Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Mar. 05, 2014 | Jun. 28, 2013 | |
Document Information [Line Items] | ' | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Trading Symbol | 'WTI | ' | ' |
Entity Registrant Name | 'W&T OFFSHORE INC | ' | ' |
Entity Central Index Key | '0001288403 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
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 | ' | 75,591,699 | ' |
Entity Public Float | ' | ' | $497,201,000 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets: | ' | ' |
Cash and cash equivalents | $15,800 | $12,245 |
Receivables: | ' | ' |
Oil and natural gas sales | 96,752 | 97,733 |
Joint interest and other | 27,984 | 56,439 |
Income tax | 3,120 | 47,884 |
Total receivables | 127,856 | 202,056 |
Prepaid expenses and other assets | 29,946 | 25,822 |
Total current assets | 173,602 | 240,123 |
Property and equipment – at cost: | ' | ' |
Oil and natural gas properties and equipment (full cost method, of which $116,612 at December 31, 2013 and $123,503 at December 31, 2012 were excluded from amortization) | 7,339,097 | 6,694,510 |
Furniture, fixtures and other | 21,431 | 21,786 |
Total property and equipment | 7,360,528 | 6,716,296 |
Less accumulated depreciation, depletion and amortization | 5,084,704 | 4,655,841 |
Net property and equipment | 2,275,824 | 2,060,455 |
Restricted deposits for asset retirement obligations | 37,421 | 28,466 |
Other assets | 20,455 | 19,943 |
Total assets | 2,507,302 | 2,348,987 |
Current liabilities: | ' | ' |
Accounts payable | 145,212 | 123,885 |
Undistributed oil and natural gas proceeds | 42,107 | 37,073 |
Asset retirement obligations | 77,785 | 92,630 |
Accrued liabilities | 28,000 | 21,021 |
Total current liabilities | 293,104 | 274,609 |
Long-term debt, less current maturities | 1,205,421 | 1,087,611 |
Asset retirement obligations, less current portion | 276,637 | 291,423 |
Deferred income taxes | 178,142 | 145,249 |
Other liabilities | 13,388 | 8,908 |
Commitments and contingencies | ' | ' |
Shareholders’ equity: | ' | ' |
Preferred stock, $0.00001 par value, 20,000,000 shares authorized and -0- issued at December 31, 2013 and December 31, 2012 | ' | ' |
Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,460,872 issued and 75,591,699 outstanding at December 31, 2013; 78,118,803 issued and 75,249,630 outstanding at December 31, 2012 | 1 | 1 |
Additional paid-in capital | 403,564 | 396,186 |
Retained earnings | 161,212 | 169,167 |
Treasury stock, at cost | -24,167 | -24,167 |
Total shareholders’ equity | 540,610 | 541,187 |
Total liabilities and shareholders’ equity | $2,507,302 | $2,348,987 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, except Share data, unless otherwise specified | ||
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization | $116,612 | $123,503 |
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 | 78,460,872 | 78,118,803 |
Common stock, outstanding | 75,591,699 | 75,249,630 |
Consolidated_Statements_Of_Inc
Consolidated Statements Of Income (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Revenues | $244,928 | [1] | $244,555 | [1] | $235,383 | [1] | $259,222 | [1] | $237,146 | $185,946 | $215,513 | $235,886 | $984,088 | $874,491 | $971,047 | ||||
Operating costs and expenses: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 270,839 | 232,260 | 219,206 | ||||||||
Production taxes | ' | ' | ' | ' | ' | ' | ' | ' | 7,135 | 5,840 | 4,275 | ||||||||
Gathering and transportation | ' | ' | ' | ' | ' | ' | ' | ' | 17,510 | 14,878 | 16,920 | ||||||||
Depreciation, depletion and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 430,611 | 336,177 | 299,015 | ||||||||
Asset retirement obligation accretion | ' | ' | ' | ' | ' | ' | ' | ' | 20,918 | 20,055 | 29,771 | ||||||||
General and administrative expenses | ' | ' | ' | ' | ' | ' | ' | ' | 81,874 | 82,017 | 74,296 | ||||||||
Derivative (gain) loss | ' | ' | ' | ' | ' | ' | ' | ' | 8,470 | 13,954 | -1,896 | ||||||||
Total costs and expenses | ' | ' | ' | ' | ' | ' | ' | ' | 837,357 | 705,181 | 641,587 | ||||||||
Operating income | 622 | [1] | 31,965 | [1] | 53,823 | [1] | 60,321 | [1] | 46,737 | 7,560 | 99,100 | 15,913 | 146,731 | 169,310 | 329,460 | ||||
Interest expense: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 85,639 | 63,268 | 52,393 | ||||||||
Capitalized | ' | ' | ' | ' | ' | ' | ' | ' | -10,058 | -13,274 | -9,877 | ||||||||
Loss on extinguishment of debt | ' | ' | ' | ' | ' | ' | ' | ' | 128 | ' | 22,694 | ||||||||
Other income | ' | ' | ' | ' | ' | ' | ' | ' | 9,074 | 215 | 84 | ||||||||
Income before income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 80,096 | 119,531 | 264,334 | ||||||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 28,774 | 47,547 | 91,517 | ||||||||
Net income | ($11,886) | [1] | $14,194 | [1] | $22,396 | [1] | $26,618 | [1] | $16,670 | ($1,471) | $53,567 | $3,218 | $51,322 | $71,984 | $172,817 | ||||
Basic and diluted earnings per common share | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | $0.21 | [2] | ($0.02) | [2] | $0.70 | [2] | $0.04 | [2] | $0.68 | $0.95 | $2.29 |
Weighted average common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | 75,239 | 74,354 | 74,033 | ||||||||
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. | ||||||||||||||||||
[2] | 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. |
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, 2010 | $421,743 | ' | ' | $1 | $377,529 | $68,380 | ' | ' | ($24,167) |
Beginning Balances (in shares) at Dec. 31, 2010 | ' | ' | ' | 74,474,000 | ' | ' | ' | ' | 2,869,000 |
Cash dividends | ' | -11,913 | -46,842 | ' | ' | ' | -11,913 | -46,842 | ' |
Share-based compensation | 9,710 | ' | ' | ' | 9,710 | ' | ' | ' | ' |
Stock issued, net of forfeitures, value | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock issued, net of forfeitures, shares | ' | ' | ' | -13,000 | ' | ' | ' | ' | ' |
Shares, RSUs surrendered for payroll taxes, value | -2,073 | ' | ' | ' | -2,073 | ' | ' | ' | ' |
Shares surrendered for payroll taxes, shares | ' | ' | ' | -109,000 | ' | ' | ' | ' | ' |
Other | 1,132 | ' | ' | ' | 1,754 | -622 | ' | ' | ' |
Net income | 172,817 | ' | ' | ' | ' | 172,817 | ' | ' | ' |
Ending Balances at Dec. 31, 2011 | 544,574 | ' | ' | 1 | 386,920 | 181,820 | ' | ' | -24,167 |
Ending 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, value | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | 75,249,630 | ' | ' | 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, value | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 |
Consolidated_Statement_Of_Chan1
Consolidated Statement Of Changes In Shareholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Common Stock, Regular | ' | ' | ' |
Paid cash dividends, per share | $0.36 | $0.32 | $0.16 |
Common Stock, Special | ' | ' | ' |
Paid cash dividends, per share | $0.42 | $0.79 | $0.63 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating activities: | ' | ' | ' |
Net income | $51,322 | $71,984 | $172,817 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Depreciation, depletion, amortization and accretion | 451,529 | 356,232 | 328,786 |
Amortization of debt issuance costs and premium | 1,645 | 2,575 | 2,010 |
Loss on extinguishment of debt | 128 | ' | 22,694 |
Share-based compensation | 11,525 | 12,398 | 9,710 |
Derivative (gain) loss | 8,470 | 13,954 | -1,896 |
Cash payments on derivative settlements (realized) | -8,589 | -7,664 | -9,873 |
Deferred income taxes | 30,920 | 88,109 | 61,835 |
Changes in operating assets and liabilities: | ' | ' | ' |
Oil and natural gas receivables | 980 | 818 | -18,639 |
Joint interest and other receivables | 28,566 | -31,399 | 375 |
Insurance proceeds | 5,691 | 2,576 | 20,771 |
Income taxes | 44,328 | -58,011 | -7,124 |
Prepaid expenses and other assets | -10,044 | 7,440 | -7,809 |
Asset retirement obligations settlements | -81,543 | -112,827 | -59,958 |
Accounts payable and accrued liabilities | 28,132 | 38,026 | 7,881 |
Other | -1,702 | 926 | -102 |
Net cash provided by operating activities | 561,358 | 385,137 | 521,478 |
Investing activities: | ' | ' | ' |
Acquisition of property interest in oil and natural gas properties | -82,424 | -205,550 | -437,247 |
Investment in oil and natural gas properties and equipment | -551,954 | -479,313 | -281,779 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | 15 |
Purchases of furniture, fixtures and other, net | -1,435 | -3,031 | -3,660 |
Net cash used in investing activities | -614,805 | -657,441 | -722,671 |
Financing activities: | ' | ' | ' |
Issuance of 8.50% Senior Notes | ' | 318,000 | 600,000 |
Repurchase of 8.25% Senior Notes | ' | ' | -450,000 |
Borrowings of long-term debt - revolving bank credit facility | 563,000 | 732,000 | 623,000 |
Repayments of long-term debt - revolving bank credit facility | -443,000 | -679,000 | -506,000 |
Repurchase premium and debt issuance costs | -3,892 | -8,510 | -32,288 |
Dividends to shareholders | -58,846 | -82,832 | -58,756 |
Other | -260 | 379 | 1,094 |
Net cash provided by financing activities | 57,002 | 280,037 | 177,050 |
Increase (decrease) in cash and cash equivalents | 3,555 | 7,733 | -24,143 |
Cash and cash equivalents, beginning of period | 12,245 | 4,512 | 28,655 |
Cash and cash equivalents, end of period | $15,800 | $12,245 | $4,512 |
Significant_Accounting_Policie
Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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. and our wholly-own subsidiary, W&T Energy VI, LLC. | |||||||||||||
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. Deferred income taxes – current asset was combined with Prepaid expenses and other assets on the Consolidated Balance Sheet, Income taxes payable was combined with Accrued liabilities on the Consolidated Balance Sheet, and changes in Other liabilities was combined with the changes in Accounts payable and accrued liabilities on the Consolidated Statement 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. | |||||||||||||
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 December 31, 2013 and 2012, $6.4 million and $6.0 million, respectively, were 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. | |||||||||||||
The following identifies customers from whom we derived 10% or more of receipts from sales of oil, natural gas liquids (“NGLs”) and natural gas. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Customer | |||||||||||||
Shell Trading (US) Co. | 48 | % | 35 | % | 36 | % | |||||||
ConocoPhillips (1) | ** | 16 | % | 16 | % | ||||||||
J.P. Morgan Ventures Energy Corp. | ** | ** | 10 | % | |||||||||
** | 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. | |||||||||||||
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 expenditures made in connection with the exploration and development 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 Sheet. | |||||||||||||
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. These additional costs related to developing proved reserves are not recorded as liabilities on the balance sheet. | |||||||||||||
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 oil and natural gas prices after December 31, 2013 may require us to record additional ceiling-test impairments in the future. We did not have any write-downs related to ceiling-test impairments during 2013, 2012 and 2011, 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 was determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs were: (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 were 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 could vary significantly from these estimates. No goodwill was recorded for the acquisitions completed in 2013, 2012 or 2011. | |||||||||||||
