178,142 | ||||||||||||
Other liabilities | 441,009 | — | (427,621 | ) | 13,388 | |||||||||||
Shareholders’ equity: | ||||||||||||||||
Common stock | 1 | — | — | 1 | ||||||||||||
Additional paid-in capital | 403,564 | 784,104 | (784,104 | ) | 403,564 | |||||||||||
Retained earnings | 161,212 | 198,843 | (198,843 | ) | 161,212 | |||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | ||||||||||
Total shareholders’ equity | 540,610 | 982,947 | (982,947 | ) | 540,610 | |||||||||||
Total liabilities and shareholders’ equity | $ | 2,735,527 | $ | 1,274,834 | $ | (1,503,059 | ) | $ | 2,507,302 | |||||||
Condensed Consolidating Statement of Income | Condensed Consolidating Statement of Operations for the Year Ended December 31, 2014 | |||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 592,460 | $ | 356,248 | $ | — | $ | 948,708 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 179,344 | 85,407 | — | 264,751 | ||||||||||||
Production taxes | 7,932 | — | — | 7,932 | ||||||||||||
Gathering and transportation | 11,712 | 8,109 | — | 19,821 | ||||||||||||
Depreciation, depletion, amortization and accretion | 276,636 | 213,833 | — | 490,469 | ||||||||||||
Asset retirement obligations accretion | 10,981 | 9,652 | — | 20,633 | ||||||||||||
General and administrative expenses | 48,084 | 38,915 | — | 86,999 | ||||||||||||
Derivative gain | (3,965 | ) | — | — | (3,965 | ) | ||||||||||
Total costs and expenses | 530,724 | 355,916 | — | 886,640 | ||||||||||||
Operating income | 61,736 | 332 | — | 62,068 | ||||||||||||
Earnings of affiliates | 240 | — | (240 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 84,460 | 2,462 | — | 86,922 | ||||||||||||
Capitalized | (6,064 | ) | (2,462 | ) | — | (8,526 | ) | |||||||||
Other income, net | 208 | — | — | 208 | ||||||||||||
Income (loss) before income tax expense (benefit) | (16,212 | ) | 332 | (240 | ) | (16,120 | ) | |||||||||
Income tax expense (benefit) | (4,551 | ) | 92 | — | (4,459 | ) | ||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 240 | $ | (240 | ) | $ | (11,661 | ) | |||||
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 631,267 | $ | 352,821 | $ | — | $ | 984,088 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 202,096 | 68,743 | — | 270,839 | ||||||||||||
Production taxes | 7,135 | — | — | 7,135 | ||||||||||||
Gathering and transportation | 9,248 | 8,262 | — | 17,510 | ||||||||||||
Depreciation, depletion, amortization and accretion | 236,600 | 194,011 | — | 430,611 | ||||||||||||
Asset retirement obligations accretion | 14,218 | 6,700 | 20,918 | |||||||||||||
General and administrative expenses | 44,040 | 37,834 | — | 81,874 | ||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | ||||||||||||
Total costs and expenses | 521,807 | 315,550 | — | 837,357 | ||||||||||||
Operating income | 109,460 | 37,271 | — | 146,731 | ||||||||||||
Earnings of affiliates | 24,400 | — | (24,400 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 82,570 | 3,069 | — | 85,639 | ||||||||||||
Capitalized | (6,989 | ) | (3,069 | ) | — | (10,058 | ) | |||||||||
Other income, net | 8,946 | — | — | 8,946 | ||||||||||||
Income before income tax expense | 67,225 | 37,271 | (24,400 | ) | 80,096 | |||||||||||
Income tax expense | 15,903 | 12,871 | — | 28,774 | ||||||||||||
Net income | $ | 51,322 | $ | 24,400 | $ | (24,400 | ) | $ | 51,322 | |||||||
Condensed Consolidating Statement of Operations for the Year Ended December 31, 2012 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 539,958 | $ | 334,533 | $ | — | $ | 874,491 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Lease operating expenses | 168,033 | 64,227 | — | 232,260 | ||||||||||||
Production taxes | 5,840 | — | — | 5,840 | ||||||||||||
Gathering and transportation | 10,197 | 4,681 | — | 14,878 | ||||||||||||
Depreciation, depletion, amortization and accretion | 187,039 | 149,138 | — | 336,177 | ||||||||||||
Asset retirement obligations accretion | 14,979 | 5,076 | 20,055 | |||||||||||||
General and administrative expenses | 45,260 | 36,757 | — | 82,017 | ||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | ||||||||||||
Total costs and expenses | 445,302 | 259,879 | — | 705,181 | ||||||||||||
Operating income | 94,656 | 74,654 | — | 169,310 | ||||||||||||
Earnings of affiliates | 49,799 | — | (49,799 | ) | — | |||||||||||
Interest expense: | ||||||||||||||||
Incurred | 60,778 | 2,490 | — | 63,268 | ||||||||||||
Capitalized | (10,784 | ) | (2,490 | ) | — | (13,274 | ) | |||||||||
Other income, net | 215 | — | — | 215 | ||||||||||||
Income before income tax expense | 94,676 | 74,654 | (49,799 | ) | 119,531 | |||||||||||
Income tax expense | 22,692 | 24,855 | — | 47,547 | ||||||||||||
Net income | $ | 71,984 | $ | 49,799 | $ | (49,799 | ) | $ | 71,984 | |||||||
Condensed Consolidating Statement of Cash Flows | Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2014 | |||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income (loss) | $ | (11,661 | ) | $ | 240 | $ | (240 | ) | $ | (11,661 | ) | |||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 287,617 | 223,485 | — | 511,102 | ||||||||||||
Amortization of debt issuance costs and premium | 701 | — | — | 701 | ||||||||||||
Share-based compensation | 14,744 | — | — | 14,744 | ||||||||||||
Derivative gain | (3,965 | ) | — | — | (3,965 | ) | ||||||||||
Cash payments on derivative settlements, net | (5,318 | ) | — | — | (5,318 | ) | ||||||||||
Deferred income taxes | (32,456 | ) | 27,696 | — | (4,760 | ) | ||||||||||
Earnings of affiliates | (240 | ) | — | 240 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | 19,553 | 9,957 | — | 29,510 | ||||||||||||
Joint interest and other receivables | (4,255 | ) | — | — | (4,255 | ) | ||||||||||
Income taxes | 30,747 | (27,604 | ) | — | 3,143 | |||||||||||
Prepaid expenses and other assets | 25,555 | 12,882 | (23,425 | ) | 15,012 | |||||||||||
Asset retirement obligation settlements | (57,253 | ) | (17,060 | ) | — | (74,313 | ) | |||||||||
Accounts payable, accrued liabilities and other | 12,816 | 5,242 | 23,425 | 41,483 | ||||||||||||
Net cash provided by operating activities | 276,585 | 234,838 | — | 511,423 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (17,407 | ) | (54,827 | ) | — | (72,234 | ) | |||||||||
Investment in oil and natural gas properties and equipment | (312,044 | ) | (242,334 | ) | — | (554,378 | ) | |||||||||
Investment in subsidiary | (62,323 | ) | — | 62,323 | — | |||||||||||
Purchases of furniture, fixtures and other | (3,340 | ) | — | — | (3,340 | ) | ||||||||||
Net cash used in investing activities | (395,114 | ) | (297,161 | ) | 62,323 | (629,952 | ) | |||||||||
Financing activities: | ||||||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 556,000 | — | — | 556,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (399,000 | ) | — | — | (399,000 | ) | ||||||||||
Dividends to shareholders | (30,260 | ) | — | — | (30,260 | ) | ||||||||||
Other | (345 | ) | — | — | (345 | ) | ||||||||||
Investment from parent | — | 62,323 | (62,323 | ) | — | |||||||||||
Net cash provided in financing activities | 126,395 | 62,323 | (62,323 | ) | 126,395 | |||||||||||
Increase in cash and cash equivalents | 7,866 | — | — | 7,866 | ||||||||||||
Cash and cash equivalents, beginning of period | 15,800 | — | — | 15,800 | ||||||||||||
Cash and cash equivalents, end of period | $ | 23,666 | $ | — | $ | — | $ | 23,666 | ||||||||
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2013 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 51,322 | $ | 24,400 | $ | (24,400 | ) | $ | 51,322 | |||||||
Adjustments to reconcile net income to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 250,818 | 200,711 | — | 451,529 | ||||||||||||
Amortization of debt issuance costs and premium | 1,645 | — | — | 1,645 | ||||||||||||
Share-based compensation | 11,525 | — | — | 11,525 | ||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | ||||||||||||
Cash payments on derivative settlements | (8,589 | ) | — | — | (8,589 | ) | ||||||||||
Deferred income taxes | 7,564 | 23,356 | — | 30,920 | ||||||||||||
Earnings of affiliates | (24,400 | ) | — | 24,400 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | 6,182 | (5,202 | ) | — | 980 | |||||||||||
Joint interest and other receivables | 34,257 | — | — | 34,257 | ||||||||||||
Income taxes | 54,813 | (10,485 | ) | — | 44,328 | |||||||||||
Prepaid expenses and other assets | (25,329 | ) | (18,835 | ) | 34,120 | (10,044 | ) | |||||||||
Asset retirement obligations | (65,438 | ) | (16,105 | ) | — | (81,543 | ) | |||||||||
Accounts payable, accrued liabilities and other | 59,961 | 717 | (34,120 | ) | 26,558 | |||||||||||
Net cash provided by operating activities | 362,801 | 198,557 | — | 561,358 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | — | (82,424 | ) | — | (82,424 | ) | ||||||||||
Investment in oil and natural gas properties and equipment | (349,804 | ) | (202,150 | ) | — | (551,954 | ) | |||||||||
Investment in subsidiary | (86,017 | ) | — | 86,017 | — | |||||||||||
Proceeds from sales of assets and other, net | 21,008 | — | — | 21,008 | ||||||||||||
Purchases of furniture, fixtures and other | (1,435 | ) | — | — | (1,435 | ) | ||||||||||
Net cash used in investing activities | (416,248 | ) | (284,574 | ) | 86,017 | (614,805 | ) | |||||||||
Financing activities: | ||||||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 563,000 | — | — | 563,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (443,000 | ) | — | — | (443,000 | ) | ||||||||||
Debt issuance costs | (3,892 | ) | — | — | (3,892 | ) | ||||||||||
Dividends to shareholders | (58,846 | ) | — | — | (58,846 | ) | ||||||||||
Investment from parent | — | 86,017 | (86,017 | ) | — | |||||||||||
Other | (260 | ) | — | — | (260 | ) | ||||||||||
Net cash used in financing activities | 57,002 | 86,017 | (86,017 | ) | 57,002 | |||||||||||
Increase in cash and cash equivalents | 3,555 | — | — | 3,555 | ||||||||||||
Cash and cash equivalents, beginning of period | 12,245 | — | — | 12,245 | ||||||||||||
Cash and cash equivalents, end of period | $ | 15,800 | $ | — | $ | — | $ | 15,800 | ||||||||
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2012 | ||||||||||||||||
Consolidated | ||||||||||||||||
Parent | Guarantor | W&T | ||||||||||||||
Company | Subsidiaries | Eliminations | Offshore, Inc. | |||||||||||||
(In thousands) | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 71,984 | $ | 49,799 | $ | (49,799 | ) | $ | 71,984 | |||||||
Adjustments to reconcile net income to net cash | ||||||||||||||||
provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 202,018 | 154,214 | — | 356,232 | ||||||||||||
Amortization of debt issuance costs and premium | 2,575 | — | — | 2,575 | ||||||||||||
Share-based compensation | 12,398 | — | — | 12,398 | ||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | ||||||||||||
Cash payments on derivative settlements | (7,664 | ) | — | — | (7,664 | ) | ||||||||||
Deferred income taxes | 81,653 | 6,456 | — | 88,109 | ||||||||||||
Earnings of affiliates | (49,799 | ) | — | 49,799 | — | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Oil and natural gas receivables | (3,783 | ) | 4,601 | — | 818 | |||||||||||
Joint interest and other receivables | (28,823 | ) | — | — | (28,823 | ) | ||||||||||
Income taxes | (76,411 | ) | 18,400 | — | (58,011 | ) | ||||||||||
Prepaid expenses and other assets | 9,017 | (119,895 | ) | 118,318 | 7,440 | |||||||||||
Asset retirement obligations | (105,773 | ) | (7,054 | ) | — | (112,827 | ) | |||||||||
Accounts payable, accrued liabilities and other | 159,774 | (2,504 | ) | (118,318 | ) | 38,952 | ||||||||||
Net cash provided by operating activities | 281,120 | 104,017 | — | 385,137 | ||||||||||||
Investing activities: | ||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (151,429 | ) | (54,121 | ) | — | (205,550 | ) | |||||||||
Investment in oil and natural gas properties and equipment | (375,296 | ) | (104,017 | ) | — | (479,313 | ) | |||||||||
Investment in subsidiary | (54,121 | ) | — | 54,121 | — | |||||||||||
Proceeds from sales of assets and other, net | 30,453 | — | — | 30,453 | ||||||||||||
Purchases of furniture, fixtures and other | (3,031 | ) | — | — | (3,031 | ) | ||||||||||
Net cash used in investing activities | (553,424 | ) | (158,138 | ) | 54,121 | (657,441 | ) | |||||||||
Financing activities: | ||||||||||||||||
Issuance of 8.50% Senior Notes | 318,000 | — | — | 318,000 | ||||||||||||
Borrowings of long-term debt – revolving bank credit facility | 732,000 | — | — | 732,000 | ||||||||||||
Repayments of long-term debt – revolving bank credit facility | (679,000 | ) | — | — | (679,000 | ) | ||||||||||
Debt issuance costs | (8,510 | ) | — | — | (8,510 | ) | ||||||||||
Dividends to shareholders | (82,832 | ) | — | — | (82,832 | ) | ||||||||||
Investment from parent | — | 54,121 | (54,121 | ) | — | |||||||||||
Other | 379 | — | — | 379 | ||||||||||||
Net cash used in financing activities | 280,037 | 54,121 | (54,121 | ) | 280,037 | |||||||||||
Increase in cash and cash equivalents | 7,733 | — | — | 7,733 | ||||||||||||
Cash and cash equivalents, beginning of period | 4,512 | — | — | 4,512 | ||||||||||||
Cash and cash equivalents, end of period | $ | 12,245 | $ | — | $ | — | $ | 12,245 | ||||||||
Supplemental_Oil_and_Gas_Discl1
Supplemental Oil and Gas Disclosures-unaudited (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Extractive Industries [Abstract] | ||||||||||||||||||||
Capitalized Costs Related to Oil and Natural Gas | Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): | |||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Net capitalized cost: | ||||||||||||||||||||
Proved oil and natural gas properties and equipment | $ | 7,924.20 | $ | 7,207.10 | $ | 6,551.50 | ||||||||||||||
Unproved oil and natural gas properties and equipment | 121.5 | 132 | 143 | |||||||||||||||||
Accumulated depreciation, depletion and amortization | (5,557.6 | ) | (5,069.2 | ) | (4,640.8 | ) | ||||||||||||||
related to oil, NGLs and natural gas activities | ||||||||||||||||||||
Net capitalized costs related to producing activities | $ | 2,488.10 | $ | 2,269.90 | $ | 2,053.70 | ||||||||||||||
Capitalized Costs Not Subject to Amortization | Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2014, by the year in which the costs were incurred (in millions): | |||||||||||||||||||
Total | 2014 | 2013 | 2012 | Prior to | ||||||||||||||||
2012 | ||||||||||||||||||||
Costs excluded by year incurred: | ||||||||||||||||||||
Acquisition costs | $ | 75.5 | $ | 2.6 | $ | 5.7 | $ | 7 | $ | 60.2 | ||||||||||
Capitalized interest not subject to amortization | 34.3 | 7.5 | 7.3 | 6.4 | 13.1 | |||||||||||||||
Total costs not subject to amortization | $ | 109.8 | $ | 10.1 | $ | 13 | $ | 13.4 | $ | 73.3 | ||||||||||
Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities | The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): | |||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Costs incurred: (1) | ||||||||||||||||||||
Proved properties acquisitions | $ | 111.5 | $ | 96.9 | $ | 239.8 | ||||||||||||||
Exploration (2) (3) | 411.1 | 215.3 | 151.3 | |||||||||||||||||
Development | 198.7 | 352.9 | 363.7 | |||||||||||||||||
Unproved properties acquisitions (4) | 3.1 | 26.3 | 26.5 | |||||||||||||||||
Total costs incurred in oil and gas property acquisition, | $ | 724.4 | $ | 691.4 | $ | 781.3 | ||||||||||||||
exploration and development activities | ||||||||||||||||||||
-1 | Includes net additions from capitalized ARO of $88.0 million, $50.6 million and $86.9 million during 2014, 2013 and 2012, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. | |||||||||||||||||||
-2 | Includes seismic costs of $9.0 million, $8.9 million and $6.2 million incurred during 2014, 2013 and 2012, respectively. | |||||||||||||||||||
-3 | Includes geological and geophysical costs charged to expense of $7.3 million, $5.9 million and $6.2 million during 2014, 2013 and 2012, respectively. | |||||||||||||||||||
-4 | The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period. | |||||||||||||||||||
Schedule of Depreciation, Depletion, Amortization and Accretion Expense | The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold. | |||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Depreciation, depletion, amortization and accretion per Boe | $ | 28.98 | $ | 25.1 | $ | 20.79 | ||||||||||||||
Schedule of Oil and Natural Gas Information | The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with 69% located in the Gulf of Mexico and the remainder located in the West Texas Permian Basin. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economically viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”. | |||||||||||||||||||
Total Energy Equivalent Reserves (1) | ||||||||||||||||||||
Oil | NGLs | Natural Gas | Oil | Natural Gas | ||||||||||||||||
(MMBbls) | (MMBbls) | (Bcf) | Equivalent | Equivalent | ||||||||||||||||
(MMBoe) | (Bcfe) | |||||||||||||||||||
Proved reserves as of Dec. 31, 2011 | 51.4 | 17.1 | 289.7 | 116.9 | 701.1 | |||||||||||||||
Revisions of previous estimates (2) | (1.1 | ) | (2.6 | ) | (4.8 | ) | (4.6 | ) | (27.5 | ) | ||||||||||
Extensions and discoveries (3) | 8.2 | 2.6 | 29.6 | 15.7 | 94.5 | |||||||||||||||
Purchase of minerals in place (4) | 2.5 | 0.2 | 25.5 | 7 | 42 | |||||||||||||||
Sales of reserves (5) | (0.2 | ) | — | (1.1 | ) | (0.4 | ) | (2.2 | ) | |||||||||||
Production | (6.0 | ) | (2.1 | ) | (53.8 | ) | (17.1 | ) | (102.8 | ) | ||||||||||
Proved reserves as of Dec. 31, 2012 | 54.8 | 15.2 | 285.1 | 117.5 | 705.1 | |||||||||||||||
Revisions of previous estimates (6) | (4.3 | ) | 0.2 | 2.1 | (3.8 | ) | (22.8 | ) | ||||||||||||
Extensions and discoveries (7) | 13.9 | 2.6 | 22 | 20.2 | 121 | |||||||||||||||
Purchase of minerals in place (8) | 1.5 | — | 4.4 | 2.3 | 13.7 | |||||||||||||||
Sales of reserves (9) | (0.4 | ) | — | (0.4 | ) | (0.5 | ) | (3.2 | ) | |||||||||||
Production | (7.0 | ) | (2.1 | ) | (53.3 | ) | (18.0 | ) | (107.9 | ) | ||||||||||
Proved reserves as of Dec. 31, 2013 | 58.5 | 15.9 | 259.9 | 117.7 | 705.9 | |||||||||||||||
Revisions of previous estimates (10) | 1.6 | 0.1 | 14.3 | 4.1 | 25.3 | |||||||||||||||
Extensions and discoveries (11) | 7.3 | 0.7 | 10.1 | 9.7 | 58.1 | |||||||||||||||
Purchase of minerals in place (12) | 1.5 | 1.2 | 20.7 | 6.1 | 36.5 | |||||||||||||||
Production | (7.2 | ) | (2.1 | ) | (50.1 | ) | (17.6 | ) | (105.8 | ) | ||||||||||
Proved reserves as of Dec. 31, 2014 | 61.7 | 15.8 | 254.9 | 120 | 720 | |||||||||||||||
Year-end proved developed reserves: | ||||||||||||||||||||
2014 | 35.7 | 10.7 | 221.1 | 83.3 | 499.7 | |||||||||||||||
2013 | 36.2 | 11.1 | 232.7 | 86.1 | 516.1 | |||||||||||||||
2012 | 35.3 | 11 | 243.5 | 86.9 | 521.2 | |||||||||||||||
Year-end proved undeveloped reserves: | ||||||||||||||||||||
2014 (13) | 26 | 5.1 | 33.8 | 36.7 | 220.3 | |||||||||||||||
2013 | 22.3 | 4.8 | 27.2 | 31.6 | 189.8 | |||||||||||||||
2012 | 19.5 | 4.2 | 41.6 | 30.6 | 183.9 | |||||||||||||||
Volume measurements: | ||||||||||||||||||||
Bbl – barrel | Mcf – thousand cubic feet | |||||||||||||||||||
MMBbls – million barrels for crude oil, condensate or NGLs | Bcf – billion cubic feet | |||||||||||||||||||
MMBoe – million barrels of oil equivalent | Bcfe – billion cubic feet of gas equivalent | |||||||||||||||||||
-1 | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. | |||||||||||||||||||
-2 | Includes downward revisions due to price of 1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field. | |||||||||||||||||||
-3 | Includes extensions and discoveries of 11.6 MMBoe at our Spraberry field and extensions and discoveries of 2.7 MMBoe at our High Island 21/22 field. | |||||||||||||||||||
-4 | Due to the acquisition of the Newfield Properties. | |||||||||||||||||||
-5 | Due to the sale of our interest in the South Timbalier 41 field. | |||||||||||||||||||
-6 | Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Spraberry field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. | |||||||||||||||||||
-7 | Includes extensions and discoveries of 12.6 MMBoe at our Spraberry field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. | |||||||||||||||||||
-8 | Primarily due to the acquisition of the Callon Properties. | |||||||||||||||||||
-9 | Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. | |||||||||||||||||||
-10 | Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Spraberry field and 2.4 MMBoe at various other fields. | |||||||||||||||||||
-11 | Includes extensions and discoveries of 4.1 MMBoe at our Spraberry field and 4.1 MMBoe at our Mississippi Canyon 782 field. | |||||||||||||||||||
-12 | Primarily due to acquiring additional ownership in the Fairway field and acquisition of the Woodside Properties. | |||||||||||||||||||
-13 | We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. These PUDs were originally recorded in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020. | |||||||||||||||||||
Schedule of Prices Weighted by Field Production Related to Proved Reserves | The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio is applied to the oil price using FASB/SEC guidance. The average commodity prices weighted by field production related to the proved reserves are as follows: | |||||||||||||||||||
December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | |||||||||||||||||
Oil - per barrel | $ | 91.12 | $ | 99.65 | $ | 98.13 | $ | 97.36 | ||||||||||||
NGLs per barrel | 34.63 | 35.21 | 47.3 | 51.3 | ||||||||||||||||
Natural gas - per Mcf | 4.27 | 3.8 | 2.77 | 4.11 | ||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flow | The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2014 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): | |||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | ||||||||||||||||||||
Future cash inflows | $ | 7,258.50 | $ | 7,376.70 | $ | 6,888.40 | ||||||||||||||
Future costs: | ||||||||||||||||||||
Production | (2,224.5 | ) | (2,142.8 | ) | (1,858.3 | ) | ||||||||||||||
Development | (922.0 | ) | (1,001.4 | ) | (655.4 | ) | ||||||||||||||
Dismantlement and abandonment | (475.4 | ) | (441.6 | ) | (508.0 | ) | ||||||||||||||
Income taxes | (948.4 | ) | (986.9 | ) | (1,002.1 | ) | ||||||||||||||
Future net cash inflows before 10% discount | 2,688.20 | 2,804.00 | 2,864.60 | |||||||||||||||||
10% annual discount factor | (985.4 | ) | (1,129.4 | ) | (1,018.2 | ) | ||||||||||||||
Total | $ | 1,702.80 | $ | 1,674.60 | $ | 1,846.40 | ||||||||||||||
Schedule of Changes In Standardized Measure | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Changes in Standardized Measure | ||||||||||||||||||||
Standardized measure, beginning of year | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | ||||||||||||||
Increases (decreases): | ||||||||||||||||||||
Sales and transfers of oil and gas produced, net of production | (650.9 | ) | (686.1 | ) | (620.4 | ) | ||||||||||||||
costs | ||||||||||||||||||||
Net changes in price, net of future production costs | (278.6 | ) | (65.2 | ) | (224.3 | ) | ||||||||||||||
Extensions and discoveries, net of future production and | 309.6 | 393.8 | 181.9 | |||||||||||||||||
development costs | ||||||||||||||||||||
Changes in estimated future development costs | (56.4 | ) | (91.1 | ) | (103.3 | ) | ||||||||||||||
Previously estimated development costs incurred | 263.1 | 262.1 | 332.9 | |||||||||||||||||
Revisions of quantity estimates | 118.6 | (91.6 | ) | (128.1 | ) | |||||||||||||||
Accretion of discount | 180.6 | 202.2 | 231.1 | |||||||||||||||||
Net change in income taxes | (11.4 | ) | 56.6 | 99.7 | ||||||||||||||||
Purchases of reserves in-place | 86.7 | 79.6 | 270.2 | |||||||||||||||||
Sales of reserves in-place | — | (53.1 | ) | (16.1 | ) | |||||||||||||||
Changes in production rates due to timing and other | 66.9 | (179.0 | ) | (183.6 | ) | |||||||||||||||
Net increase (decrease) in standardized measure | 28.2 | (171.8 | ) | (160.0 | ) | |||||||||||||||
Standardized measure, end of year | $ | 1,702.80 | $ | 1,674.60 | $ | 1,846.40 | ||||||||||||||
Significant_Accounting_Policie3
Significant Accounting Policies - Additional Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MMcf | MMcf | |||
Significant Accounting Policies [Line Items] | ||||
Increase in natural gas production volumes | 2,600 | 1,900 | ||
Natural gas imbalances | $6,400,000 | $6,400,000 | $6,400,000 | |
Percentage of discount from proved reserves | 10.00% | |||
Ceiling test impairment | 0 | 0 | 0 | |
Proved undeveloped reserves classification period to be drilled | 5 years | |||
Goodwill, acquired during period | 0 | 0 | 0 | |
Payments received related to break-up fee and termination of certain purchase and sale agreement | 9,200,000 | |||
Third-party expenses related to the cancelled transaction | 100,000 | |||
Fixtures and Non-Oil and Natural Gas Property and Equipment | Minimum | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 5 years | |||
Fixtures and Non-Oil and Natural Gas Property and Equipment | Maximum | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 7 years | |||
Natural Gas | ||||
Significant Accounting Policies [Line Items] | ||||
Adjustment to depreciation, depletion, amortization and accretion | 7,100,000 | 5,000,000 | ||
Reduction in net income | $4,600,000 | $3,200,000 |
Significant_Accounting_Policie4
Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) (Sales Revenue Net, Customer Concentration Risk) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Shell Trading (US) Co. | ||||
Entity Wide Revenue Major Customer [Line Items] | ||||