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 share 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 | |||||||||||||
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 statement of cash flows. | |||||||||||||
Recent Accounting Developments | |||||||||||||
In February 2013, the Financial Accounting Standards Board (“FASB”) issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. The Company does not expect its disclosures to be affected by ASU 2013-04. | |||||||||||||
In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740); Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists - a consensus of the FASB Emerging Task Force, which provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. The amendment is effective for annual periods and interim periods beginning after December 15, 2013. Early adoption is permitted and the amendment is to be applied prospectively. The Company does not expect its balance sheet presentation or its disclosures to be affected by ASU 2013-11. |
Acquisitions_and_Divestitures
Acquisitions and Divestitures | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Acquisitions and Divestitures | ' | ||||||||
2. Acquisitions and 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. The consideration and the purchase price allocation, as set forth in the table below, are subject to further post-closing adjustments which we expect to be finalized during 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 acquisition of the Callon Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 73,176 | |||||||
Unevaluated properties | 9,248 | ||||||||
Sub-total – cash consideration | 82,424 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - current | 90 | ||||||||
Asset retirement obligation - non-current | 4,143 | ||||||||
Sub-total – non-cash consideration | 4,233 | ||||||||
Total consideration | $ | 86,657 | |||||||
Expenses associated with acquisition activities and transition activities related to the acquisition of the Callon Properties for the year ended December 31, 2013 were $0.4 million and are included in general and administrative expenses (“G&A”). 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 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 | 59,073 | 85,378 | |||||||
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 | 2012 | ||||||||
Revenues (a) | $ | 34,030 | $ | 48,559 | |||||
Direct operating expenses (a) | 6,405 | 8,525 | |||||||
DD&A (b) | 14,856 | 17,492 | |||||||
G&A (c) | (361 | ) | — | ||||||
Interest expense (d) | 1,374 | 1,648 | |||||||
Capitalized interest (e) | (168 | ) | 288 | ||||||
Income tax expense (f) | 4,173 | 7,212 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | ||||||||
(b) | 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. | ||||||||
(c) | 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. | ||||||||
(d) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $82.4 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. | ||||||||
(e) | 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. Positive amounts represent increases to net expenses. The negative amount represents a decrease to net expenses. | ||||||||
(f) | 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 $16.5 million. 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). 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 and no further adjustments are expected. A net purchase price increase of $0.2 million was recorded during the year ended December 31, 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 obligation - current | 7,250 | ||||||||
Asset retirement obligation - non-current | 24,414 | ||||||||
Sub-total – non-cash consideration | 31,664 | ||||||||
Total consideration | $ | 237,452 | |||||||
Expenses associated with acquisition activities and transition activities related to the acquisition of the Newfield Properties for the year ended December 31, 2012 were $0.6 million and are included in G&A. 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. For the period of October 5, 2012 to December 31, 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 December 31, | |||||||||
2012 | 2011 | ||||||||
Revenue | $ | 980,196 | $ | 1,187,808 | |||||
Net income | 77,036 | 220,835 | |||||||
Basic and diluted earnings per common share | 1.01 | 2.92 | |||||||
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 | 2011 | ||||||||
Revenues (a) | $ | 105,705 | $ | 216,761 | |||||
Direct operating expenses (a) | 33,186 | 24,563 | |||||||
Insurance costs (b) | 475 | 633 | |||||||
DD&A (c) | 53,408 | 102,713 | |||||||
G&A (d) | (553 | ) | — | ||||||
Interest expense (e) | 12,060 | 15,846 | |||||||
Capitalized interest (f) | (643 | ) | (868 | ) | |||||
Income tax expense (g) | 2,720 | 25,856 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | ||||||||
(b) | 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. | ||||||||
(c) | 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. | ||||||||
(d) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.7 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. | ||||||||
(f) | 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. | ||||||||
(g) | 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. | |||||||||
2011 Acquisitions | |||||||||
On May 11, 2011, we acquired from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”) certain oil and gas leasehold interests (the “Opal Properties”). The properties consisted of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the West Texas Permian Basin. The effective date was January 1, 2011. The transaction included customary adjustments for the effective date, certain closing adjustments, and we assumed the related ARO along with a certain long-term liability. The consideration and the purchase price allocation are set forth in the table below. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility. | |||||||||
The following table presents the purchase price allocation, including adjustments, for the acquisition of the Opal Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 313,165 | |||||||
Unevaluated properties | 81,212 | ||||||||
Sub-total – cash consideration | 394,377 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - non-current | 382 | ||||||||
Long-term liability | 2,143 | ||||||||
Sub-total – non-cash consideration | 2,525 | ||||||||
Total consideration | $ | 396,902 | |||||||
On August 10, 2011, we acquired from Shell Offshore Inc. (“Shell”) certain oil and gas leasehold and property interests (the “Fairway Properties”). The properties consisted of Shell’s 64.3% interest in the Fairway field along with a like interest in the associated Yellowhammer gas treatment plant. The effective date was September 1, 2010. 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 acquisition was funded from borrowings under our revolving bank credit facility. | |||||||||
The following table presents the purchase price allocation, including adjustments, for the acquisition of the Fairway Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 42,870 | |||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - non-current | 7,812 | ||||||||
Total consideration | $ | 50,682 | |||||||
Expenses associated with acquisition activities and transition activities related to the Opal Properties and Fairway Properties for the year 2011 were $1.6 million and are included in G&A. The acquisitions were 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. | |||||||||
2011 Acquisitions — Revenue, Net Income and Pro Forma Financial Information — Unaudited | |||||||||
The Opal Properties and the Fairway Properties were not included in our consolidated results until their respective close dates. For the period of May 11, 2011 to December 31, 2011 for the Opal Properties and the period of August 10, 2011 to December 31, 2011 for the Fairway Properties, these two acquisitions accounted for $64.0 million of revenue, $25.5 million of direct operating expenses, $20.5 million of DD&A and $6.3 million of income taxes, resulting in $11.7 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 Opal Properties and the Fairway Properties were 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, 2011, the unaudited pro forma financial information was computed as if the acquisition of the Opal Properties and the Fairway Properties had been completed on January 1, 2010. The historical financial information is derived from W&T’s audited historical consolidated financial statements, the Opal Properties’ audited historical financial statement for 2010, the Fairway Properties’ unaudited historical statement for 2010 and the unaudited historical statements of the sellers for the 2011 interim period. | |||||||||
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Opal Properties and the Fairway Properties. The pro forma financial information is not necessarily indicative of the results of operations had the respective purchases occurred on January 1, 2010. If the transactions 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 the sellers. Realized sales prices for oil, NGLs and natural gas may have been different and costs of operating the 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, | |||||||||
2011 | |||||||||
Revenue | $ | 1,023,430 | |||||||
Net income | 180,779 | ||||||||
Basic and diluted earnings per common share | 2.39 | ||||||||
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 Opal Properties and the Fairway Properties (in thousands): | |||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
December 31, | |||||||||
2011 | |||||||||
Revenues (a) | $ | 52,383 | |||||||
Direct operating expenses (a) | 16,368 | ||||||||
DD&A (b) | 21,836 | ||||||||
G&A (c) | (1,596 | ) | |||||||
Interest expense (d) | 4,612 | ||||||||
Capitalized interest (e) | (1,086 | ) | |||||||
Income tax expense (f) | 4,287 | ||||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Opal Properties and the Fairway Properties were derived from the historical records of the sellers up to the respective closing dates. | ||||||||
(b) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Opal Properties and Fairway 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 were estimated by W&T management. | ||||||||
(c) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2011 results. | ||||||||
(d) | The acquisitions were assumed to be funded entirely with borrowed funds and that borrow capacity would have been available on the revolving bank credit facility due to the increase in reserves. Interest expense was computed using assumed borrowings of $437.2 million, which equates to the cash component of the transactions, and an interest rate ranging from 2.6% to 3.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(e) | 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. | ||||||||
(f) | 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. |
Hurricane_Remediation_and_Insu
Hurricane Remediation and Insurance Claims | 12 Months Ended |
Dec. 31, 2013 | |
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 and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. 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 2013, 2012 and 2011, we have received insurance proceeds of $6.7 million, $2.9 million and $20.9 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 Sheet, with minor amounts recorded as reductions in Lease operating expense in the Consolidated Statement of Income. From the third quarter of 2008 through December 31, 2013, we have received $148.9 million cumulative from our insurance underwriters related to Hurricane Ike. See Note 5 for additional information about the impact of hurricane related items on our ARO. See Note 18 for information regarding legal actions taken by certain insurers and the Company. |
Restricted_Deposits
Restricted Deposits | 12 Months Ended |
Dec. 31, 2013 | |
Restricted Deposits | ' |
4. Restricted Deposits | |
Restricted deposits as of December 31, 2013 and 2012 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. Monthly payments are made to an escrow account and these funds are returned once verification is made as to fulfilling the security amount requirements. We were in compliance with the security requirements as of December 31, 2013. See Note 16 for potential future security requirements. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
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): | |||||||||
2013 | 2012 | ||||||||
Asset retirement obligations, beginning of period | $ | 384,053 | $ | 393,880 | |||||
Liabilities settled | (81,543 | ) | (112,827 | ) | |||||
Accretion of discount | 20,918 | 20,055 | |||||||
Disposition of properties | (19,564 | ) | (3,993 | ) | |||||
Liabilities assumed through acquisition | 4,233 | 31,664 | |||||||
Liabilities incurred | 1,745 | 1,815 | |||||||
Revisions of estimated liabilities due to Hurricane Ike | 6,801 | (20,616 | ) | ||||||
Revisions of estimated liabilities—all other | 37,779 | 74,075 | |||||||
Asset retirement obligations, end of period | 354,422 | 384,053 | |||||||
Less current portion | 77,785 | 92,630 | |||||||
Long-term | $ | 276,637 | $ | 291,423 | |||||
Each year (or more often if conditions warrant) we review and, to the extent necessary, revise our ARO estimates. During 2013, we reduced our ARO by $81.5 million for the plug and abandonment work performed during the year (including reductions of $11.6 million to plug and abandon wells and facilities damaged by Hurricane Ike). The acquisition of the Callon Properties caused an increase of $4.2 million. Revisions related to Hurricane Ike were a net increase of $6.8 million and other revisions increased ARO by $37.8 million. These were attributable to: a) regulation interpretations issued by the Bureau of Safety and Environmental Enforcement (“BSEE”), which increased the amount of work involved, b) revisions to third-party contractor estimate 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 are taking longer to complete the plugging and abandonment work than previously estimated due to operational issues. In addition, increases in estimates were made for certain non-operated properties. | |||||||||
During 2012, we reduced our ARO by $112.8 million for the plug and abandonment work performed during the year (including reductions of $29.6 million to plug and abandon wells and facilities damaged by Hurricane Ike). The acquisition of the Newfield Properties caused an increase of $31.7 million. Revisions made related to Hurricane Ike were a net decrease of $20.6 million, which was primarily attributable to the designation of a reef in place at one of the hurricane damaged platforms. Other revisions increased ARO by $74.1 million and were attributable to: a) regulation interpretations issued by the BSEE, which increased the amount of work involved, b) revisions to third-party contractor estimate 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 are taking longer to complete the plugging and abandoning work than previously estimated due to operational issues. In addition, increases in estimates were made for certain non-operated properties. |
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | ||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||
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. For additional information about fair value measurements, refer to Note 7. 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 statement of cash flows. | |||||||||||||||||||||||||||
For information about fair value measurements, refer to Note 8. | |||||||||||||||||||||||||||
Commodity Derivatives | |||||||||||||||||||||||||||
We have entered into commodity swap contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 2014. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. During the years ended December 31, 2013, 2012 and 2011, our derivative contracts consisted entirely of crude oil swap contracts. The crude oil swap contracts are 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 are priced off the Brent crude oil price quoted on the IntercontinentalExchange, known as ICE. The WTI based swap contracts are priced off the New York Mercantile Exchange, known as NYMEX. The LLS based swap contracts are priced from data provided by Argus, an independent media organization. Although our Gulf of Mexico crude oil 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, have been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which is based off the Brent crude oil price. Therefore, a portion of the swap oil contracts are priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production. | |||||||||||||||||||||||||||
As of December 31, 2013, our open commodity derivative contracts were as follows: | |||||||||||||||||||||||||||
Swaps – Oil | |||||||||||||||||||||||||||
Priced off Brent | Priced off WTI | Priced off LLS | |||||||||||||||||||||||||
(ICE) | (NYMEX) | (ARGUS) | |||||||||||||||||||||||||
Termination Period | Notional | Weighted | Notional | Weighted | Notional | Weighted | |||||||||||||||||||||
Quantity | Average | Quantity | Average | Quantity | Average | ||||||||||||||||||||||
(Bbls) | Contract | (Bbls) | Contract | (Bbls) | Contract | ||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||||
2014:00:00 | 1st Qtr | 180,000 | $ | 97.38 | 762,000 | $ | 97.39 | 180,000 | $ | 98.2 | |||||||||||||||||
2nd Qtr | 172,900 | 97.38 | 455,000 | 97.17 | 364,000 | 97.88 | |||||||||||||||||||||
3rd Qtr | 165,600 | 97.38 | 155,000 | 97 | 552,000 | 97.65 | |||||||||||||||||||||
4th Qtr | 156,400 | 97.37 | — | — | 368,000 | 97.88 | |||||||||||||||||||||
674,900 | $ | 97.38 | 1,372,000 | $ | 97.27 | 1,464,000 | $ | 97.83 | |||||||||||||||||||
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, | |||||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||||
Prepaid and other assets | $ | 141 | $ | — | |||||||||||||||||||||||
Accrued liabilities | 9,423 | 6,355 | |||||||||||||||||||||||||
Other liabilities (noncurrent) | — | 3,046 | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||||
Derivative (gain) loss: | 2013 | 2012 | 2011 | ||||||||||||||||||||||||
Realized | $ | 8,589 | $ | 7,665 | $ | 9,873 | |||||||||||||||||||||
Unrealized | (119 | ) | 6,289 | (11,769 | ) | ||||||||||||||||||||||
Total | $ | 8,470 | $ | 13,954 | $ | (1,896 | ) | ||||||||||||||||||||
Offsetting Commodity Derivatives | |||||||||||||||||||||||||||
As of December 31, 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 provide 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 be 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 account for our derivative contracts on a gross basis per contract as either an asset or liability. | |||||||||||||||||||||||||||
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): | |||||||||||||||||||||||||||
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 | |||||||||||||||||||||||
There were no potential effects of master netting agreements on the fair value of open derivative contracts as of December 31, 2012 due to all open derivative contracts being valued as liabilities. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Long-Term Debt | ' | ||||||||
7. Long-Term Debt | |||||||||
As of December 31, 2013 and 2012 our long-term debt was as follows (in thousands): | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
8.50% Senior Notes, due June 2019 | $ | 900,000 | $ | 900,000 | |||||
Debt premiums, net of amortization | 15,421 | 17,611 | |||||||
Revolving bank credit facility, due Nov 2018 | 290,000 | 170,000 | |||||||
Total long-term debt (1) | 1,205,421 | 1,087,611 | |||||||
Current maturities of long-term debt | — | — | |||||||
Long-term debt, less current maturities | $ | 1,205,421 | $ | 1,087,611 | |||||
-1 | Aggregate annual maturities of long-term debt as of December 31, 2013 are as follows (in millions): 2014–$0.0; 2015–$0.0; 2016–$0.0; 2017–$0.0; thereafter–$1,190.0. | ||||||||
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. | |||||||||
During 2011, we used a portion of the net proceeds from the June 2011 issuance of the 8.50% Senior Notes to repurchase all of our 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”), which had a principal amount of $450.0 million. Costs of $22.0 million related to repurchasing the 8.25% Senior Notes, which included repurchase premiums and the unamortized debt issuance costs, are included in the statement of income within the line item classification, Loss on extinguishment of debt. | |||||||||
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, 2013 and 2012, the outstanding balance of our 8.50% Senior Notes was $900.0 million and 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 2013, which includes amortization of debt issuance costs and premiums. At December 31, 2013 and 2012, the estimated fair value of the 8.50% Senior Notes was approximately $962.5 million and $963.0 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, 2013. | |||||||||
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 with an initial borrowing base of $800.0 million. Letters of credit may be issued up to $300.0 million, provided availability under the revolving bank credit facility exists. This is a secured facility that 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”). 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 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. | |||||||||
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 3.8% for 2013 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. | |||||||||
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 has been 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, 2013, we had $290.0 million in borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2012, we had $170.0 million in borrowings and $0.6 million in letters of credit outstanding under the revolving bank credit facility. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2013. | |||||||||
For information about fair value measurements, refer to Note 8. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
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). | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
Hierarchy | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
Derivatives | Level 2 | $ | 141 | $ | 9,423 | $ | — | $ | 9,401 | ||||||||||||
8.50% Senior Notes | Level 2 | — | 962,460 | — | 963,000 | ||||||||||||||||
Revolving bank credit facility | Level 2 | — | 290,000 | — | 170,000 | ||||||||||||||||
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, 2013 and 2012. The revolving bank credit facility debt is reported in the statement of financial position at its carrying value, which was $290.0 million and $170.0 million at December 31, 2013 and 2012, respectively. | |||||||||||||||||||||
For additional information about our derivative financial instruments refer to Note 6 and for additional information on our Senior Notes and revolving bank credit facility refer to Note 7. |
Equity_Structure_and_Transacti
Equity Structure and Transactions | 12 Months Ended |
Dec. 31, 2013 | |
Equity Structure and Transactions | ' |
9. Equity Structure and Transactions | |
As of December 31, 2013 and 2012, 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 2013, 2012 and 2011, we paid regular cash dividends of $0.36, $0.32 and $0.16 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. In December 2011, we paid a special dividend of $0.63 per share or $46.9 million. On March 6, 2014, our board of directors declared a cash dividend of $0.10 per common share, payable on March 31, 2014 to shareholders of record on March 18, 2014. |