Percentage of receipts | 47.00% | 48.00% | 35.00% | |
ConocoPhillips | ||||
Entity Wide Revenue Major Customer [Line Items] | ||||
Percentage of receipts | 16.00% | [1] | ||
[1] | (1) ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. |
Significant_Accounting_Policie5
Significant Accounting Policies - Percentage of Revenue by Major Customers (Parenthetical) (Details) (ConocoPhillips) | 12 Months Ended | |
Dec. 31, 2012 | ||
Entity | ||
Companies Separated Into Two | ||
Entity Wide Revenue Major Customer [Line Items] | ||
Number of companies separated | 2 | |
Sales Revenue Net | Customer Concentration Risk | ||
Entity Wide Revenue Major Customer [Line Items] | ||
Percentage of receipts | 16.00% | [1] |
Sales Revenue Net | Companies Separated Into Two | Customer Concentration Risk | ||
Entity Wide Revenue Major Customer [Line Items] | ||
Percentage of receipts | 8.00% | |
[1] | (1) ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. |
Acquisitions_and_Divestitures_1
Acquisitions and Divestitures - Additional Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | 7 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Jul. 11, 2013 | Sep. 26, 2013 | Dec. 31, 2012 | 15-May-12 | Sep. 15, 2014 | Sep. 14, 2014 | 20-May-14 | Oct. 17, 2013 | Oct. 05, 2012 | |||||
Block | |||||||||||||||||||||||||
acre | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Goodwill, acquired during period | $0 | $0 | $0 | ||||||||||||||||||||||
Revenues | 196,677,000 | 234,521,000 | 262,994,000 | 254,516,000 | 244,928,000 | [1],[2] | 244,555,000 | [1],[2] | 235,383,000 | [1],[2] | 259,222,000 | [1],[2] | 948,708,000 | 984,088,000 | 874,491,000 | ||||||||||
DD&A | 511,102,000 | 451,529,000 | 356,232,000 | ||||||||||||||||||||||
Income tax expense | -4,459,000 | 28,774,000 | 47,547,000 | ||||||||||||||||||||||
Net income | -33,371,000 | 684,000 | 9,837,000 | 11,189,000 | -11,886,000 | [1],[2] | 14,194,000 | [1],[2] | 22,396,000 | [1],[2] | 26,618,000 | [1],[2] | -11,661,000 | 51,322,000 | 71,984,000 | ||||||||||
Fairway | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Percentage of working interest | 100.00% | 64.30% | |||||||||||||||||||||||
Goodwill, acquired during period | 0 | ||||||||||||||||||||||||
Woodside Properties | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Percentage of working interest | 20.00% | ||||||||||||||||||||||||
Goodwill, acquired during period | 0 | ||||||||||||||||||||||||
Revenues | 28,400,000 | ||||||||||||||||||||||||
Lease operating expenses | 5,500,000 | ||||||||||||||||||||||||
DD&A | 11,000,000 | ||||||||||||||||||||||||
Income tax expense | 4,200,000 | ||||||||||||||||||||||||
Net income | 7,700,000 | ||||||||||||||||||||||||
Callon Properties | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Percentage of working interest | 15.00% | ||||||||||||||||||||||||
Goodwill, acquired during period | 0 | ||||||||||||||||||||||||
Revenues | 5,800,000 | 32,500,000 | |||||||||||||||||||||||
Lease operating expenses | 1,300,000 | 6,600,000 | |||||||||||||||||||||||
DD&A | 2,400,000 | 16,400,000 | |||||||||||||||||||||||
Income tax expense | 700,000 | 3,300,000 | |||||||||||||||||||||||
Net income | 1,400,000 | 6,200,000 | |||||||||||||||||||||||
Adjustments to purchase price | 600,000 | ||||||||||||||||||||||||
Green Canyon Fields | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Reversal of asset retirement obligation | 15,600,000 | ||||||||||||||||||||||||
Proceeds from sale of properties | 4,300,000 | ||||||||||||||||||||||||
West Delta Area Block Twenty Nine | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Reversal of asset retirement obligation | 3,900,000 | ||||||||||||||||||||||||
Proceeds from sale of properties | 14,700,000 | ||||||||||||||||||||||||
West Delta Area Block Twenty Nine | Post Effective Date Repayment | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Proceeds from sale of properties | 1,700,000 | 1,700,000 | 1,700,000 | ||||||||||||||||||||||
Newfield Properties | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Goodwill, acquired during period | 0 | ||||||||||||||||||||||||
Revenues | 121,100,000 | 127,100,000 | 29,600,000 | ||||||||||||||||||||||
Lease operating expenses | 23,500,000 | 26,700,000 | 5,400,000 | ||||||||||||||||||||||
DD&A | 60,500,000 | 57,600,000 | 11,900,000 | ||||||||||||||||||||||
Income tax expense | 13,000,000 | 15,000,000 | 4,300,000 | ||||||||||||||||||||||
Net income | 24,100,000 | 27,800,000 | 8,000,000 | ||||||||||||||||||||||
Adjustments to purchase price | 200,000 | ||||||||||||||||||||||||
Number of federal offshore blocks | 78 | ||||||||||||||||||||||||
Leasehold interest acres acquired, gross | 416,000 | ||||||||||||||||||||||||
Leasehold interest acres acquired, net | 268,000 | ||||||||||||||||||||||||
South Timbalier 41 | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Reversal of asset retirement obligation | 4,000,000 | ||||||||||||||||||||||||
Proceeds from sale of properties | $30,500,000 | ||||||||||||||||||||||||
Percentage of non-operating working interest sold | 40.00% | ||||||||||||||||||||||||
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | ||||||||||||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. |
Acquisitions_and_Divestitures_2
Acquisitions and Divestitures - Purchase Price Allocation for Acquisition (Details) (USD $) | 0 Months Ended | 1 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 15, 2014 | 20-May-14 | Oct. 17, 2013 | 11-May-11 |
Fairway | ||||
Non-cash consideration: | ||||
Asset retirement obligations - non-current | $6,124 | |||
Total consideration | 23,531 | |||
Fairway | Evaluated Properties Including Equipment | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 17,407 | |||
Woodside Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 54,827 | |||
Non-cash consideration: | ||||
Asset retirement obligations - non-current | 10,543 | |||
Asset retirement obligations - current | 782 | |||
Non-cash consideration | 11,325 | |||
Total consideration | 66,152 | |||
Woodside Properties | Evaluated Properties Including Equipment | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 52,167 | |||
Woodside Properties | Unevaluated Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 2,660 | |||
Callon Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 83,000 | |||
Non-cash consideration: | ||||
Asset retirement obligations - non-current | 4,143 | |||
Asset retirement obligations - current | 90 | |||
Non-cash consideration | 4,233 | |||
Total consideration | 87,233 | |||
Callon Properties | Evaluated Properties Including Equipment | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 73,752 | |||
Callon Properties | Unevaluated Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 9,248 | |||
Newfield Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 205,788 | |||
Non-cash consideration: | ||||
Asset retirement obligations - non-current | 24,414 | |||
Asset retirement obligations - current | 7,250 | |||
Non-cash consideration | 31,664 | |||
Total consideration | 237,452 | |||
Newfield Properties | Evaluated Properties Including Equipment | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | 192,723 | |||
Newfield Properties | Unevaluated Properties | ||||
Cash consideration: | ||||
Oil and natural gas properties and equipment | $13,065 |
Acquisitions_and_Divestitures_3
Acquisitions and Divestitures - Summary of Proforma Financial Information for Acquisition (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Woodside Properties | |||
Business Acquisition [Line Items] | |||
Revenue | $971,595 | $1,047,037 | |
Net income (loss) | -5,495 | 71,432 | |
Basic and diluted earnings (loss) per common share | ($0.08) | $0.94 | |
Callon Properties | |||
Business Acquisition [Line Items] | |||
Revenue | 1,018,118 | 923,050 | |
Net income (loss) | 59,015 | 85,310 | |
Basic and diluted earnings (loss) per common share | $0.78 | $1.12 | |
Newfield Properties | |||
Business Acquisition [Line Items] | |||
Revenue | 980,196 | ||
Net income (loss) | $77,036 | ||
Basic and diluted earnings (loss) per common share | $1.01 |
Acquisitions_and_Divestitures_4
Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Details) (USD $) | 3 Months Ended | 12 Months Ended | 7 Months Ended | 12 Months Ended | 3 Months Ended | |||||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | |||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | $196,677 | $234,521 | $262,994 | $254,516 | $244,928 | [1],[2] | $244,555 | [1],[2] | $235,383 | [1],[2] | $259,222 | [1],[2] | $948,708 | $984,088 | $874,491 | |||||||||
DD&A | 511,102 | 451,529 | 356,232 | |||||||||||||||||||||
G&A | 86,999 | 81,874 | 82,017 | |||||||||||||||||||||
Interest expense | 86,922 | 85,639 | 63,268 | |||||||||||||||||||||
Capitalized | -8,526 | -10,058 | -13,274 | |||||||||||||||||||||
Income tax expense | -4,459 | 28,774 | 47,547 | |||||||||||||||||||||
Woodside Properties | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 28,400 | |||||||||||||||||||||||
Direct operating expenses | 5,500 | |||||||||||||||||||||||
DD&A | 11,000 | |||||||||||||||||||||||
Income tax expense | 4,200 | |||||||||||||||||||||||
Woodside Properties | Pro Forma | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 22,887 | [3],[4] | 62,949 | [3] | ||||||||||||||||||||
Direct operating expenses | 4,417 | [3],[4] | 9,583 | [3] | ||||||||||||||||||||
DD&A | 8,374 | [4],[5] | 20,476 | [5] | ||||||||||||||||||||
G&A | 300 | [4],[6] | 800 | [6] | ||||||||||||||||||||
Interest expense | 329 | [4],[7] | 987 | [7] | ||||||||||||||||||||
Capitalized | -19 | [4],[8] | 164 | [8] | ||||||||||||||||||||
Income tax expense | 3,320 | [4],[9] | 10,829 | [9] | ||||||||||||||||||||
Callon Properties | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 5,800 | 32,500 | ||||||||||||||||||||||
Direct operating expenses | 1,300 | 6,600 | ||||||||||||||||||||||
DD&A | 2,400 | 16,400 | ||||||||||||||||||||||
Income tax expense | 700 | 3,300 | ||||||||||||||||||||||
Callon Properties | Pro Forma | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 34,030 | [10],[11] | 48,559 | [10] | ||||||||||||||||||||
Direct operating expenses | 6,405 | [10],[11] | 8,525 | [10] | ||||||||||||||||||||
DD&A | 14,931 | [11],[12] | 17,578 | [12] | ||||||||||||||||||||
G&A | -361 | [11],[13] | ||||||||||||||||||||||
Interest expense | 1,383 | [11],[14] | 1,660 | [14] | ||||||||||||||||||||
Capitalized | -164 | [11],[15] | 295 | [15] | ||||||||||||||||||||
Income tax expense | 4,143 | [11],[9] | 7,175 | [9] | ||||||||||||||||||||
Newfield Properties | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 121,100 | 127,100 | 29,600 | |||||||||||||||||||||
Direct operating expenses | 23,500 | 26,700 | 5,400 | |||||||||||||||||||||
DD&A | 60,500 | 57,600 | 11,900 | |||||||||||||||||||||
Income tax expense | 13,000 | 15,000 | 4,300 | |||||||||||||||||||||
Newfield Properties | Pro Forma | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 105,705 | [16],[17] | ||||||||||||||||||||||
Direct operating expenses | 33,186 | [16],[17] | ||||||||||||||||||||||
Insurance costs | 475 | [16],[18] | ||||||||||||||||||||||
DD&A | 53,408 | [16],[19] | ||||||||||||||||||||||
G&A | -553 | [16],[20] | ||||||||||||||||||||||
Interest expense | 12,060 | [16],[21] | ||||||||||||||||||||||
Capitalized | -643 | [16],[22] | ||||||||||||||||||||||
Income tax expense | $2,720 | [16],[9] | ||||||||||||||||||||||
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | |||||||||||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. | |||||||||||||||||||||||
[3] | Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside. | |||||||||||||||||||||||
[4] | The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014. | |||||||||||||||||||||||
[5] | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Propertiesb costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | |||||||||||||||||||||||
[6] | Estimated insurance costs related to the Woodside Properties. | |||||||||||||||||||||||
[7] | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $54.8 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | |||||||||||||||||||||||
[8] | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. | |||||||||||||||||||||||
[9] | Income tax expense was computed using the 35% federal statutory rate. | |||||||||||||||||||||||
[10] | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | |||||||||||||||||||||||
[11] | The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013. | |||||||||||||||||||||||
[12] | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Propertiesb costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | |||||||||||||||||||||||
[13] | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results. | |||||||||||||||||||||||
[14] | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | |||||||||||||||||||||||