Incentive_Compensation_Plan
Incentive Compensation Plan | 12 Months Ended |
Dec. 31, 2013 | |
Incentive Compensation Plan | ' |
10. Incentive Compensation Plan | |
In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders and in 2013, shareholders approved two amendments to the Plan. The Plan covers the Company’s eligible employees and consultants. The Plan amended and restated the Company’s previous Long-term Incentive Compensation Plan (the “Previous Plan”). 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 2013, 2012 and 2011, 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. | |
During 2013, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2013; (ii) Adjusted EBITDA as a percent of total revenue (“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, was approximately at target for 2013 Adjusted EBITDA Margin and was below target for TSR ranking. Also during 2013, RSUs were granted which were not subject to performance criteria and amounted to 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. | |
During 2011, RSUs granted were subject to single performance criteria, EPS for 2011, and adjustments ranged from 0% to 100%. The Company exceeded the top-tier target; therefore, 100% were deemed eligible for vesting. | |
All RSUs granted to date are subject to employment-based criteria and vesting occurs in December of the third year after the grant. For example, the RSUs granted during 2011 vested in December 2013 to eligible employees. | |
For information concerning grants awarded, the determination of fair value for RSUs and amounts recognized in expense, see Note 11. | |
Cash-based Awards | |
For 2013, 2012 and 2011, 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 EPS, reserve and production growth, cost containment and individual performance measures. With respect to the 2013 cash-based awards, most of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. 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. With respect to the 2011 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. Eligible employees are paid their cash-based awards within 75 days following year end. | |
For information concerning amounts recognized in expense, see Note 11. |
ShareBased_and_CashBased_Incen
Share-Based and Cash-Based Incentive Compensation | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Share-Based and Cash-Based Incentive Compensation | ' | ||||||||||||||||||||||||
11. Share-Based and Cash-Based Incentive Compensation | |||||||||||||||||||||||||
As allowed by the Plan, in 2013, 2012 and 2011, the Company granted RSUs to certain of its employees. In 2013, 2012 and 2011, 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 2013, 2012 and 2011. | |||||||||||||||||||||||||
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, 2013, there were 5,078,983 shares of common stock available for issuance in satisfaction of awards under the Plan and 519,379 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. 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 Company’s share-based payment plans, restricted shares were issued in 2013, 2012 and 2011 and were primarily issued to the Company’s non-employee directors. As of December 31, 2013, all of the unvested restricted shares outstanding were held by non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction 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. | |||||||||||||||||||||||||
A summary of activity related to restricted stock is as follows: | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Restricted | Weighted | Restricted | Weighted | Restricted | Weighted | ||||||||||||||||||||
Shares | Average | Shares | Average | Shares | Average | ||||||||||||||||||||
Grant Date | Grant Date | Grant Date | |||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||
Per Share | Per Share | Per Share | |||||||||||||||||||||||
Nonvested, beginning of period | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | 470,392 | $ | 7.42 | ||||||||||||||||
Granted | 27,450 | 12.75 | 21,954 | 19.13 | 20,433 | 25.45 | |||||||||||||||||||
Vested | (27,297 | ) | 17.09 | (27,475 | ) | 13.59 | (404,422 | ) | 7.31 | ||||||||||||||||
Forfeited | — | — | (2,662 | ) | 18.78 | (34,533 | ) | 6.83 | |||||||||||||||||
Nonvested, end of period | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | ||||||||||||||||
Subject to the satisfaction of service conditions, the restricted shares outstanding as of December 31, 2013 are expected to vest as follows: | |||||||||||||||||||||||||
Shares | |||||||||||||||||||||||||
2014 | 19,445 | ||||||||||||||||||||||||
2015 | 15,245 | ||||||||||||||||||||||||
2016 | 9,150 | ||||||||||||||||||||||||
Total | 43,840 | ||||||||||||||||||||||||
Restricted stock fair value at grant date and vested date: The grant date fair value of restricted stock granted during 2013, 2012 and 2011 was $0.3 million, $0.4 million and $0.5 million, respectively, based on the Company’s closing price on the date of grant. The fair value of the restricted stock that vested during 2013, 2012 and 2011 was $0.4 million, $0.5 million and $7.9 million, respectively, based on the Company’s closing price on the date of vesting. | |||||||||||||||||||||||||
Restricted Stock Units | |||||||||||||||||||||||||
During 2013, 2012 and 2011, 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. 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. See Note 10 for additional information concerning RSUs. | |||||||||||||||||||||||||
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 (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. | |||||||||||||||||||||||||
The fair value of the RSUs granted in 2011 was determined using the Company’s closing price on the grant date. | |||||||||||||||||||||||||
A summary of activity related to RSUs is as follows: | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
RSUs | Weighted | RSUs | Weighted | Weighted | |||||||||||||||||||||
Average | Average | RSUs | Average | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | |||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||
Per RSU | Per RSU | Per RSU | |||||||||||||||||||||||
Nonvested, beginning of period | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | 1,266,617 | $ | 9.36 | ||||||||||||||||
Granted | 969,919 | 13.23 | 764,654 | 18.64 | 534,375 | 26.93 | |||||||||||||||||||
Vested | (468,925 | ) | 26.93 | (1,198,208 | ) | 9.36 | — | — | |||||||||||||||||
Forfeited | (139,061 | ) | 16.5 | (329,329 | ) | 19.56 | (68,289 | ) | 12.03 | ||||||||||||||||
Nonvested, end of period | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | ||||||||||||||||
Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2013 are eligible to vest in the year indicated in the table below: | |||||||||||||||||||||||||
RSUs | |||||||||||||||||||||||||
2014 – subject to service requirements | 359,785 | ||||||||||||||||||||||||
2014 – subject to service and other requirements (1) | 67,877 | ||||||||||||||||||||||||
2015 – subject to service requirements | 719,971 | ||||||||||||||||||||||||
2015 – subject to service and other requirements (1) | 184,120 | ||||||||||||||||||||||||
Total | 1,331,753 | ||||||||||||||||||||||||
-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 2013, 2012 and 2011, the grant date fair value of RSUs granted was $12.8 million, $14.3 million and $14.4 million, respectively. | |||||||||||||||||||||||||
RSUs fair value at vested date: The fair value of the RSUs that vested during 2013 and 2012 was $7.2 million and $20.0 million, respectively, based on the Company’s closing price on the vesting date. | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Share-based compensation expense from: | |||||||||||||||||||||||||
Restricted stock | $ | 397 | $ | 399 | $ | 2,377 | |||||||||||||||||||
Restricted stock units | 11,128 | 11,999 | 7,333 | ||||||||||||||||||||||
Total | $ | 11,525 | $ | 12,398 | $ | 9,710 | |||||||||||||||||||
Share-based compensation tax benefit: | |||||||||||||||||||||||||
Tax benefit computed at the statutory rate | $ | 4,034 | $ | 4,339 | $ | 3,399 | |||||||||||||||||||
As of December 31, 2013, unrecognized share-based compensation expense related to our issued restricted shares and RSUs was $0.5 million and $12.1 million, respectively. Unrecognized compensation expense will be recognized through April 2016 for restricted shares and November 2015 for RSUs. | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Share-based compensation expense included in: | |||||||||||||||||||||||||
Lease operating expense | $ | — | $ | — | $ | 466 | |||||||||||||||||||
General and administrative | 11,525 | 12,398 | 9,244 | ||||||||||||||||||||||
Total charged to operating income | 11,525 | 12,398 | 9,710 | ||||||||||||||||||||||
Cash-based incentive compensation included in: | |||||||||||||||||||||||||
Lease operating expense | 3,482 | 3,787 | 3,700 | ||||||||||||||||||||||
General and administrative | 8,817 | 6,558 | 12,213 | ||||||||||||||||||||||
Total charged to operating income | 12,299 | 10,345 | 15,913 | ||||||||||||||||||||||
Total incentive compensation charged to operating income | $ | 23,824 | $ | 22,743 | $ | 25,623 | |||||||||||||||||||
Employee_Benefit_Plan
Employee Benefit Plan | 12 Months Ended |
Dec. 31, 2013 | |
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 2013, 2012 and 2011, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% for 2013 and 2012 and 5% for 2011 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 $2.1 million, $2.1 million and $1.8 million for 2013, 2012 and 2011, respectively. | |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Income Taxes | ' | ||||||||||||||||||||||||
13. Income Taxes | |||||||||||||||||||||||||
Income Tax Expense | |||||||||||||||||||||||||
Components of income tax expense were as follows (in thousands): | |||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Current | $ | (2,146 | ) | $ | (40,562 | ) | $ | 29,682 | |||||||||||||||||
Deferred | 30,920 | 88,109 | 61,835 | ||||||||||||||||||||||
$ | 28,774 | $ | 47,547 | $ | 91,517 | ||||||||||||||||||||
Effective Tax Rate Reconciliation | |||||||||||||||||||||||||
The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense is as follows (in thousands): | |||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Income tax expense at the federal statutory rate | $ | 28,033 | 35 | % | $ | 41,836 | 35 | % | $ | 92,517 | 35 | % | |||||||||||||
Qualified domestic production activities | — | — | 4,256 | 3.5 | (1,823 | ) | (0.7 | ) | |||||||||||||||||
State income taxes | 343 | 0.4 | 750 | 0.7 | 603 | 0.2 | |||||||||||||||||||
Other | 398 | 0.5 | 705 | 0.6 | 220 | 0.1 | |||||||||||||||||||
$ | 28,774 | 35.9 | % | $ | 47,547 | 39.8 | % | $ | 91,517 | 34.6 | % | ||||||||||||||
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. Our effective tax rate for the year 2011 differed from the federal statutory rate primarily as a result of the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the IRC. | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Deferred tax liabilities: | |||||||||||||||||||||||||
Property and equipment | $ | 297,942 | $ | 186,599 | |||||||||||||||||||||
Other | 3,602 | 4,822 | |||||||||||||||||||||||
Total deferred tax liabilities | 301,544 | 191,421 | |||||||||||||||||||||||
Deferred tax assets: | |||||||||||||||||||||||||
Minimum tax credit | 20,486 | 22,314 | |||||||||||||||||||||||
Federal net operating losses | 91,472 | 12,389 | |||||||||||||||||||||||
State net operating losses | 5,028 | 5,057 | |||||||||||||||||||||||
Derivatives | 3,270 | 3,312 | |||||||||||||||||||||||
Valuation allowance (state) | (4,490 | ) | (4,674 | ) | |||||||||||||||||||||
Accrued cash-based bonus | 3,873 | 2,455 | |||||||||||||||||||||||
Stock-based compensation | 3,703 | 4,256 | |||||||||||||||||||||||
Other | 643 | 1,330 | |||||||||||||||||||||||
Total deferred tax assets | 123,985 | 46,439 | |||||||||||||||||||||||
Net deferred tax liabilities | $ | 177,559 | $ | 144,982 | |||||||||||||||||||||
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. During 2011, we made payments primarily for federal and state income taxes of $35.7 million and we received refunds related to prior years of $0.4 million. | |||||||||||||||||||||||||
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. At December 31, 2012, we had a federal income tax receivable of $47.9 million. This amount is comprised principally of a net operating loss carryback from 2012 to 2010 of $29.1 million and a net operating loss carryback from 2012 to 2011 of $13.8 million. Additionally, federal estimated tax payments were deposited in 2012 of $5.0 million. | |||||||||||||||||||||||||
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, 2013 (in thousands): | |||||||||||||||||||||||||
Amount | Expiration Year | ||||||||||||||||||||||||
Federal net operating loss | $ | 263,388 | 2033 | ||||||||||||||||||||||
State net operating losses | 95,912 | 2017-2028 | |||||||||||||||||||||||
Minimum tax credit | 12,091 | Indefinite | |||||||||||||||||||||||
General business credit | 406 | 2027-2028 | |||||||||||||||||||||||
The federal net operating loss and 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, 2013 and December 31, 2012, 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, | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Balance at beginning of period | $ | — | $ | — | |||||||||||||||||||||
Increases related to carryback positions | 9,482 | — | |||||||||||||||||||||||
Balance at end of period | $ | 9,482 | $ | — | |||||||||||||||||||||
We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2013, 2012 and 2011, the amounts recognized in income tax expense were immaterial. | |||||||||||||||||||||||||
Years open to examination | |||||||||||||||||||||||||
The tax years from 2010 through 2013 remain open to examination by the tax jurisdictions to which we are subject. |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Net income | $ | 51,322 | $ | 71,984 | $ | 172,817 | |||||||
Less portion allocated to nonvested shares | 303 | 983 | 3,211 | ||||||||||
Net income allocated to common shares | $ | 51,019 | $ | 71,001 | $ | 169,606 | |||||||
75,239 | 74,354 | 74,033 | |||||||||||
Weighted average common shares outstanding | |||||||||||||
$ | 0.68 | $ | 0.95 | $ | 2.29 | ||||||||
Basic and diluted earnings per common share | |||||||||||||
— | 1,923 | 1,873 | |||||||||||
Shares excluded due to being anti-dilutive | |||||||||||||
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Supplemental Cash Flow Information | ' | ||||||||||||
15. Supplemental Cash Flow Information | |||||||||||||
The following reflects our supplemental cash flow information (in thousands): | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Cash paid for interest, net of interest capitalized of $10,058 in 2013, $13,274 in 2012 and $9,877 in 2011 | $ | 73,909 | $ | 46,247 | $ | 39,772 | |||||||
Cash paid for income taxes | 3,000 | 16,056 | 35,655 | ||||||||||
Cash refunds received for income taxes | 59,126 | 479 | 379 | ||||||||||
Cash paid for share-based compensation (1) | 466 | 1,531 | 1,062 | ||||||||||
Cash tax benefit related to share-based compensation (2) | — | 5,962 | 3,125 | ||||||||||
-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 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, 2013 | |
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, 2013 are as follows (in millions): 2014–$1.3; 2015–$1.3; 2016-$1.3; 2017-$1.4; thereafter–$8.0. | |
Total rent expense was approximately $2.6 million, $1.7 million and $1.9 million during 2013, 2012 and 2011, 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, 2013, we were in compliance with the security amount requirement of $55.0 million. Additional security requirements are $9.0 million in 2014, $9.0 million in 2015, $6.0 million in 2016, $6.0 million in 2017 and $18.0 million in the 2018 to 2023 time period to a total security requirement of $103.0 million by 2023. | |
Pursuant to the Purchase and Sale agreement with 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 additional bonding requirements primarily related to properties owned by our subsidiary, W&T Energy VI, LLC, which require bonds in compliance with requirements set by the BOEM. These bonds are required as long as W&T Energy VI, LLC owns the properties, including completion of plugging and abandonment activities. | |
Total fees related to bonds, inclusive of the bonds in connection with Total E&P and Shell described above, were $5.0 million, $2.9 million and $2.6 million during 2013, 2012 and 2011, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future fees 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 (in millions): 2014–$5.5 million; 2015–$5.7 million; 2016–$5.8 million; 2017–$5.7 million; thereafter– $48.4 million. See Note 18 for additional information in connection with bond requirements. | |
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, 2013, future payments due are $1.9 million in 2014, $1.9 million in 2015 and $1.9 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, 2013 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2013 were $21.5 million in 2013. |
Related_Parties
Related Parties | 12 Months Ended |
Dec. 31, 2013 | |
Related Parties | ' |
17. Related Parties | |
During 2013, 2012 and 2011, there were certain transactions between us and other companies our majority shareholder either controlled or had an ownership interest in. In addition, there were transactions with a company that employs the spouse of our majority shareholder. Our majority shareholder owns a certain 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 $1.2 million, $1.0 million and $1.1 million for the years 2013, 2012 and 2011, 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 and $0.7 million for drilling related services during 2013 and 2012, respectively. A company that provides 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 2013, 2012 and 2011. 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, 2013 | |
Contingencies | ' |
18. Contingencies | |
Notice of Suspension and Debarment | |
In November 2013, the parent company, W&T Offshore, Inc., received a Notice of Suspension and Proposed Debarment and a Notice of Clean Water Act Listing from the EPA. The first Notice suspends the parent company and proposes a three year debarment from participation in future federal contracts, including future federal oil and gas leases, and assistance activities and renders the parent company ineligible to receive any federal contracts or approved subcontracts or to act as an agent or representative on behalf of another in such transaction, or receive certain federal benefits. The second Notice provides a narrower prohibition on federal contracts or benefits for the parent company. The Notices stemmed from the Company’s previously disclosed plea agreement and corporate conviction on two criminal counts as described below under Federal Grand Jury Investigation. The Company has commenced discussions with the EPA Suspension and Debarment Official (the “EPA SDO”) and made filings to contest the limitations in both Notices and seek a resolution to remove the suspension in a cooperative fashion as soon as practicable. The timing and ultimate result of these efforts, however, cannot be predicted at this time. | |
The Company does not believe that the regulatory requirements for suspension and debarment exist. The Company has corrected the issues leading to the 2009 offenses that form the basis for suspension and debarment and has been and remains a responsible operator. Suspension is not necessary to protect the Government’s business interests. The Company believes the EPA action fails to recognize the Company’s compliance with the plea agreement referred to below to demonstrate that the conditions which gave rise to the violations have been corrected and that the Company is a responsible operator acting under a comprehensive environmental and safety compliance program. | |
Disqualification of waiver concerning certain supplement bonding requirements from the BOEM. | |
In November and December 2013, the parent company, W&T Offshore, Inc., received letters from the BOEM claiming that it no longer qualifies for a waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging, and abandonment liabilities. The letter notifies the parent company that it must provide supplemental bonding on certain of its offshore leases, rights of way and easements in the Gulf of Mexico. We believe that this action is without basis and inconsistent with regulatory requirements. We have had continuing discussions with representatives of the BOEM regarding this decision in an attempt to resolve this issue. We are also discussing potential additional supplemental bonding requirements that may be required to be met in the event that the BOEM’s decision regarding the parent company’s supplemental bonding waiver is not modified or reversed. While these discussions remain ongoing, in order to preserve our rights, in January 2014 we filed a Petition for Stay Pending Appeal and Request for Interim Relief with the U.S. Department of Interior’s Board of Land Appeals. The petition seeks a stay of any supplemental bonding requirements pending the appeal and to reverse BOEM’s revocation of W&T Offshore, Inc.’s waiver of supplemental bonding requirements. Initially, we were granted a stay until February 15, 2014 in response to our petition and recently we were granted a stay until April 15, 2014 to facilitate ongoing negotiations. We continue to believe that W&T Offshore, Inc. qualifies for a supplemental bonding waiver. We intend to continue to work with the BOEM staff to resolve this matter. If resolving this matter ultimately involves additional bonding, it will result in increased costs of conducting our offshore business and operations and could utilize a portion of the borrowing capacity available under our revolving bank credit facility. | |
Federal Grand Jury Investigation | |
The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the U.S. Environmental Protection Agency (the “EPA”) conducted a federal grand jury investigation beginning in late 2010 of environmental law violations that occurred in 2009. In December 2012, an agreement was reached that resolved these environmental compliance matters and the agreement was approved by the federal district court in January 2013. Under the agreement, the Company on January 3, 2013 (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for failure to report a discharge of a small amount of oil from the same platform in November 2009, (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation. The probation terms require that the Company commit no further environmental law violations, comply with an Environmental Compliance Plan during the probation period and take no adverse action against personnel who cooperated in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. | |
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. Based upon informal discussions with representatives of the ONRR, we believe that it is likely the ONRR will assess a statutory fine, which could be in an amount substantially in excess of the underpayment. If such an assessment is made in an amount we deem excessive, we intend to contest the fine to the fullest extent possible. We assessed the probability of paying a substantial fine as unlikely and have not accrued any amounts in our contingent liabilities as of December 31, 2013. However, we cannot state with certainty that our estimate of additional exposure is accurate concerning this matter. | |