[15] | The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses. | |||||||||||||||||||||||
[16] | The adjustments are for the period from January 1, 2012 to October 5, 2012. | |||||||||||||||||||||||
[17] | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | |||||||||||||||||||||||
[18] | Incremental costs for insurance were estimated from the incremental costs to add the Newfield Properties to W&Tbs insurance programs. The direct operating costs for the Newfield Properties described above excluded insurance costs. | |||||||||||||||||||||||
[19] | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Propertiesb costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. | |||||||||||||||||||||||
[20] | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | |||||||||||||||||||||||
[21] | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.8 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. | |||||||||||||||||||||||
[22] | Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. |
Acquisitions_and_Divestitures_5
Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Parenthetical) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 |
Business Acquisition [Line Items] | ||||
Long-term debt, less current maturities | $1,360,057 | $1,205,421 | $1,205,421 | |
Federal statutory income tax rate | 35.00% | 35.00% | 35.00% | |
Woodside Properties | ||||
Business Acquisition [Line Items] | ||||
Long-term debt, less current maturities | 54,800 | |||
Effective interest rate | 1.80% | |||
Federal statutory income tax rate | 35.00% | |||
Callon Properties | ||||
Business Acquisition [Line Items] | ||||
Long-term debt, less current maturities | 83,000 | 83,000 | ||
Effective interest rate | 2.00% | 2.00% | ||
Federal statutory income tax rate | 35.00% | |||
Newfield Properties | ||||
Business Acquisition [Line Items] | ||||
Long-term debt, less current maturities | 205,800 | |||
Effective interest rate | 7.70% | |||
Federal statutory income tax rate | 35.00% |
Hurricane_Remediation_and_Insu1
Hurricane Remediation and Insurance Claims - Additional Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2008 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Insurance [Abstract] | ||||
Retention amount per occurrence | $10 | |||
Maximum insurance coverage policy limit due to named windstorms for per incident | 150 | |||
Maximum insurance coverage policy limit except for property damage due to named windstorms | 250 | |||
Insurance proceeds | 12.2 | 6.7 | 2.9 | |
Cumulative insurance recoveries related to hurricanes | $161.20 |
Asset_Retirement_Obligations_R
Asset Retirement Obligations - Reconciliation of Asset Retirement Obligations Liability (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligations, beginning of period | $354,422 | $384,053 | |
Asset retirement obligation settlements | -74,313 | -81,543 | -112,827 |
Accretion of discount | 20,633 | 20,918 | 20,055 |
Disposition of properties | -19,564 | ||
Liabilities assumed through acquisition | 21,820 | 4,233 | |
Liabilities incurred | 3,258 | 1,745 | |
Revisions of estimated liabilities | 64,748 | 44,580 | |
Asset retirement obligations, end of period | 390,568 | 354,422 | 384,053 |
Less current portion | 36,003 | 77,785 | |
Long-term | $354,565 | $276,637 |
Derivative_Financial_Instrumen2
Derivative Financial Instruments - Estimated Fair Value of Derivative Contracts (Details) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Derivatives Fair Value [Line Items] | |
Fair value of commodity derivative contracts | $141 |
Fair value of commodity derivative contracts | 9,423 |
Prepaid And Other Assets | |
Derivatives Fair Value [Line Items] | |
Fair value of commodity derivative contracts | 141 |
Accrued Liabilities | |
Derivatives Fair Value [Line Items] | |
Fair value of commodity derivative contracts | $9,423 |
Derivative_Financial_Instrumen3
Derivative Financial Instruments - Changes in Fair Value of Commodity Derivative Contracts Recognized in Earnings (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Gain Loss On Derivative Instruments Net Pretax [Abstract] | |||
Derivative (gain) loss | ($3,965) | $8,470 | $13,954 |
Derivative_Financial_Instrumen4
Derivative Financial Instruments - Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
Cash payments on derivative settlements, net | $5,318 | $8,589 | $7,664 |
Derivative_Financial_Instrumen5
Derivative Financial Instruments - Additional Information (Details) | Dec. 31, 2014 |
DerivativeInstrument | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
No. of open derivative instruments | 0 |
Derivative_Financial_Instrumen6
Derivative Financial Instruments - Reconciliation of Gross Assets and Liabilities and Netting Agreements on Fair Value of Open Derivative Contracts (Details) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Derivative Assets | |
Fair value of commodity derivative contracts | $141 |
Amounts not offset in the balance sheet | -141 |
Derivative Liabilities | |
Fair value of commodity derivative contracts | 9,423 |
Amounts not offset in the balance sheet | -141 |
Net Amounts | $9,282 |
LongTerm_Debt_LongTerm_Debt_De
Long-Term Debt - Long-Term Debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Disclosure [Abstract] | ||
8.50% Senior Notes | $900,000 | $900,000 |
Debt premiums, net of amortization | 13,057 | 15,421 |
Revolving bank credit facility | 447,000 | 290,000 |
Total long-term debt | 1,360,057 | 1,205,421 |
Long term debt, less current maturities | $1,360,057 | $1,205,421 |
LongTerm_Debt_LongTerm_Debt_Pa
Long-Term Debt - Long-Term Debt (Parenthetical) (Details) (USD $) | Dec. 31, 2014 | Oct. 24, 2012 | Jun. 10, 2011 |
In Millions, unless otherwise specified | |||
Debt Instrument [Line Items] | |||
Aggregate annual maturities of long-term debt, 2015 | 0 | ||
Aggregate annual maturities of long-term debt, 2016 | 0 | ||
Aggregate annual maturities of long-term debt, 2017 | 0 | ||
Aggregate annual maturities of long-term debt, 2018 | 447 | ||
Aggregate annual maturities of long-term debt, thereafter | 900 | ||
Senior notes interest rate | 8.50% | ||
8.50% Senior Notes, due June 2019 | |||
Debt Instrument [Line Items] | |||
Senior notes interest rate | 8.50% | 8.50% | 8.50% |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||
Dec. 31, 2014 | Oct. 24, 2012 | Jun. 10, 2011 | Dec. 31, 2013 | Nov. 08, 2013 | |
Debt Instrument [Line Items] | |||||
8.50% Senior Notes | $900,000,000 | $900,000,000 | |||
Senior notes interest rate | 8.50% | ||||
Restriction on payment of dividends | 60,000,000 | ||||
Common stock and senior note repurchases | 100,000,000 | ||||
Percentage of hedging contracts | 75.00% | ||||
Adjustment to borrowing base | 0.25 | ||||
Revolving bank credit facility interest rate description | Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (bLIBORb) plus a margin that varies from 1.75% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1.0%, plus applicable margin ranging from 0.75% to 1.75%. | ||||
Leverage ratio | 350.00% | ||||
Current ratio | 100.00% | ||||
Revolving bank credit facility | 447,000,000 | 290,000,000 | |||
Revolving Bank Credit Facility Due November 2018 | |||||
Debt Instrument [Line Items] | |||||
Effective interest rate | 2.90% | ||||
London Interbank Offered Rate (LIBOR) | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 1.00% | ||||
Federal Funds Effective Swap Rate | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 0.50% | ||||
Minimum | |||||
Debt Instrument [Line Items] | |||||
Unused portion of the borrowing base commitment fee | 0.38% | ||||
Minimum | London Interbank Offered Rate (LIBOR) | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 1.75% | ||||
Minimum | London Interbank Offered Rate Additional Applicable Margin | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 0.75% | ||||
Maximum | |||||
Debt Instrument [Line Items] | |||||
Unused portion of the borrowing base commitment fee | 0.50% | ||||
Maximum | London Interbank Offered Rate (LIBOR) | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 2.75% | ||||
Maximum | London Interbank Offered Rate Additional Applicable Margin | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, basis spread on variable rate | 1.75% | ||||
8.50% Senior Notes, due June 2019 | |||||
Debt Instrument [Line Items] | |||||
8.50% Senior Notes | 300,000,000 | 600,000,000 | |||
Debt issuance, premium percentage | 106.00% | ||||
Senior notes interest rate | 8.50% | 8.50% | 8.50% | ||
Senior notes maturity date | 15-Jun-19 | 15-Jun-19 | |||
Net proceeds after fees and expenses | 312,000,000 | 593,500,000 | |||
Effective interest rate | 8.40% | 7.70% | |||
Senior notes payment terms | semi-annually in arrears on June 15 and December 15 of each year | ||||
Estimated senior notes fair value | 594,000,000 | 962,500,000 | |||
Revolving Bank Credit Facility Due November 2018 | |||||
Debt Instrument [Line Items] | |||||
Revolving bank credit facility maximum lender commitment | 1,200,000,000 | ||||
Credit agreement expiration date | 8-Nov-18 | ||||
Revolving bank credit facility borrowing base | 750,000,000 | ||||
Revolving bank credit facility | 447,000,000 | 290,000,000 | |||
Letters of credit outstanding | 600,000 | 400,000 | |||
Revolving Bank Credit Facility Due November 2018 | Letter of Credit | |||||
Debt Instrument [Line Items] | |||||
Revolving bank credit facility maximum lender commitment | $300,000,000 |
Fair_Value_Measurements_Schedu
Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Senior Notes (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | $141 | |
Derivative liabilities | 9,423 | |
Fair Value, Inputs, Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | 141 | |
8.50% Senior Notes | 594,000 | 962,460 |
Derivative liabilities | 9,423 | |
Revolving bank credit facility | $447,000 | $290,000 |
Fair_Value_Measurements_Additi
Fair Value Measurements - Additional Information (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Carrying value of senior notes | $900,000 | $900,000 |
Revolving bank credit facility | 447,000 | 290,000 |
Fair Value, Inputs, Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Revolving bank credit facility | $447,000 | $290,000 |
Equity_Structure_and_Transacti1
Equity Structure and Transactions - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Equity Structure And Transactions [Line Items] | |||
Preferred stock, shares authorized | 20,000,000 | 20,000,000 | |
Preferred stock, par value | $0.00 | $0.00 | |
Preferred stock, issued | 0 | 0 | |
Cash dividends paid | $30,260 | $58,846 | $82,832 |
Common Stock, Regular | |||
Equity Structure And Transactions [Line Items] | |||
Paid cash dividends, per share | $0.40 | $0.36 | $0.32 |
Common Stock, Special | |||
Equity Structure And Transactions [Line Items] | |||
Paid cash dividends, per share | $0.42 | $0.79 | |
Cash dividends paid | $31,800 | $59,000 |
Incentive_Compensation_Plan_an1
Incentive Compensation Plan and Directors Compensation Plan - Additional Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Compensation Plan [Line Items] | |||
Share based compensation performance awards grant performance period | 10 years | ||
Annual incentive awards payment period | 90 days | ||
Percentage of restricted stock units granted not subject to performance criteria | 3.00% | ||
Expected vesting month and year | 2014-12 | ||
Cash based compensation payment period | 75 days | ||
2014 Annual Incentive Plan Award | Chief Executive Officer | |||
Compensation Plan [Line Items] | |||
Common stock pre-determined price per share | 14.66 | ||
Directors Compensation Plan Share-Based Awards | Restricted Shares | |||
Compensation Plan [Line Items] | |||
Vesting rights description | Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. | ||
Grant vesting period | 3 years | 3 years | 3 years |
Adjusted EBITDA and Adjusted EBITDA Margin | |||
Compensation Plan [Line Items] | |||
Restricted stock units earning per share, minimum | 0.00% | 0.00% | |
Restricted stock units earning per share, maximum | 100.00% | 150.00% | |
Shareholder bReturn bPerformance bStock bAwards | |||
Compensation Plan [Line Items] | |||
Restricted stock units earning per share, minimum | 0.00% | 0.00% | |
Restricted stock units earning per share, maximum | 200.00% | 150.00% | |
Earnings Per Share Targets | |||
Compensation Plan [Line Items] | |||
Restricted stock units earning per share, minimum | 0.00% | ||
Restricted stock units earning per share, maximum | 100.00% |
ShareBased_and_CashBased_Incen2
Share-Based and Cash-Based Incentive Compensation - Additional Information (Details) (USD $) | 12 Months Ended | 3 Months Ended | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Common stock available for award under plans | 4,790,082 | |||