Cameron Parish Louisiana Claim | |
Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2013 and 2012, we settled claims with certain landowners and paid $1.3 million and $10.0 million, respectively. There is one lawsuit pending in this matter and we assessed further claims to be unlikely and have not accrued any additional amounts in our contingent liabilities as of December 31, 2013. However, we cannot state with certainty that our estimate of additional exposure is accurate concerning this matter. | |
Qui Tam Litigation | |
On September 21, 2012, we were served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of one of our contractors. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against us and three other working interest owners related to claims associated with three of our operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. This matter was more fully described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. On November 5, 2013, the court granted the Company’s motion to dismiss and the complaint was dismissed with prejudice. | |
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 and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that our Excess Policies do not cover removal-of-wreck and debris claims arising from Hurricane Ike 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. We did not file any claims under such Excess Policies during 2013 but currently anticipate filing a claim under the policies in 2014. As of December 31, 2013, we have spent $45.7 million to date of removal-of-wreck costs and expect to incur an additional $1.9 million of removal-of-wreck costs associated with platforms damaged by Hurricane Ike. 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 disagree with the Court’s ruling and have appealed the decision. Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Consolidated Balance Sheet. If we are successful in our appeal, any recoveries from claims made on these Excess Policies will be recorded as reductions in this line item, which will reduce the our DD&A rate. | |
Royalties | |
In 2009, the Company recognized $5.3 million in 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 the third quarter of 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue of $4.7 million in the third quarter of 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR and we are pursuing our claim to resolve the matter. | |
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 $0.5 million, $9.3 million and $1.7 million for the years 2013, 2012 and 2011, respectively. These expenses are reported within Operating costs and expenses on the statement of income and reflect the items noted above and other various claims, complaints and fines. As of December 31, 2013 and 2012, we have recorded a liability of $0.2 million and $1.3 million, respectively, which is included in Accrued liabilities on the Consolidated Balance Sheet, 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, 2013 | |||||||||||||||||
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, 2013 (1) | |||||||||||||||||
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 (2) | 0.35 | 0.29 | 0.19 | (0.16 | ) | ||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Revenues | $ | 235,886 | $ | 215,513 | $ | 185,946 | $ | 237,146 | |||||||||
Operating income | 15,913 | 99,100 | 7,560 | 46,737 | |||||||||||||
Net income | 3,218 | 53,567 | (1,471 | ) | 16,670 | ||||||||||||
Basic and diluted earnings (loss) per common share (2) | 0.04 | 0.7 | (0.02 | ) | 0.21 | ||||||||||||
-1 | 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. | |||||||||||||||||
-2 | 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. |
Supplemental_Guarantor_Informa
Supplemental Guarantor Information | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Supplemental Guarantor Information | ' | ||||||||||||||||
20. Supplemental Guarantor Information | |||||||||||||||||
Our payment obligations under the Company’s outstanding 8.50% Senior Notes and the Credit Agreement are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, including 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 unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. (the “Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. | |||||||||||||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Current assets: | |||||||||||||||||
Cash and cash equivalents | $ | 15,800 | $ | — | $ | — | $ | 15,800 | |||||||||
Receivables: | |||||||||||||||||
Oil and natural gas sales | 75,486 | 21,266 | — | 96,752 | |||||||||||||
Joint interest and other | 27,984 | — | — | 27,984 | |||||||||||||
Income taxes | 124,393 | — | (121,273 | ) | 3,120 | ||||||||||||
Total receivables | 227,863 | 21,266 | (121,273 | ) | 127,856 | ||||||||||||
Prepaid expenses and other assets | 23,674 | 6,272 | — | 29,946 | |||||||||||||
Total current assets | 267,337 | 27,538 | (121,273 | ) | 173,602 | ||||||||||||
Property and equipment—at cost: | |||||||||||||||||
Oil and natural gas properties and equipment | 6,770,396 | 568,701 | — | 7,339,097 | |||||||||||||
Furniture, fixtures and other | 21,431 | — | — | 21,431 | |||||||||||||
Total property and equipment | 6,791,827 | 568,701 | — | 7,360,528 | |||||||||||||
Less accumulated depreciation, depletion and amortization | 4,784,932 | 299,772 | — | 5,084,704 | |||||||||||||
Net property and equipment | 2,006,895 | 268,929 | — | 2,275,824 | |||||||||||||
Restricted deposits for asset retirement obligations | 37,421 | — | — | 37,421 | |||||||||||||
Other assets | 574,280 | 427,619 | (981,444 | ) | 20,455 | ||||||||||||
Total assets | $ | 2,885,933 | $ | 724,086 | $ | (1,102,717 | ) | $ | 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 | 75,977 | 1,808 | — | 77,785 | |||||||||||||
Accrued liabilities | 28,000 | 121,273 | (121,273 | ) | 28,000 | ||||||||||||
Total current liabilities | 290,204 | 124,173 | (121,273 | ) | 293,104 | ||||||||||||
Long-term debt, less current maturities | 1,205,421 | — | — | 1,205,421 | |||||||||||||
Asset retirement obligations, less current portion | 238,270 | 38,367 | — | 276,637 | |||||||||||||
Deferred income taxes | 170,419 | 7,723 | — | 178,142 | |||||||||||||
Other liabilities | 441,009 | — | (427,621 | ) | 13,388 | ||||||||||||
Commitments and contingencies | |||||||||||||||||
Shareholders’ equity: | |||||||||||||||||
Common stock | 1 | — | — | 1 | |||||||||||||
Additional paid-in capital | 403,564 | 317,776 | (317,776 | ) | 403,564 | ||||||||||||
Retained earnings | 161,212 | 236,047 | (236,047 | ) | 161,212 | ||||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | |||||||||||
Total shareholders’ equity | 540,610 | 553,823 | (553,823 | ) | 540,610 | ||||||||||||
Total liabilities and shareholders’ equity | $ | 2,885,933 | $ | 724,086 | $ | (1,102,717 | ) | $ | 2,507,302 | ||||||||
Condensed Consolidating Balance Sheet as of December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Current assets: | |||||||||||||||||
Cash and cash equivalents | $ | 12,245 | $ | — | $ | — | $ | 12,245 | |||||||||
Receivables: | |||||||||||||||||
Oil and natural gas sales | 80,729 | 17,004 | — | 97,733 | |||||||||||||
Joint interest and other | 56,439 | — | — | 56,439 | |||||||||||||
Income taxes | 163,750 | — | (115,866 | ) | 47,884 | ||||||||||||
Total receivables | 300,918 | 17,004 | (115,866 | ) | 202,056 | ||||||||||||
Prepaid expenses and other assets | 25,822 | — | — | 25,822 | |||||||||||||
Total current assets | 338,985 | 17,004 | (115,866 | ) | 240,123 | ||||||||||||
Property and equipment—at cost: | |||||||||||||||||
Oil and natural gas properties and equipment | 6,356,529 | 337,981 | — | 6,694,510 | |||||||||||||
Furniture, fixtures and other | 21,786 | — | — | 21,786 | |||||||||||||
Total property and equipment | 6,378,315 | 337,981 | — | 6,716,296 | |||||||||||||
Less accumulated depreciation, depletion and amortization | 4,461,886 | 193,955 | — | 4,655,841 | |||||||||||||
Net property and equipment | 1,916,429 | 144,026 | — | 2,060,455 | |||||||||||||
Restricted deposits for asset retirement obligations | 28,466 | — | — | 28,466 | |||||||||||||
Other assets | 442,540 | 407,008 | (829,605 | ) | 19,943 | ||||||||||||
Total assets | $ | 2,726,420 | $ | 568,038 | $ | (945,471 | ) | $ | 2,348,987 | ||||||||
Liabilities and Shareholders’ Equity | |||||||||||||||||
Current liabilities: | |||||||||||||||||
Accounts payable | $ | 123,792 | $ | 93 | $ | — | $ | 123,885 | |||||||||
Undistributed oil and natural gas proceeds | 36,791 | 282 | — | 37,073 | |||||||||||||
Asset retirement obligations | 92,595 | — | 35 | 92,630 | |||||||||||||
Accrued liabilities | 20,755 | 116,132 | (115,866 | ) | 21,021 | ||||||||||||
Total current liabilities | 273,933 | 116,507 | (115,831 | ) | 274,609 | ||||||||||||
Long-term debt | 1,087,611 | — | — | 1,087,611 | |||||||||||||
Asset retirement obligations, less current portion | 262,524 | 28,934 | (35 | ) | 291,423 | ||||||||||||
Deferred income taxes | 158,758 | — | (13,509 | ) | 145,249 | ||||||||||||
Other liabilities | 402,407 | — | (393,499 | ) | 8,908 | ||||||||||||
Commitments and contingencies | |||||||||||||||||
Shareholders’ equity: | |||||||||||||||||
Common stock | 1 | — | — | 1 | |||||||||||||
Additional paid-in capital | 396,186 | 231,759 | (231,759 | ) | 396,186 | ||||||||||||
Retained earnings | 169,167 | 190,838 | (190,838 | ) | 169,167 | ||||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | |||||||||||
Total shareholders’ equity | 541,187 | 422,597 | (422,597 | ) | 541,187 | ||||||||||||
Total liabilities and shareholders’ equity | $ | 2,726,420 | $ | 568,038 | $ | (945,471 | ) | $ | 2,348,987 | ||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 780,442 | $ | 203,646 | $ | — | $ | 984,088 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 252,511 | 18,328 | — | 270,839 | |||||||||||||
Production taxes | 7,135 | — | — | 7,135 | |||||||||||||
Gathering and transportation | 13,747 | 3,763 | — | 17,510 | |||||||||||||
Depreciation, depletion and amortization | 324,794 | 105,817 | — | 430,611 | |||||||||||||
Asset retirement obligation accretion | 18,152 | 2,766 | — | 20,918 | |||||||||||||
General and administrative expenses | 78,649 | 3,225 | — | 81,874 | |||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | |||||||||||||
Total costs and expenses | 703,458 | 133,899 | — | 837,357 | |||||||||||||
Operating income | 76,984 | 69,747 | — | 146,731 | |||||||||||||
Earnings of affiliates | 45,209 | — | (45,209 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 85,531 | 108 | — | 85,639 | |||||||||||||
Capitalized | (9,950 | ) | (108 | ) | — | (10,058 | ) | ||||||||||
Loss on extinguishment of debt | 128 | — | — | 128 | |||||||||||||
Other income | 9,074 | — | — | 9,074 | |||||||||||||
Income before income tax expense | 55,558 | 69,747 | (45,209 | ) | 80,096 | ||||||||||||
Income tax expense | 4,236 | 24,538 | — | 28,774 | |||||||||||||
Net income | $ | 51,322 | $ | 45,209 | $ | (45,209 | ) | $ | 51,322 | ||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 659,203 | $ | 215,288 | $ | — | $ | 874,491 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 209,581 | 22,679 | — | 232,260 | |||||||||||||
Production taxes | 5,840 | — | — | 5,840 | |||||||||||||
Gathering and transportation | 11,703 | 3,175 | — | 14,878 | |||||||||||||
Depreciation, depletion and amortization | 253,807 | 82,370 | — | 336,177 | |||||||||||||
Asset retirement obligation accretion | 17,463 | 2,592 | — | 20,055 | |||||||||||||