Additional shares authorized under share based compensation arrangements | 4,000,000 | |||
Common Stock | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Unrecognized share-based compensation expense | 0.1 | |||
Recognition period for unrecognized compensation expense | 2015-02 | |||
Chief Executive Officer | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of shares granted | 42,547 | |||
Number of shares issued | 42,547 | |||
Directors Compensation Plan | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Common stock available for award under plans | 500,564 | |||
Restricted Shares | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Shares granted, grant date fair value | 0.3 | 0.3 | 0.4 | |
Shares vested, vested date fair value | 0.3 | 0.4 | 0.5 | |
Number of shares granted | 18,815 | 27,450 | 21,954 | |
Unrecognized share-based compensation expense | 0.5 | |||
Recognition period for unrecognized compensation expense | 2017-04 | |||
Restricted Stock Units (RSUs) | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Shares granted, grant date fair value | 20.1 | 12.8 | 14.3 | |
Shares vested, vested date fair value | 2 | 7.2 | 20 | |
Expected volatility, minimum | 30.00% | 33.00% | ||
Expected volatility, maximum | 63.00% | 74.00% | ||
Adjusted EBITDA | 40.00% | |||
Adjusted EBITDA margin | 30.00% | |||
TSR ranking | 30.00% | 30.00% | ||
TSR ranking for each of three-year performance periods | 10.00% | 10.00% | ||
EPS comprised | 70.00% | |||
Number of shares granted | 1,195,388 | 969,919 | 764,654 | |
Unrecognized share-based compensation expense | 16.5 | |||
Recognition period for unrecognized compensation expense | 2016-11 | |||
Restricted Stock Units (RSUs) | London Interbank Offered Rate (LIBOR) | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Risk-free interest rate, minimum | 0.27% | 0.15% | ||
Risk-free interest rate, maximum | 0.91% | 0.72% | ||
Restricted Stock Units (RSUs) | Minimum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Expected dividend yield | 0.00% | 0.00% | ||
Correlation of movement of total shareholder return | -84.00% | -67.00% | ||
Restricted Stock Units (RSUs) | Maximum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Expected dividend yield | 3.10% | 2.50% | ||
Correlation of movement of total shareholder return | 95.00% | 94.00% |
ShareBased_and_CashBased_Incen3
Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) (Restricted Shares, USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Restricted Shares | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Nonvested, beginning of period | 43,840 | 43,687 | 51,870 |
Granted | 18,815 | 27,450 | 21,954 |
Vested | -19,445 | -27,297 | -27,475 |
Forfeited | -2,662 | ||
Nonvested, end of period | 43,210 | 43,840 | 43,687 |
Weighted Average Grant Date Value, Beginning of period | $15.96 | $18.69 | $15.81 |
Weighted Average Grant Date Fair Value, Granted | $18.60 | $12.75 | $19.13 |
Weighted Average Grant Date Fair Value, Vested | $18 | $17.09 | $13.59 |
Weighted Average Grant Date Fair Value, Forfeited | $18.78 | ||
Weighted Average Grant Date Value, End of period | $16.20 | $15.96 | $18.69 |
ShareBased_and_CashBased_Incen4
Share-Based and Cash-Based Incentive Compensation - Outstanding Restricted Shares Issued to Non-employee Directors (Details) (Restricted Shares) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 43,210 | 43,840 | 43,687 | 51,870 |
2015 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 21,520 | |||
2016 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 15,420 | |||
2017 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 6,270 |
ShareBased_and_CashBased_Incen5
Share-Based and Cash-Based Incentive Compensation - Summary of Share Activity Related to Restricted Stock Units (Details) (Restricted Stock Units (RSUs), USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Restricted Stock Units (RSUs) | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Nonvested, beginning of period | 1,331,753 | 969,820 | 1,732,703 |
Granted | 1,195,388 | 969,919 | 764,654 |
Vested | -354,692 | -468,925 | -1,198,208 |
Forfeited | -195,114 | -139,061 | -329,329 |
Nonvested, end of period | 1,977,335 | 1,331,753 | 969,820 |
Weighted Average Grant Date Value, Beginning of period | $14.96 | $22.70 | $14.67 |
Weighted Average Grant Date Fair Value, Granted | $16.84 | $13.23 | $18.64 |
Weighted Average Grant Date Fair Value, Vested | $18.59 | $26.93 | $9.36 |
Weighted Average Grant Date Fair Value, Forfeited | $16.53 | $16.50 | $19.56 |
Weighted Average Grant Date Value, End of period | $15.29 | $14.96 | $22.70 |
ShareBased_and_CashBased_Incen6
Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Details) (Restricted Stock Units (RSUs)) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Awards expected to vest by period | 1,977,335 | 1,331,753 | 969,820 | 1,732,703 | |
2015 | Restricted Stock Units subject to service requirements | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Awards expected to vest by period | 759,234 | ||||
2015 | Restricted Stock Units subject to service and other requirements | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Awards expected to vest by period | 90,105 | [1] | |||
2016 | Restricted Stock Units subject to service requirements | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Awards expected to vest by period | 1,127,996 | ||||
[1] | In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted. |
ShareBased_and_CashBased_Incen7
Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Parenthetical) (Details) (Restricted Stock Units (RSUs), 2015, Restricted Stock Units subject to service and other requirements) | 12 Months Ended |
Dec. 31, 2014 | |
Restricted Stock Units (RSUs) | 2015 | Restricted Stock Units subject to service and other requirements | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Restricted stock units adjustments, percentage | 0.00% |
Restricted stock units adjustments, percentage | 200.00% |
ShareBased_and_CashBased_Incen8
Share-Based and Cash-Based Incentive Compensation - Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | $14,744 | $11,525 | $12,398 |
Tax benefit computed at the statutory rate | 5,160 | 4,034 | 4,339 |
Restricted Shares | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | 369 | 397 | 399 |
Restricted Stock Units (RSUs) | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | 13,150 | 11,128 | 11,999 |
Common Stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | $1,225 |
ShareBased_and_CashBased_Incen9
Share-Based and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ||||||
Share-based compensation charged to operating income | $14,744 | $11,525 | $12,398 | |||
Total charged to operating income | 24,979 | 23,824 | 22,743 | |||
General and Administrative | ||||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ||||||
Share-based compensation charged to operating income | 14,744 | [1] | 11,525 | [1] | 12,398 | [1] |
Cash-based incentive compensation charged to operating income | 6,950 | [1] | 8,817 | [1] | 6,558 | [1] |
Lease Operating Expense | ||||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ||||||
Cash-based incentive compensation charged to operating income | $3,285 | $3,482 | $3,787 | |||
[1] | Reclassified $0.7 million from cash-based incentive compensation expense to share-based compensation expense in 2014 related to the CEObs 2013 award. |
Recovered_Sheet1
Share-Based and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense (Parenthetical) (Details) (CEO's 2013 Award, USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
CEO's 2013 Award | |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |
Reclassification of incentive compensation | $0.70 |
Employee_Benefit_Plan_Addition
Employee Benefit Plan - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Compensation And Retirement Disclosure [Abstract] | |||
Percentage of matching contribution of each participants | 100.00% | 100.00% | 100.00% |
Maximum contribution percentage of participating employees | 6.00% | 6.00% | 6.00% |
Year of service on which employer's matching contribution under 401K plan will be 100% vested | 5 years | ||
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage | 20.00% | ||
Company's contribution to 401K plan | $2.40 | $2.10 | $2.10 |
Income_Taxes_Components_of_Inc
Income Taxes - Components of Income Tax Expense (Benefit) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||
Current | $301 | ($2,146) | ($40,562) |
Deferred | -4,760 | 30,920 | 88,109 |
Income tax expense (benefit) | ($4,459) | $28,774 | $47,547 |
Income_Taxes_Reconciliation_of
Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount [Abstract] | |||
Income tax expense (benefit) at the federal statutory rate | ($5,642) | $28,033 | $41,836 |
Qualified domestic production activities | 4,256 | ||
State income taxes | 263 | 343 | 750 |
Other | 920 | 398 | 705 |
Income tax expense (benefit) | ($4,459) | $28,774 | $47,547 |
Income tax expense (benefit) at the federal statutory rate, tax rate | 35.00% | 35.00% | 35.00% |
Qualified domestic production activities, tax rate | 3.50% | ||
State income taxes, tax rate | -1.60% | 0.40% | 0.70% |
Other, tax rate | -5.70% | 0.50% | 0.60% |
Effective income tax rate, total | 27.70% | 35.90% | 39.80% |
Income_Taxes_Significant_Compo
Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred tax liabilities: | ||
Property and equipment | $518,566 | $422,805 |
Other | 5,019 | 3,602 |
Total deferred tax liabilities | 523,585 | 426,407 |
Deferred tax assets: | ||
Alternative minimum tax credit | 20,486 | 20,486 |
Asset retirement obligations | 137,597 | 124,863 |
Federal net operating losses | 180,024 | 91,472 |
State net operating losses | 5,008 | 5,028 |
Derivatives | 3,270 | |
Valuation allowance (state) | -4,255 | -4,490 |
Accrued cash-based bonus | 3,559 | 3,873 |
Stock-based compensation | 5,042 | 3,703 |
Other | 798 | 643 |
Total deferred tax assets | 348,259 | 248,848 |
Net deferred tax liabilities | $175,326 | $177,559 |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||
Cash paid for income taxes | $3,000 | $16,056 | |
Unrecognized tax benefits | 9,482 | 9,482 | |
Proceeds from income tax refunds | 3,000 | 59,126 | 479 |
Income taxes | $3,120 | ||
Minimum | |||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||
Tax years under examination | 2010 | ||
Maximum | |||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||
Tax years under examination | 2014 |
Income_Taxes_Net_Operating_Los
Income Taxes - Net Operating Loss and Tax Credit Carryovers (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Internal Revenue Service (IRS) | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | 516,393 |
Internal Revenue Service (IRS) | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | 31-Dec-32 |
Internal Revenue Service (IRS) | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | 31-Dec-34 |
State and Local Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | 99,656 |
State and Local Jurisdiction | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | 31-Dec-21 |
State and Local Jurisdiction | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | 31-Dec-29 |
Alternative Minimum Tax Credit | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward | 12,091 |
Tax credit carryforward, expiration year description | Indefinite |
General Business Tax Credit Carryforward | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward | 406 |
General Business Tax Credit Carryforward | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward, expiration year | 31-Dec-27 |
General Business Tax Credit Carryforward | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward, expiration year | 31-Dec-28 |
Income_Taxes_Balances_and_Chan
Income Taxes - Balances and Changes in Uncertain Tax Positions (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2014 |
Income Tax Disclosure [Abstract] | ||
Balance, beginning of period | $9,482 | |
Increases related to carryback positions | 9,482 | |
Balance, end of period | $9,482 | $9,482 |
Earnings_Per_Share_Schedule_of
Earnings Per Share - Schedule of Calculation of Basic and Diluted Earnings Per Common Share (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Earnings Per Share, Basic and Diluted [Abstract] | |||||||||||||||||||
Net income (loss) | ($33,371) | $684 | $9,837 | $11,189 | ($11,886) | [1],[2] | $14,194 | [1],[2] | $22,396 | [1],[2] | $26,618 | [1],[2] | ($11,661) | $51,322 | $71,984 | ||||
Less portion allocated to nonvested shares | 269 | 303 | 983 | ||||||||||||||||
Net income (loss) allocated to common shares | ($11,930) | $51,019 | $71,001 | ||||||||||||||||
Weighted average common shares outstanding | 75,609 | 75,239 | 74,354 | ||||||||||||||||
Basic and diluted earnings (loss) per common share | ($0.44) | [1] | $0.01 | [1] | $0.13 | [1] | $0.15 | [1] | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | ($0.16) | $0.68 | $0.95 |
Shares excluded due to being anti-dilutive (weighted-average) | 29 | 1,923 | |||||||||||||||||
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | ||||||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. |
Supplemental_Cash_Flow_Informa2
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Supplemental Cash Flow Elements [Abstract] | ||||||
Cash paid for interest, net of interest capitalized of $8,526 in 2014, $10,058 in 2013 and $13,274 in 2012 | $77,607 | $73,909 | $46,247 | |||
Cash paid for income taxes | 3,000 | 16,056 | ||||
Cash refunds received for income taxes | 3,000 | 59,126 | 479 | |||
Cash paid for share-based compensation | 431 | [1] | 466 | [1] | 1,531 | [1] |
Cash tax benefit related to share-based compensation | $0 | [2] | $0 | [2] | $5,962 | [2] |
[1] | The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements. | |||||
[2] | The cash tax benefit for share-based compensation is attributable to tax deductions for vested restricted shares, vested RSUs, dividends paid on unvested restricted stock and dividend equivalents paid on RSUs. For 2014 and 2013, no cash tax benefit was realized as the Company had a tax loss for that year and all carrybacks had previously been utilized. |
Supplemental_Cash_Flow_Informa3
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Parenthetical) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid, interest capitalized | $8,526 | $10,058 | $13,274 |
Commitments_Additional_Informa
Commitments - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commitments [Line Items] | |||
Minimum future lease payments due under noncancelable operating leases, 2015 | $1.50 | ||
Minimum future lease payments due under noncancelable operating leases, 2016 | 1.6 | ||
Minimum future lease payments due under noncancelable operating leases, 2017 | 1.6 | ||
Minimum future lease payments due under noncancelable operating leases, 2018 | 1.7 | ||
Minimum future lease payments due under noncancelable operating leases, thereafter | 7.5 | ||
Total rent expense | 3.2 | 2.6 | 1.7 |
Security amount requirement | 64 | ||
Additional security requirements for 2015 | 9 | ||
Additional security requirements for 2016 | 6 | ||
Additional security requirements for 2017 | 4 | ||
Additional security requirements for 2018 | 5 | ||
Additional security requirements for 2019 to 2023 | 15 | ||
Total security requirement | 103 | ||
Lease expiration date | 31-Dec-23 | ||
Expenses related to bonds | 4.1 | 5 | 2.9 |
Other commitments | 5.8 | ||
Future estimated costs, 2016 | 5.8 | ||
Future estimated costs, 2017 | 5.4 | ||
Future estimated costs, 2018 | 5.2 | ||
Future estimated costs, thereafter | 32.9 | ||
Drilling Rig Commitments | |||
Commitments [Line Items] | |||
Minimum future lease payments due under noncancelable operating leases, 2014 | 12.6 | ||
Helix Well Containment Group | |||
Commitments [Line Items] | |||
Other commitments | 2.1 | ||
Future estimated costs, 2016 | 2.1 | ||
Other commitment | |||
Commitments [Line Items] | |||
Security requirement minimum | 74 | ||
Security requirement maximum | $94 |
Related_Parties_Additional_Inf
Related Parties - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Airplane Services | |||
Related Party Transaction [Line Items] | |||
Related party transactions | $0.90 | $1.20 | $1 |
Directional Drilling Services | |||
Related Party Transaction [Line Items] | |||
Related party transactions | 0.2 | 0.2 | 0.7 |
Minimum | Marine Transportation and Logistic Services | |||
Related Party Transaction [Line Items] | |||
Related party transactions | $0.20 | $0.20 | $0.20 |
Contingencies_Additional_Infor
Contingencies - Additional Information (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Jan. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 15, 2014 | Dec. 31, 2010 | |
Loss Contingencies [Line Items] | |||||||
Underpayment of royalties | $30,000 | ||||||
Under payment percentage of total royalty payments | 0.00% | ||||||
Statutory fine payment relative to underpayment | 2,300,000 | ||||||
Loss contingency, range of possible loss, minimum | 0 | ||||||
Loss contingency, range of possible loss, maximum | 32,000,000 | ||||||
Insurance claims submitted for removal-of-wreck expenses | 43,000,000 | ||||||
Notified disallowed amount in reductions taken by ONRR | 4,700,000 | ||||||
Settlement of lawsuits, fines, penalties and other | 400,000 | 500,000 | 9,300,000 | ||||
Liability loss contingency | 100,000 | 200,000 | |||||
Liberty Mutual Insurance Co | |||||||
Loss Contingencies [Line Items] | |||||||
Insurance claims received | 5,000,000 | ||||||
Revised estimate | |||||||
Loss Contingencies [Line Items] | |||||||
Insurance claims receivable | 31,000,000 | ||||||
Comprehensive General Liability policy | |||||||
Loss Contingencies [Line Items] | |||||||
Insurance claims received | 1,000,000 | ||||||
Energy Package | |||||||
Loss Contingencies [Line Items] | |||||||
Insurance claims received | 1,000,000 | ||||||
Starr Marine | |||||||
Loss Contingencies [Line Items] | |||||||
Insurance claims received | $5,000,000 |
Selected_Quarterly_Financial_D2
Selected Quarterly Financial Data (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Revenues | $196,677 | $234,521 | $262,994 | $254,516 | $244,928 | [1],[2] | $244,555 | [1],[2] | $235,383 | [1],[2] | $259,222 | [1],[2] | $948,708 | $984,088 | $874,491 | ||||
Operating income (loss) | -30,543 | 20,983 | 34,403 | 37,225 | 622 | [1],[2] | 31,965 | [1],[2] | 53,823 | [1],[2] | 60,321 | [1],[2] | 62,068 | 146,731 | 169,310 | ||||
Net income (loss) | ($33,371) | $684 | $9,837 | $11,189 | ($11,886) | [1],[2] | $14,194 | [1],[2] | $22,396 | [1],[2] | $26,618 | [1],[2] | ($11,661) | $51,322 | $71,984 | ||||
Basic and diluted earnings (loss) per common share | ($0.44) | [1] | $0.01 | [1] | $0.13 | [1] | $0.15 | [1] | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | ($0.16) | $0.68 | $0.95 |
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | ||||||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. |
Selected_Quarterly_Financial_D3
Selected Quarterly Financial Data (Parenthetical) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2014 |
MMcf | MMcf | ||
Quarterly Financial Data [Line Items] | |||
One-time increase in production | 2,600 | 1,900 | |
Natural Gas | |||
Quarterly Financial Data [Line Items] | |||
Adjustment to depreciation, depletion, amortization and accretion | 7.1 | $5 | |
Reduction in net income | 4.6 | $3.20 |
Supplemental_Guarantor_Informa2
Supplemental Guarantor Information - Additional Information (Details) | Dec. 31, 2014 |
Debt Disclosure [Abstract] | |
Senior notes interest rate | 8.50% |
Percentage of subsidiaries owned | 100.00% |
Supplemental_Guarantor_Informa3
Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Current assets: | ||||
Cash and cash equivalents | $23,666 | $15,800 | $12,245 | $4,512 |
Receivables: | ||||
Oil and natural gas sales | 67,242 | 96,752 | ||
Joint interest and other | 43,645 | 31,104 | ||
Total receivables | 110,887 | 127,856 | ||
Deferred income taxes | 11,662 | 584 | ||
Prepaid expenses and other assets | 36,347 | 29,362 | ||
Total current assets | 182,562 | 173,602 | ||
Property and equipment - at cost: | ||||
Oil and natural gas properties and equipment | 8,045,666 | 7,339,097 | ||
Furniture, fixtures and other | 23,269 | 21,431 | ||
Total property and equipment | 8,068,935 | 7,360,528 | ||
Less accumulated depreciation, depletion and amortization | 5,575,078 | 5,084,704 | ||
Net property and equipment | 2,493,857 | 2,275,824 | ||
Restricted deposits for asset retirement obligations | 15,444 | 37,421 | ||
Other assets | 17,244 | 20,455 | ||
Total assets | 2,709,107 | 2,507,302 | ||
Current liabilities: | ||||
Accounts payable | 194,109 | 145,212 | ||
Undistributed oil and natural gas proceeds | 37,009 | 42,107 | ||
Asset retirement obligations | 36,003 | 77,785 | ||
Accrued liabilities | 17,377 | 28,000 | ||
Total current liabilities | 284,498 | 293,104 | ||
Long-term debt, less current maturities | 1,360,057 | 1,205,421 | ||
Asset retirement obligations, less current portion | 354,565 | 276,637 | ||
Deferred income taxes | 186,988 | 178,142 | ||
Other liabilities | 13,691 | 13,388 | ||
Shareholders' equity: | ||||
Common stock | 1 | 1 | ||
Additional paid-in capital | 414,580 | 403,564 | ||
Retained earnings | 118,894 | 161,212 | ||
Treasury stock, at cost | -24,167 | -24,167 | ||
Total shareholders' equity | 509,308 | 540,610 | 541,187 | 544,574 |
Total liabilities and shareholders' equity | 2,709,107 | 2,507,302 | ||
Parent Company | ||||
Current assets: | ||||
Cash and cash equivalents | 23,666 | 15,800 | 12,245 | 4,512 |
Receivables: | ||||
Oil and natural gas sales | 41,820 | 61,373 | ||
Joint interest and other | 142,885 | 123,595 | ||
Total receivables | 184,705 | 184,968 | ||
Deferred income taxes | 9,797 | 584 | ||
Prepaid expenses and other assets | 28,728 | 23,090 | ||
Total current assets | 246,896 | 224,442 | ||
Property and equipment - at cost: | ||||
Oil and natural gas properties and equipment | 6,038,915 | 5,667,389 | ||
Furniture, fixtures and other | 23,269 | 21,431 | ||
Total property and equipment | 6,062,184 | 5,688,820 | ||
Less accumulated depreciation, depletion and amortization | 4,442,899 | 4,166,359 | ||
Net property and equipment | 1,619,285 | 1,522,461 | ||
Restricted deposits for asset retirement obligations | 15,444 | 37,421 | ||
Other assets | 974,049 | 951,203 | ||
Total assets | 2,855,674 | 2,735,527 | ||
Current liabilities: | ||||
Accounts payable | 188,654 | 144,492 | ||
Undistributed oil and natural gas proceeds | 36,130 | 41,735 | ||
Asset retirement obligations | 30,711 | 65,329 | ||
Accrued liabilities | 17,437 | 28,000 | ||
Total current liabilities | 272,932 | 279,556 | ||
Long-term debt, less current maturities | 1,360,057 | 1,205,421 | ||
Asset retirement obligations, less current portion | 235,876 | 189,507 | ||
Deferred income taxes | 59,616 | 79,424 | ||
Other liabilities | 417,885 | 441,009 | ||
Shareholders' equity: | ||||
Common stock | 1 | 1 | ||
Additional paid-in capital | 414,580 | 403,564 | ||
Retained earnings | 118,894 | 161,212 | ||
Treasury stock, at cost | -24,167 | -24,167 | ||
Total shareholders' equity | 509,308 | 540,610 | ||
Total liabilities and shareholders' equity | 2,855,674 | 2,735,527 | ||
Guarantor Subsidiaries | ||||
Receivables: | ||||
Oil and natural gas sales | 25,422 | 35,379 | ||
Total receivables | 25,422 | 35,379 | ||
Deferred income taxes | 1,865 | |||
Prepaid expenses and other assets | 7,619 | 6,272 | ||
Total current assets | 34,906 | 41,651 | ||
Property and equipment - at cost: | ||||
Oil and natural gas properties and equipment | 2,006,751 | 1,671,708 | ||
Total property and equipment | 2,006,751 | 1,671,708 | ||
Less accumulated depreciation, depletion and amortization | 1,132,179 | 918,345 | ||
Net property and equipment | 874,572 | 753,363 | ||
Other assets | 349,912 | 479,820 | ||
Total assets | 1,259,390 | 1,274,834 | ||
Current liabilities: | ||||
Accounts payable | 5,455 | 720 | ||
Undistributed oil and natural gas proceeds | 879 | 372 | ||
Asset retirement obligations | 5,292 | 12,456 | ||
Accrued liabilities | 99,180 | 92,491 | ||
Total current liabilities | 110,806 | 106,039 | ||
Asset retirement obligations, less current portion | 118,689 | 87,130 | ||
Deferred income taxes | 127,372 | 98,718 | ||
Shareholders' equity: | ||||
Additional paid-in capital | 703,440 | 784,104 | ||
Retained earnings | 199,083 | 198,843 | ||
Total shareholders' equity | 902,523 | 982,947 | ||
Total liabilities and shareholders' equity | 1,259,390 | 1,274,834 | ||
Eliminations | ||||
Receivables: | ||||
Joint interest and other | -99,240 | -92,491 | ||
Total receivables | -99,240 | -92,491 | ||
Total current assets | -99,240 | -92,491 | ||
Property and equipment - at cost: | ||||
Other assets | -1,306,717 | -1,410,568 | ||
Total assets | -1,405,957 | -1,503,059 | ||
Current liabilities: | ||||
Accrued liabilities | -99,240 | -92,491 | ||
Total current liabilities | -99,240 | -92,491 | ||
Other liabilities | -404,194 | -427,621 | ||
Shareholders' equity: | ||||
Additional paid-in capital | -703,440 | -784,104 | ||
Retained earnings | -199,083 | -198,843 | ||
Total shareholders' equity | -902,523 | -982,947 | ||
Total liabilities and shareholders' equity | ($1,405,957) | ($1,503,059) |
Supplemental_Guarantor_Informa4
Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Condensed Income Statements Captions [Line Items] | |||||||||||||||
Revenues | $196,677 | $234,521 | $262,994 | $254,516 | $244,928 | [1],[2] | $244,555 | [1],[2] | $235,383 | [1],[2] | $259,222 | [1],[2] | $948,708 | $984,088 | $874,491 |