General and administrative expenses | 79,424 | 2,593 | — | 82,017 | |||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | |||||||||||||
Total costs and expenses | 591,772 | 113,409 | — | 705,181 | |||||||||||||
Operating income | 67,431 | 101,879 | — | 169,310 | |||||||||||||
Earnings of affiliates | 66,195 | — | (66,195 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 63,268 | — | — | 63,268 | |||||||||||||
Capitalized | (13,274 | ) | — | — | (13,274 | ) | |||||||||||
Other income | 215 | — | — | 215 | |||||||||||||
Income before income tax expense | 83,847 | 101,879 | (66,195 | ) | 119,531 | ||||||||||||
Income tax expense | 11,863 | 35,684 | — | 47,547 | |||||||||||||
Net income | $ | 71,984 | $ | 66,195 | $ | (66,195 | ) | $ | 71,984 | ||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2011 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 697,899 | $ | 273,148 | $ | — | $ | 971,047 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 182,165 | 37,041 | — | 219,206 | |||||||||||||
Production taxes | 4,275 | — | — | 4,275 | |||||||||||||
Gathering and transportation | 12,676 | 4,244 | — | 16,920 | |||||||||||||
Depreciation, depletion and amortization | 214,740 | 84,275 | — | 299,015 | |||||||||||||
Asset retirement obligation accretion | 26,947 | 2,824 | — | 29,771 | |||||||||||||
General and administrative expenses | 71,714 | 2,582 | — | 74,296 | |||||||||||||
Derivative gain | (1,896 | ) | — | — | (1,896 | ) | |||||||||||
Total costs and expenses | 510,621 | 130,966 | — | 641,587 | |||||||||||||
Operating income | 187,278 | 142,182 | — | 329,460 | |||||||||||||
Earnings of affiliates | 92,533 | — | (92,533 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 52,393 | — | — | 52,393 | |||||||||||||
Capitalized | (9,877 | ) | — | — | (9,877 | ) | |||||||||||
Loss on extinguishment of debt | 22,694 | — | — | 22,694 | |||||||||||||
Other income | 84 | — | — | 84 | |||||||||||||
Income before income tax expense | 214,685 | 142,182 | (92,533 | ) | 264,334 | ||||||||||||
Income tax expense | 41,868 | 49,649 | — | 91,517 | |||||||||||||
Net income | $ | 172,817 | $ | 92,533 | $ | (92,533 | ) | $ | 172,817 | ||||||||
Condensed Consolidating Statement of Cash Flows for the Twelve Months Ended December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 51,322 | $ | 45,209 | $ | (45,209 | ) | $ | 51,322 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 342,946 | 108,583 | — | 451,529 | |||||||||||||
Amortization of debt issuance costs and premium | 1,645 | — | — | 1,645 | |||||||||||||
Loss on extinguishment of debt | 128 | — | — | 128 | |||||||||||||
Share-based compensation | 11,525 | — | — | 11,525 | |||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | |||||||||||||
Cash payments on derivative settlements (realized) | (8,589 | ) | — | — | (8,589 | ) | |||||||||||
Deferred income taxes | 11,522 | 19,398 | — | 30,920 | |||||||||||||
Earnings of affiliates | (45,209 | ) | — | 45,209 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | 5,242 | (4,262 | ) | — | 980 | ||||||||||||
Joint interest and other receivables | 28,566 | — | — | 28,566 | |||||||||||||
Insurance proceeds | 5,691 | — | — | 5,691 | |||||||||||||
Income taxes | 39,188 | 5,140 | — | 44,328 | |||||||||||||
Prepaid expenses and other assets | (5,606 | ) | (38,558 | ) | 34,120 | (10,044 | ) | ||||||||||
Asset retirement obligations | (79,950 | ) | (1,593 | ) | — | (81,543 | ) | ||||||||||
Accounts payable and accrued liabilities | 27,415 | 717 | — | 28,132 | |||||||||||||
Other | 32,418 | — | (34,120 | ) | (1,702 | ) | |||||||||||
Net cash provided by operating activities | 426,724 | 134,634 | — | 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 | (331,303 | ) | (220,651 | ) | — | (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, misc. sales and other | (1,435 | ) | — | — | (1,435 | ) | |||||||||||
Net cash used in investing activities | (480,171 | ) | (220,651 | ) | 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 provided by 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 Twelve Months Ended December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 71,984 | $ | 66,195 | $ | (66,195 | ) | $ | 71,984 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 271,270 | 84,962 | — | 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 (realized) | (7,664 | ) | — | — | (7,664 | ) | |||||||||||
Deferred income taxes | 83,981 | 4,128 | — | 88,109 | |||||||||||||
Earnings of affiliates | (66,195 | ) | — | 66,195 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | (2,597 | ) | 3,415 | — | 818 | ||||||||||||
Joint interest and other receivables | (31,399 | ) | — | — | (31,399 | ) | |||||||||||
Insurance proceeds | 2,576 | — | — | 2,576 | |||||||||||||
Income taxes | (89,568 | ) | 31,557 | — | (58,011 | ) | |||||||||||
Prepaid expenses and other assets | 7,442 | (118,320 | ) | 118,318 | 7,440 | ||||||||||||
Asset retirement obligations | (112,199 | ) | (628 | ) | — | (112,827 | ) | ||||||||||
Accounts payable and accrued liabilities | 40,530 | (2,504 | ) | — | 38,026 | ||||||||||||
Other | 119,244 | — | (118,318 | ) | 926 | ||||||||||||
Net cash provided by operating activities | 316,332 | 68,805 | — | 385,137 | |||||||||||||
Investing activities: | |||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (205,550 | ) | — | — | (205,550 | ) | |||||||||||
Investment in oil and natural gas properties and equipment | (410,508 | ) | (68,805 | ) | — | (479,313 | ) | ||||||||||
Proceeds from sales of assets and other, net | 30,453 | — | — | 30,453 | |||||||||||||
Purchases of furniture, fixtures, misc. sales and other | (3,031 | ) | — | — | (3,031 | ) | |||||||||||
Net cash used in investing activities | (588,636 | ) | (68,805 | ) | — | (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 | ) | |||||||||||
Other | 379 | — | — | 379 | |||||||||||||
Net cash provided by financing activities | 280,037 | — | — | 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 | |||||||||
Condensed Consolidating Statement of Cash Flows for the Twelve Months Ended December 31, 2011 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 172,817 | $ | 92,533 | $ | (92,533 | ) | $ | 172,817 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 241,687 | 87,099 | — | 328,786 | |||||||||||||
Amortization of debt issuance costs | 2,010 | — | — | 2,010 | |||||||||||||
Loss on extinguishment of debt | 22,694 | — | — | 22,694 | |||||||||||||
Share-based compensation | 9,710 | — | — | 9,710 | |||||||||||||
Derivative gain | (1,896 | ) | — | — | (1,896 | ) | |||||||||||
Cash payments on derivative settlements (realized) | (9,873 | ) | — | — | (9,873 | ) | |||||||||||
Deferred income taxes | 76,717 | (14,882 | ) | — | 61,835 | ||||||||||||
Earnings of affiliates | (92,533 | ) | — | 92,533 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | (27,709 | ) | 9,070 | — | (18,639 | ) | |||||||||||
Joint interest and other receivables | 375 | — | — | 375 | |||||||||||||
Insurance proceeds | 20,771 | — | — | 20,771 | |||||||||||||
Income taxes | (71,655 | ) | 64,531 | — | (7,124 | ) | |||||||||||
Prepaid expenses and other assets | (8,003 | ) | (228,020 | ) | 228,214 | (7,809 | ) | ||||||||||
Asset retirement obligations | (59,958 | ) | — | — | (59,958 | ) | |||||||||||
Accounts payable and accrued liabilities | 8,589 | (514 | ) | (194 | ) | 7,881 | |||||||||||
Other | 227,918 | — | (228,020 | ) | (102 | ) | |||||||||||
Net cash provided by operating activities | 511,661 | 9,817 | — | 521,478 | |||||||||||||
Investing activities: | |||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (437,247 | ) | — | — | (437,247 | ) | |||||||||||
Investment in oil and natural gas properties and equipment | (277,147 | ) | (4,632 | ) | — | (281,779 | ) | ||||||||||
Investment in subsidiary | 5,185 | — | (5,185 | ) | — | ||||||||||||
Proceeds from sales of assets and other, net | 15 | — | — | 15 | |||||||||||||
Purchases of furniture, fixtures, misc. sales and other | (3,660 | ) | — | — | (3,660 | ) | |||||||||||
Net cash used in investing activities | (712,854 | ) | (4,632 | ) | (5,185 | ) | (722,671 | ) | |||||||||
Financing activities: | |||||||||||||||||
Issuance of 8.50% Senior Notes | 600,000 | — | — | 600,000 | |||||||||||||
Repurchase of 8.25% Senior Notes | (450,000 | ) | — | — | (450,000 | ) | |||||||||||
Borrowings of long-term debt - revolving bank credit facility | 623,000 | — | — | 623,000 | |||||||||||||
Repayments of long-term debt - revolving bank credit facility | (506,000 | ) | — | — | (506,000 | ) | |||||||||||
Repurchase premium and debt issuance costs | (32,288 | ) | — | — | (32,288 | ) | |||||||||||
Dividends to shareholders | (58,756 | ) | — | — | (58,756 | ) | |||||||||||
Investment from parent | — | (5,185 | ) | 5,185 | — | ||||||||||||
Other | 1,094 | — | — | 1,094 | |||||||||||||
Net cash provided by (used in) financing activities | 177,050 | (5,185 | ) | 5,185 | 177,050 | ||||||||||||
Decrease in cash and cash equivalents | (24,143 | ) | — | — | (24,143 | ) | |||||||||||
Cash and cash equivalents, beginning of period | 28,655 | — | — | 28,655 | |||||||||||||
Cash and cash equivalents, end of period | $ | 4,512 | $ | — | $ | — | $ | 4,512 | |||||||||
Supplemental_Oil_and_Gas_Discl
Supplemental Oil and Gas Disclosures-unaudited | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Net capitalized cost: | |||||||||||||||||||||
Proved oil and natural gas properties and equipment | $ | 7,207.10 | $ | 6,551.50 | $ | 5,775.40 | |||||||||||||||
Unproved oil and natural gas properties and equipment | 132 | 143 | 183.6 | ||||||||||||||||||
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | (5,069.2 | ) | (4,640.8 | ) | (4,307.1 | ) | |||||||||||||||
Net capitalized costs related to producing activities | $ | 2,269.90 | $ | 2,053.70 | $ | 1,651.90 | |||||||||||||||
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, 2013, by the year in which the costs were incurred (in millions): | |||||||||||||||||||||
Total | 2013 | 2012 | 2011 | Prior to | |||||||||||||||||
2011 | |||||||||||||||||||||
Costs excluded by year incurred: | |||||||||||||||||||||
Acquisition costs | $ | 87.3 | $ | 9.2 | $ | 8.7 | $ | 50.1 | $ | 19.3 | |||||||||||
Capitalized interest not subject to amortization | 29.3 | 8.4 | 7.4 | 5.1 | 8.4 | ||||||||||||||||
Total costs not subject to amortization | $ | 116.6 | $ | 17.6 | $ | 16.1 | $ | 55.2 | $ | 27.7 | |||||||||||
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): | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Costs incurred (1): | |||||||||||||||||||||
Proved property acquisitions | $ | 96.9 | $ | 239.8 | $ | 369.9 | |||||||||||||||
Exploration (2) (3) | 215.3 | 151.3 | 92.7 | ||||||||||||||||||
Development | 352.9 | 363.7 | 203.7 | ||||||||||||||||||
Unproved property acquisitions (4) | 26.3 | 26.5 | 95.1 | ||||||||||||||||||
Total costs incurred in oil and gas property acquisition, exploration and development activities | $ | 691.4 | $ | 781.3 | $ | 761.4 | |||||||||||||||
-1 | Includes net additions to our ARO of $50.6 million, $86.9 million and $32.8 million during 2013, 2012 and 2011, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5. | ||||||||||||||||||||
-2 | Includes seismic costs of $8.9 million, $6.2 million and $8.0 million incurred during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||
-3 | Includes geological and geophysical costs charged to expense of $5.9 million, $6.2 million and $6.8 million during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||
-4 | The amounts for unproved property acquisitions include capitalized interest associated with properties classified as unproved as of the end of the period. | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion expense | |||||||||||||||||||||