Operating costs and expenses: | |||||||||||||||
Lease operating expenses | 264,751 | 270,839 | 232,260 | ||||||||||||
Production taxes | 7,932 | 7,135 | 5,840 | ||||||||||||
Gathering and transportation | 19,821 | 17,510 | 14,878 | ||||||||||||
Depreciation, depletion and amortization | 490,469 | 430,611 | 336,177 | ||||||||||||
Asset retirement obligations accretion | 20,633 | 20,918 | 20,055 | ||||||||||||
General and administrative expenses | 86,999 | 81,874 | 82,017 | ||||||||||||
Derivative (gain) loss | -3,965 | 8,470 | 13,954 | ||||||||||||
Total costs and expenses | 886,640 | 837,357 | 705,181 | ||||||||||||
Operating income | -30,543 | 20,983 | 34,403 | 37,225 | 622 | [1],[2] | 31,965 | [1],[2] | 53,823 | [1],[2] | 60,321 | [1],[2] | 62,068 | 146,731 | 169,310 |
Interest expense: | |||||||||||||||
Incurred | 86,922 | 85,639 | 63,268 | ||||||||||||
Capitalized | -8,526 | -10,058 | -13,274 | ||||||||||||
Other income, net | 208 | 8,946 | 215 | ||||||||||||
Income (loss) before income tax expense (benefit) | -16,120 | 80,096 | 119,531 | ||||||||||||
Income tax expense (benefit) | -4,459 | 28,774 | 47,547 | ||||||||||||
Net income (loss) | -33,371 | 684 | 9,837 | 11,189 | -11,886 | [1],[2] | 14,194 | [1],[2] | 22,396 | [1],[2] | 26,618 | [1],[2] | -11,661 | 51,322 | 71,984 |
Parent Company | |||||||||||||||
Condensed Income Statements Captions [Line Items] | |||||||||||||||
Revenues | 592,460 | 631,267 | 539,958 | ||||||||||||
Operating costs and expenses: | |||||||||||||||
Lease operating expenses | 179,344 | 202,096 | 168,033 | ||||||||||||
Production taxes | 7,932 | 7,135 | 5,840 | ||||||||||||
Gathering and transportation | 11,712 | 9,248 | 10,197 | ||||||||||||
Depreciation, depletion and amortization | 276,636 | 236,600 | 187,039 | ||||||||||||
Asset retirement obligations accretion | 10,981 | 14,218 | 14,979 | ||||||||||||
General and administrative expenses | 48,084 | 44,040 | 45,260 | ||||||||||||
Derivative (gain) loss | -3,965 | 8,470 | 13,954 | ||||||||||||
Total costs and expenses | 530,724 | 521,807 | 445,302 | ||||||||||||
Operating income | 61,736 | 109,460 | 94,656 | ||||||||||||
Earnings of affiliates | 240 | 24,400 | 49,799 | ||||||||||||
Interest expense: | |||||||||||||||
Incurred | 84,460 | 82,570 | 60,778 | ||||||||||||
Capitalized | -6,064 | -6,989 | -10,784 | ||||||||||||
Other income, net | 208 | 8,946 | 215 | ||||||||||||
Income (loss) before income tax expense (benefit) | -16,212 | 67,225 | 94,676 | ||||||||||||
Income tax expense (benefit) | -4,551 | 15,903 | 22,692 | ||||||||||||
Net income (loss) | -11,661 | 51,322 | 71,984 | ||||||||||||
Guarantor Subsidiaries | |||||||||||||||
Condensed Income Statements Captions [Line Items] | |||||||||||||||
Revenues | 356,248 | 352,821 | 334,533 | ||||||||||||
Operating costs and expenses: | |||||||||||||||
Lease operating expenses | 85,407 | 68,743 | 64,227 | ||||||||||||
Gathering and transportation | 8,109 | 8,262 | 4,681 | ||||||||||||
Depreciation, depletion and amortization | 213,833 | 194,011 | 149,138 | ||||||||||||
Asset retirement obligations accretion | 9,652 | 6,700 | 5,076 | ||||||||||||
General and administrative expenses | 38,915 | 37,834 | 36,757 | ||||||||||||
Total costs and expenses | 355,916 | 315,550 | 259,879 | ||||||||||||
Operating income | 332 | 37,271 | 74,654 | ||||||||||||
Interest expense: | |||||||||||||||
Incurred | 2,462 | 3,069 | 2,490 | ||||||||||||
Capitalized | -2,462 | -3,069 | -2,490 | ||||||||||||
Income (loss) before income tax expense (benefit) | 332 | 37,271 | 74,654 | ||||||||||||
Income tax expense (benefit) | 92 | 12,871 | 24,855 | ||||||||||||
Net income (loss) | 240 | 24,400 | 49,799 | ||||||||||||
Eliminations | |||||||||||||||
Operating costs and expenses: | |||||||||||||||
Earnings of affiliates | -240 | -24,400 | -49,799 | ||||||||||||
Interest expense: | |||||||||||||||
Income (loss) before income tax expense (benefit) | -240 | -24,400 | -49,799 | ||||||||||||
Net income (loss) | ($240) | ($24,400) | ($49,799) | ||||||||||||
[1] | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. | ||||||||||||||
[2] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (bMMBtub) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).B The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. B The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.B We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013. |
Supplemental_Guarantor_Informa5
Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating activities: | |||
Net income (loss) | ($11,661) | $51,322 | $71,984 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 511,102 | 451,529 | 356,232 |
Amortization of debt issuance costs and premium | 701 | 1,645 | 2,575 |
Share-based compensation | 14,744 | 11,525 | 12,398 |
Derivative gain (loss) | -3,965 | 8,470 | 13,954 |
Cash payments on derivative settlements, net | -5,318 | -8,589 | -7,664 |
Deferred income taxes | -4,760 | 30,920 | 88,109 |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | 29,510 | 980 | 818 |
Joint interest and other receivables | -4,255 | 34,257 | -28,823 |
Income taxes | 3,143 | 44,328 | -58,011 |
Prepaid expenses and other assets | 15,012 | -10,044 | 7,440 |
Asset retirement obligation settlements | -74,313 | -81,543 | -112,827 |
Accounts payable, accrued liabilities and other | 41,483 | 26,558 | 38,952 |
Net cash provided by operating activities | 511,423 | 561,358 | 385,137 |
Investing activities: | |||
Acquisition of property interest in oil and natural gas properties | -72,234 | -82,424 | -205,550 |
Investment in oil and natural gas properties and equipment | -554,378 | -551,954 | -479,313 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | |
Purchases of furniture, fixtures and other | -3,340 | -1,435 | -3,031 |
Net cash used in investing activities | -629,952 | -614,805 | -657,441 |
Financing activities: | |||
Issuance of 8.50% Senior Notes | 318,000 | ||
Borrowings of long-term debt - revolving bank credit facility | 556,000 | 563,000 | 732,000 |
Repayments of long-term debt - revolving bank credit facility | -399,000 | -443,000 | -679,000 |
Debt issuance costs | -3,892 | -8,510 | |
Dividends to shareholders | -30,260 | -58,846 | -82,832 |
Other | -345 | -260 | 379 |
Net cash provided by financing activities | 126,395 | 57,002 | 280,037 |
Increase in cash and cash equivalents | 7,866 | 3,555 | 7,733 |
Cash and cash equivalents, beginning of period | 15,800 | 12,245 | 4,512 |
Cash and cash equivalents, end of period | 23,666 | 15,800 | 12,245 |
Parent Company | |||
Operating activities: | |||
Net income (loss) | -11,661 | 51,322 | 71,984 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 287,617 | 250,818 | 202,018 |
Amortization of debt issuance costs and premium | 701 | 1,645 | 2,575 |
Share-based compensation | 14,744 | 11,525 | 12,398 |
Derivative gain (loss) | -3,965 | 8,470 | 13,954 |
Cash payments on derivative settlements, net | -5,318 | -8,589 | -7,664 |
Deferred income taxes | -32,456 | 7,564 | 81,653 |
Earnings of affiliates | -240 | -24,400 | -49,799 |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | 19,553 | 6,182 | -3,783 |
Joint interest and other receivables | -4,255 | 34,257 | -28,823 |
Income taxes | 30,747 | 54,813 | -76,411 |
Prepaid expenses and other assets | 25,555 | -25,329 | 9,017 |
Asset retirement obligation settlements | -57,253 | -65,438 | -105,773 |
Accounts payable, accrued liabilities and other | 12,816 | 59,961 | 159,774 |
Net cash provided by operating activities | 276,585 | 362,801 | 281,120 |
Investing activities: | |||
Acquisition of property interest in oil and natural gas properties | -17,407 | -151,429 | |
Investment in oil and natural gas properties and equipment | -312,044 | -349,804 | -375,296 |
Investment in subsidiary | -62,323 | -86,017 | -54,121 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | |
Purchases of furniture, fixtures and other | -3,340 | -1,435 | -3,031 |
Net cash used in investing activities | -395,114 | -416,248 | -553,424 |
Financing activities: | |||
Issuance of 8.50% Senior Notes | 318,000 | ||
Borrowings of long-term debt - revolving bank credit facility | 556,000 | 563,000 | 732,000 |
Repayments of long-term debt - revolving bank credit facility | -399,000 | -443,000 | -679,000 |
Debt issuance costs | -3,892 | -8,510 | |
Dividends to shareholders | -30,260 | -58,846 | -82,832 |
Other | -345 | -260 | 379 |
Net cash provided by financing activities | 126,395 | 57,002 | 280,037 |
Increase in cash and cash equivalents | 7,866 | 3,555 | 7,733 |
Cash and cash equivalents, beginning of period | 15,800 | 12,245 | 4,512 |
Cash and cash equivalents, end of period | 23,666 | 15,800 | 12,245 |
Guarantor Subsidiaries | |||
Operating activities: | |||
Net income (loss) | 240 | 24,400 | 49,799 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 223,485 | 200,711 | 154,214 |
Deferred income taxes | 27,696 | 23,356 | 6,456 |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | 9,957 | -5,202 | 4,601 |
Income taxes | -27,604 | -10,485 | 18,400 |
Prepaid expenses and other assets | 12,882 | -18,835 | -119,895 |
Asset retirement obligation settlements | -17,060 | -16,105 | -7,054 |
Accounts payable, accrued liabilities and other | 5,242 | 717 | -2,504 |
Net cash provided by operating activities | 234,838 | 198,557 | 104,017 |
Investing activities: | |||
Acquisition of property interest in oil and natural gas properties | -54,827 | -82,424 | -54,121 |
Investment in oil and natural gas properties and equipment | -242,334 | -202,150 | -104,017 |
Net cash used in investing activities | -297,161 | -284,574 | -158,138 |
Financing activities: | |||
Investment from parent | 62,323 | 86,017 | 54,121 |
Net cash provided by financing activities | 62,323 | 86,017 | 54,121 |
Eliminations | |||
Operating activities: | |||
Net income (loss) | -240 | -24,400 | -49,799 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Earnings of affiliates | 240 | 24,400 | 49,799 |
Changes in operating assets and liabilities: | |||
Prepaid expenses and other assets | -23,425 | 34,120 | 118,318 |
Accounts payable, accrued liabilities and other | 23,425 | -34,120 | -118,318 |
Investing activities: | |||
Investment in subsidiary | 62,323 | 86,017 | 54,121 |
Net cash used in investing activities | 62,323 | 86,017 | 54,121 |
Financing activities: | |||
Investment from parent | -62,323 | -86,017 | -54,121 |
Net cash provided by financing activities | ($62,323) | ($86,017) | ($54,121) |
Supplemental_Oil_and_Gas_Discl2
Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | |||
Net capitalized cost: | |||
Proved oil and natural gas properties and equipment | $7,924.20 | $7,207.10 | $6,551.50 |
Unproved oil and natural gas properties and equipment | 121.5 | 132 | 143 |
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | -5,557.60 | -5,069.20 | -4,640.80 |
Net capitalized costs related to producing activities | $2,488.10 | $2,269.90 | $2,053.70 |
Supplemental_Oil_and_Gas_Discl3
Supplemental Oil and Gas Disclosures - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Reserve Quantities [Line Items] | |
Percentage non-operated non-producing reserves | 11.00% |
Present value discounted percentage | 10.00% |
Gulf of Mexico | |
Reserve Quantities [Line Items] | |
Percentage of oil, NGLs and natural gas reserves | 69.00% |
Minimum | |
Reserve Quantities [Line Items] | |
Expected time to evaluate properties, in years | 1 year |
Maximum | |
Reserve Quantities [Line Items] | |
Expected time to evaluate properties, in years | 5 years |
Supplemental_Oil_and_Gas_Discl4
Supplemental Oil and Gas Disclosures - Capitalized Costs Not Subject to Amortization (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Costs excluded by year incurred: | ||||
Acquisition costs, Total | $75.50 | |||
Capitalized interest not subject to amortization, Total | 34.3 | |||
Total costs not subject to amortization, Total | 109.8 | |||
Acquisition costs | 2.6 | 5.7 | 7 | 60.2 |
Capitalized interest not subject to amortization | 7.5 | 7.3 | 6.4 | 13.1 |
Total costs not subject to amortization | $10.10 | $13 | $13.40 | $73.30 |
Supplemental_Oil_and_Gas_Discl5
Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Costs incurred: | ||||||
Proved properties acquisitions | $111.50 | [1] | $96.90 | [1] | $239.80 | [1] |
Exploration | 411.1 | [1],[2],[3] | 215.3 | [1],[2],[3] | 151.3 | [1],[2],[3] |
Development | 198.7 | [1] | 352.9 | [1] | 363.7 | [1] |
Unproved property acquisitions | 3.1 | [1],[4] | 26.3 | [1],[4] | 26.5 | [1],[4] |
Total costs incurred in oil and gas property acquisition, exploration and development activities | $724.40 | [1] | $691.40 | [1] | $781.30 | [1] |
[1] | Includes net additions from capitalized ARO of $88.0 million, $50.6 million and $86.9 million during 2014, 2013 and 2012, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. | |||||
[2] | Includes seismic costs of $9.0 million, $8.9 million and $6.2 million incurred during 2014, 2013 and 2012, respectively. | |||||
[3] | Includes geological and geophysical costs charged to expense of $7.3 million, $5.9 million and $6.2 million during 2014, 2013 and 2012, respectively. | |||||
[4] | The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period. |
Supplemental_Oil_and_Gas_Discl6
Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Parenthetical) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Capitalized Costs Oil And Gas Producing Activities Net [Abstract] | |||
Additions (reductions) of asset retirement obligations | $88 | $50.60 | $86.90 |
Seismic costs | 9 | 8.9 | 6.2 |
Geological and geophysical costs | $7.30 | $5.90 | $6.20 |
Supplemental_Oil_and_Gas_Discl7
Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Capitalized Costs Oil And Gas Producing Activities Net [Abstract] | |||
Depreciation, depletion, amortization and accretion per Boe | 28.98 | 25.1 | 20.79 |
Supplemental_Oil_and_Gas_Discl8
Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Details) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
MMBbls | MMBbls | MMBbls | ||||
Oil | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, beginning balance | 58.5 | 54.8 | 51.4 | |||
Revisions of previous estimates | 1.6 | [1] | -4.3 | [2] | -1.1 | [3] |
Extensions and discoveries | 7.3 | [4] | 13.9 | [5] | 8.2 | [6] |
Purchase of minerals in place | 1.5 | [7] | 1.5 | [8] | 2.5 | [9] |
Sales of reserves | -0.4 | [10] | -0.2 | [11] | ||
Production | -7.2 | -7 | -6 | |||
Proved reserves, ending balance | 61.7 | 58.5 | 54.8 | |||
Oil | Proved Developed Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 35.7 | 36.2 | 35.3 | |||
Oil | Proved Undeveloped Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 26 | [12] | 22.3 | 19.5 | ||
NGLs | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, beginning balance | 15.9 | 15.2 | 17.1 | |||
Revisions of previous estimates | 0.1 | [1] | 0.2 | [2] | -2.6 | [3] |
Extensions and discoveries | 0.7 | [4] | 2.6 | [5] | 2.6 | [6] |
Purchase of minerals in place | 1.2 | [7] | 0.2 | [9] | ||
Production | -2.1 | -2.1 | -2.1 | |||
Proved reserves, ending balance | 15.8 | 15.9 | 15.2 | |||
NGLs | Proved Developed Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 10.7 | 11.1 | 11 | |||
NGLs | Proved Undeveloped Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 5.1 | [12] | 4.8 | 4.2 | ||
Natural Gas | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, beginning balance | 259,900 | 285,100 | 289,700 | |||
Revisions of previous estimates | 14,300 | [1] | 2,100 | [2] | -4,800 | [3] |
Extensions and discoveries | 10,100 | [4] | 22,000 | [5] | 29,600 | [6] |
Purchase of minerals in place | 20,700 | [7] | 4,400 | [8] | 25,500 | [9] |
Sales of reserves | -400 | [10] | -1,100 | [11] | ||
Production | -50,100 | -53,300 | -53,800 | |||
Proved reserves, ending balance | 254,900 | 259,900 | 285,100 | |||
Natural Gas | Proved Developed Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 221,100 | 232,700 | 243,500 | |||
Natural Gas | Proved Undeveloped Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 33,800 | [12] | 27,200 | 41,600 | ||
Barrel Equivalent | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, beginning balance | 117.7 | [13] | 117.5 | [13] | 116.9 | [13] |
Revisions of previous estimates | 4.1 | [1],[13] | -3.8 | [13],[2] | -4.6 | [13],[3] |
Extensions and discoveries | 9.7 | [13],[4] | 20.2 | [13],[5] | 15.7 | [13],[6] |
Purchase of minerals in place | 6.1 | [13],[7] | 2.3 | [13],[8] | 7 | [13],[9] |
Sales of reserves | -0.5 | [10],[13] | -0.4 | [11],[13] | ||
Production | -17.6 | [13] | -18 | [13] | -17.1 | [13] |
Proved reserves, ending balance | 120 | [13] | 117.7 | [13] | 117.5 | [13] |
Barrel Equivalent | Proved Developed Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 83.3 | [13] | 86.1 | [13] | 86.9 | [13] |
Barrel Equivalent | Proved Undeveloped Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 36.7 | [12],[13] | 31.6 | [13] | 30.6 | [13] |
Natural Gas Equivalent | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, beginning balance | 705,900,000 | [13] | 705,100,000 | [13] | 701,100,000 | [13] |
Revisions of previous estimates | 25,300,000 | [1],[13] | -22,800,000 | [13],[2] | -27,500,000 | [13],[3] |
Extensions and discoveries | 58,100,000 | [13],[4] | 121,000,000 | [13],[5] | 94,500,000 | [13],[6] |
Purchase of minerals in place | 36,500,000 | [13],[7] | 13,700,000 | [13],[8] | 42,000,000 | [13],[9] |
Sales of reserves | -3,200,000 | [10],[13] | -2,200,000 | [11],[13] | ||
Production | -105,800,000 | [13] | -107,900,000 | [13] | -102,800,000 | [13] |
Proved reserves, ending balance | 720,000,000 | [13] | 705,900,000 | [13] | 705,100,000 | [13] |
Natural Gas Equivalent | Proved Developed Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 499,700,000 | [13] | 516,100,000 | [13] | 521,200,000 | [13] |
Natural Gas Equivalent | Proved Undeveloped Reserves | ||||||
Reserve Quantities [Line Items] | ||||||
Proved reserves, ending balance | 220,300,000 | [12],[13] | 189,800,000 | [13] | 183,900,000 | [13] |
[1] | Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Spraberry field and 2.4 MMBoe at various other fields. | |||||
[2] | Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Spraberry field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. | |||||
[3] | Includes downward revisions due to price of 1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field. | |||||
[4] | Includes extensions and discoveries of 4.1 MMBoe at our Spraberry field and 4.1 MMBoe at our Mississippi Canyon 782 field. | |||||
[5] | Includes extensions and discoveries of 12.6 MMBoe at our Spraberry field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. | |||||
[6] | Includes extensions and discoveries of 11.6 MMBoe at our Spraberry field and extensions and discoveries of 2.7 MMBoe at our High Island 21/22 field. | |||||
[7] | Primarily due to acquiring additional ownership in the Fairway field and acquisition of the Woodside Properties. | |||||
[8] | Primarily due to the acquisition of the Callon Properties. | |||||
[9] | Due to the acquisition of the Newfield Properties. | |||||
[10] | Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. | |||||
[11] | Due to the sale of our interest in the South Timbalier 41 field. | |||||
[12] | We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undeveloped (bPUDsb), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. These PUDs were originally recorded in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020. | |||||
[13] | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. |
Supplemental_Oil_and_Gas_Discl9
Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Parenthetical) (Details) | 12 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||
MMBoe | MMBoe | MMBoe | MMBoe | |||||
Reserve Quantities [Line Items] | ||||||||
Proved undeveloped reserves, that will not be developed with in five years | 1.4 | |||||||
Percentage of proved undeveloped reserves that will be developed with in five years | 96.00% | |||||||
Wells expected to be drilled, year | 2020 | |||||||
Barrel Equivalent | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 4.1 | [1],[2] | -3.8 | [1],[3] | -4.6 | [1],[4] | ||
Extensions and discoveries | 9.7 | [1],[5] | 20.2 | [1],[6] | 15.7 | [1],[7] | ||
Proved reserves | 120 | [1] | 117.7 | [1] | 117.5 | [1] | 116.9 | [1] |
Barrel Equivalent | Proved Undeveloped Reserves | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved reserves | 36.7 | [1],[8] | 31.6 | [1] | 30.6 | [1] | ||
Changes due to price | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.3 | 1.9 | 1.3 | |||||
Changes at the Spraberry field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | -3.9 | -4.9 | -3 | |||||
Extensions and discoveries | 4.1 | 12.6 | 11.6 | |||||
Changes at the High Island 22 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | -2.3 | |||||||
Extensions and discoveries | 2.7 | |||||||
Changes at the Ship Shoal 349/359 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | -1.3 | |||||||
Changes at the Main Pass 98 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.7 | |||||||
Changes at the South Timbalier 314 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.7 | |||||||
Changes at the Main Pass 108 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.6 | |||||||
Changes at the South Timbalier 176 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.5 | |||||||
Changes at the Ship Shoal 349 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Extensions and discoveries | 4.2 | |||||||
Changes at the Mississippi Canyon 698 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Extensions and discoveries | 1.9 | |||||||
Changes at the Fairway field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 2.4 | |||||||
Changes at the Mississippi Canyon 800 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 1.2 | |||||||
Various field positive revisions | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 6.4 | |||||||
Various field negative revisions | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | -2.4 | |||||||
Changes at the Mississippi Canyon 782 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Extensions and discoveries | 4.1 | |||||||
[1] | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. | |||||||
[2] | Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Spraberry field and 2.4 MMBoe at various other fields. | |||||||
[3] | Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Spraberry field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. | |||||||
[4] | Includes downward revisions due to price of 1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field. | |||||||
[5] | Includes extensions and discoveries of 4.1 MMBoe at our Spraberry field and 4.1 MMBoe at our Mississippi Canyon 782 field. | |||||||
[6] | Includes extensions and discoveries of 12.6 MMBoe at our Spraberry field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. | |||||||
[7] | Includes extensions and discoveries of 11.6 MMBoe at our Spraberry field and extensions and discoveries of 2.7 MMBoe at our High Island 21/22 field. | |||||||
[8] | We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undeveloped (bPUDsb), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. These PUDs were originally recorded in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020. |
Recovered_Sheet2
Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Oil | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | 91.12 | 99.65 | 98.13 | 97.36 |
NGLs | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | 34.63 | 35.21 | 47.3 | 51.3 |
Natural Gas | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | 4.27 | 3.8 | 2.77 | 4.11 |
Recovered_Sheet3
Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Millions, unless otherwise specified | ||||
Standardized Measure of Discounted Future Net Cash Flows | ||||
Future cash inflows | $7,258.50 | $7,376.70 | $6,888.40 | |
Production | -2,224.50 | -2,142.80 | -1,858.30 | |
Development | -922 | -1,001.40 | -655.4 | |
Dismantlement and abandonment | -475.4 | -441.6 | -508 | |
Income taxes | -948.4 | -986.9 | -1,002.10 | |
Future net cash inflows before 10% discount | 2,688.20 | 2,804 | 2,864.60 | |
10% annual discount factor | -985.4 | -1,129.40 | -1,018.20 | |
Standardized measure of discounted future net cash flows | $1,702.80 | $1,674.60 | $1,846.40 | $2,006.40 |
Recovered_Sheet4
Supplemental Oil and Gas Disclosures - Schedule of Changes in Standardized Measure (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Changes in Standardized Measure | |||
Changes in Standardized Measure Standardized measure, beginning of year | $1,674.60 | $1,846.40 | $2,006.40 |
Sales and transfers of oil and gas produced, net of production costs | -650.9 | -686.1 | -620.4 |
Net changes in price, net of future production costs | -278.6 | -65.2 | -224.3 |
Extensions and discoveries, net of future production and development costs | 309.6 | 393.8 | 181.9 |
Changes in estimated future development costs | -56.4 | -91.1 | -103.3 |
Previously estimated development costs incurred | 263.1 | 262.1 | 332.9 |
Revisions of quantity estimates | 118.6 | -91.6 | -128.1 |
Accretion of discount | 180.6 | 202.2 | 231.1 |
Net change in income taxes | -11.4 | 56.6 | 99.7 |
Purchases of reserves in-place | 86.7 | 79.6 | 270.2 |
Sales of reserves in-place | -53.1 | -16.1 | |
Changes in production rates due to timing and other | 66.9 | -179 | -183.6 |
Net increase (decrease) in standardized measure | 28.2 | -171.8 | -160 |
Changes in Standardized measure, end of year | $1,702.80 | $1,674.60 | $1,846.40 |