The following table presents our depreciation, depletion, amortization and accretion expense per thousand cubic feet equivalent (“Mcfe”) of products sold. | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Depreciation, depletion, amortization and accretion per Mcfe | $ | 4.18 | $ | 3.47 | $ | 3.24 | |||||||||||||||
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 9% 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 and the majority of the reserves are located in the Gulf of Mexico. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. Estimated reserves for the periods presented are 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. | |||||||||||||||||||||
Total Equivalent Reserves | |||||||||||||||||||||
Oil | NGLs | Natural Gas | Oil | Natural Gas | |||||||||||||||||
(MMBbls) | (MMBbls) | (Bcf) | Equivalent | Equivalent | |||||||||||||||||
(MMBoe) (1) | (Bcfe) (1) | ||||||||||||||||||||
Proved reserves as of December 31, 2010 | 34 | 4.2 | 256.3 | 80.9 | 485.4 | ||||||||||||||||
Revisions of previous estimates (2) | 0.8 | 5.5 | 13.5 | 8.6 | 51.1 | ||||||||||||||||
Extensions and discoveries (3) | 2 | 0.4 | 17.7 | 5.3 | 32 | ||||||||||||||||
Purchase of minerals in place (4) | 20.7 | 8.9 | 55.9 | 39 | 234.1 | ||||||||||||||||
Production | (6.1 | ) | (1.9 | ) | (53.7 | ) | (16.9 | ) | (101.5 | ) | |||||||||||
Proved reserves as of December 31, 2011 | 51.4 | 17.1 | 289.7 | 116.9 | 701.1 | ||||||||||||||||
Revisions of previous estimates (5) | (1.1 | ) | (2.6 | ) | (4.8 | ) | (4.6 | ) | (27.5 | ) | |||||||||||
Extensions and discoveries (6) | 8.2 | 2.6 | 29.6 | 15.7 | 94.5 | ||||||||||||||||
Purchase of minerals in place (7) | 2.5 | 0.2 | 25.5 | 7 | 42 | ||||||||||||||||
Sales of reserves (8) | (0.2 | ) | — | (1.1 | ) | (0.4 | ) | (2.2 | ) | ||||||||||||
Production | (6.0 | ) | (2.1 | ) | (53.8 | ) | (17.1 | ) | (102.8 | ) | |||||||||||
Proved reserves as of December 31, 2012 | 54.8 | 15.2 | 285.1 | 117.5 | 705.1 | ||||||||||||||||
Revisions of previous estimates (9) | (4.3 | ) | 0.2 | 2.1 | (3.8 | ) | (22.8 | ) | |||||||||||||
Extensions and discoveries (10) | 13.9 | 2.6 | 22 | 20.2 | 121 | ||||||||||||||||
Purchase of minerals in place (11) | 1.5 | — | 4.4 | 2.3 | 13.7 | ||||||||||||||||
Sales of reserves (12) | (0.4 | ) | — | (0.4 | ) | (0.5 | ) | (3.2 | ) | ||||||||||||
Production | (7.0 | ) | (2.1 | ) | (53.3 | ) | (18.0 | ) | (107.9 | ) | |||||||||||
Proved reserves as of December 31, 2013 | 58.5 | 15.9 | 259.9 | 117.7 | 705.9 | ||||||||||||||||
Year-end proved developed reserves: | |||||||||||||||||||||
2013 | 36.2 | 11.1 | 232.7 | 86.1 | 516.1 | ||||||||||||||||
2012 | 35.3 | 11 | 243.5 | 86.9 | 521.2 | ||||||||||||||||
2011 | 23.4 | 11 | 251.4 | 76.4 | 458.2 | ||||||||||||||||
Year-end proved undeveloped reserves: | |||||||||||||||||||||
2013 | 22.3 | 4.8 | 27.2 | 31.6 | 189.8 | ||||||||||||||||
2012 | 19.5 | 4.2 | 41.6 | 30.6 | 183.9 | ||||||||||||||||
2011 | 28 | 6.1 | 38.3 | 40.5 | 242.9 | ||||||||||||||||
-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 revision of 6.3 Bcfe due to an increase in average prices; 16.5 Bcfe for a change in NGLs marketing arrangements; 11.3 Bcfe increase due to additional compression at our Tahoe field that increases production and ultimate recoveries; and 10.6 Bcfe at our Fairway field for revisions to reserve estimates from the acquisition date to year end. | ||||||||||||||||||||
-3 | Includes discoveries of 13.9 Bcfe at our Main Pass 98 field and 8.0 Bcfe at our Ship Shoal 349/359 field and extensions of 3.7 Bcfe at our Main Pass 108 field. | ||||||||||||||||||||
-4 | Primarily due to the acquisition of the Opal Properties and the Fairway Properties. | ||||||||||||||||||||
-5 | Includes downward revisions due to price of 8.0 Bcfe and negative performance revisions of 17.9 Bcfe at our Spraberry field. | ||||||||||||||||||||
-6 | Includes extensions and discoveries of 69.5 Bcfe at our Spraberry field and extensions and discoveries of 16.2 Bcfe at our High Island 21/22 field. | ||||||||||||||||||||
-7 | Due to the acquisition of the Newfield Properties. | ||||||||||||||||||||
-8 | Due to the sale of our interest in the South Timbalier 41 field. | ||||||||||||||||||||
-9 | Includes upward revision due to price of 11.3 Bcfe; negative revisions of 29.6 Bcfe at our Spraberry field for performance and technical changes, 13.9 Bcfe at our High Island 21/22 field for performance, 7.9 Bcfe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 4.3 Bcfe at our Main Pass 98 field, 4.0 Bcfe at our South Timbalier 314, 3.5 Bcfe at our Main Pass 108 field and 3.2 at our South Timbalier 176 field. | ||||||||||||||||||||
-10 | Includes extensions and discoveries of 75.4 Bcfe at our Spraberry field, 25.3 Bcfe at our Ship Shoal 349/359 field and 11.5 Bcfe at our Mississippi Canyon 698 field. | ||||||||||||||||||||
-11 | Primarily due to the acquisition of the Callon Properties. | ||||||||||||||||||||
-12 | 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. | ||||||||||||||||||||
Volume measurements: | |||||||||||||||||||||
Mcf – thousand cubic feet | Bbl - barrel | ||||||||||||||||||||
Bcf – billion cubic feet | MMBbls - million barrels for crude oil, condensate or NGLs | ||||||||||||||||||||
Bcfe – billion cubic feet equivalent | MMBoe – million barrels of oil equivalent | ||||||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | 2010 | ||||||||||||||||||
Oil – per barrel | $ | 99.65 | $ | 98.13 | $ | 97.36 | $ | 76.28 | |||||||||||||
NGLs – per barrel | 35.21 | 47.3 | 51.3 | 44.92 | |||||||||||||||||
Natural gas – per Mcf | 3.8 | 2.77 | 4.11 | 4.57 | |||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | |||||||||||||||||||||
Future cash inflows | $ | 7,376.70 | $ | 6,888.40 | $ | 7,077.20 | |||||||||||||||
Future costs: | |||||||||||||||||||||
Production | (2,142.8 | ) | (1,858.3 | ) | (1,862.5 | ) | |||||||||||||||
Development | (1,001.4 | ) | (655.4 | ) | (543.0 | ) | |||||||||||||||
Dismantlement and abandonment | (441.6 | ) | (508.0 | ) | (513.6 | ) | |||||||||||||||
Income taxes | (986.9 | ) | (1,002.1 | ) | (1,126.6 | ) | |||||||||||||||
Future net cash inflows before 10% discount | 2,804.00 | 2,864.60 | 3,031.50 | ||||||||||||||||||
10% annual discount factor | (1,129.4 | ) | (1,018.2 | ) | (1,025.1 | ) | |||||||||||||||
Total | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | |||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Changes in Standardized Measure | |||||||||||||||||||||
Standardized measure, beginning of year | $ | 1,846.40 | $ | 2,006.40 | $ | 1,179.10 | |||||||||||||||
Increases (decreases): | |||||||||||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (686.1 | ) | (620.4 | ) | (729.6 | ) | |||||||||||||||
Net changes in price, net of future production costs | (65.2 | ) | (224.3 | ) | 634.2 | ||||||||||||||||
Extensions and discoveries, net of future production and development costs | 393.8 | 181.9 | 219.9 | ||||||||||||||||||
Changes in estimated future development costs | (91.1 | ) | (103.3 | ) | (4.6 | ) | |||||||||||||||
Previously estimated development costs incurred | 262.1 | 332.9 | 173.9 | ||||||||||||||||||
Revisions of quantity estimates | (91.6 | ) | (128.1 | ) | 205 | ||||||||||||||||
Accretion of discount | 202.2 | 231.1 | 135.8 | ||||||||||||||||||
Net change in income taxes | 56.6 | 99.7 | (398.2 | ) | |||||||||||||||||
Purchases of reserves in-place | 79.6 | 270.2 | 483.3 | ||||||||||||||||||
Sales of reserves in-place | (53.1 | ) | (16.1 | ) | — | ||||||||||||||||
Changes in production rates due to timing and other | (179.0 | ) | (183.6 | ) | 107.6 | ||||||||||||||||
Net increase (decrease) in standardized measure | (171.8 | ) | (160.0 | ) | 827.3 | ||||||||||||||||
Standardized measure, end of year | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | |||||||||||||||
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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. and our wholly-own subsidiary, W&T Energy VI, LLC. | |||||||||||||
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. Deferred income taxes – current asset was combined with Prepaid expenses and other assets on the Consolidated Balance Sheet, Income taxes payable was combined with Accrued liabilities on the Consolidated Balance Sheet, and changes in Other liabilities was combined with the changes in Accounts payable and accrued liabilities on the Consolidated Statement 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. | |||||||||||||
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 December 31, 2013 and 2012, $6.4 million and $6.0 million, respectively, were 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. | |||||||||||||
The following identifies customers from whom we derived 10% or more of receipts from sales of oil, natural gas liquids (“NGLs”) and natural gas. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Customer | |||||||||||||
Shell Trading (US) Co. | 48 | % | 35 | % | 36 | % | |||||||
ConocoPhillips (1) | ** | 16 | % | 16 | % | ||||||||
J.P. Morgan Ventures Energy Corp. | ** | ** | 10 | % | |||||||||
** | 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 Receivable | ' | ||||||||||||
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. | |||||||||||||
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 expenditures made in connection with the exploration and development 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 Sheet. | |||||||||||||
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. These additional costs related to developing proved reserves are not recorded as liabilities on the balance sheet. | |||||||||||||
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 oil and natural gas prices after December 31, 2013 may require us to record additional ceiling-test impairments in the future. We did not have any write-downs related to ceiling-test impairments during 2013, 2012 and 2011, 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 was determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs were: (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 were 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 could vary significantly from these estimates. No goodwill was recorded for the acquisitions completed in 2013, 2012 or 2011. | |||||||||||||
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 share 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 | ' | ||||||||||||
Other Income | |||||||||||||
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 statement of cash flows. | |||||||||||||
Recent Accounting Developments | ' | ||||||||||||
Recent Accounting Developments | |||||||||||||
In February 2013, the Financial Accounting Standards Board (“FASB”) issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. The Company does not expect its disclosures to be affected by ASU 2013-04. | |||||||||||||
In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740); Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists - a consensus of the FASB Emerging Task Force, which provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. The amendment is effective for annual periods and interim periods beginning after December 15, 2013. Early adoption is permitted and the amendment is to be applied prospectively. The Company does not expect its balance sheet presentation or its disclosures to be affected by ASU 2013-11. |
Significant_Accounting_Policie2
Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Percentage of Revenue by Major Customers | ' | ||||||||||||
The following identifies customers from whom we derived 10% or more of receipts from sales of oil, natural gas liquids (“NGLs”) and natural gas. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Customer | |||||||||||||
Shell Trading (US) Co. | 48 | % | 35 | % | 36 | % | |||||||
ConocoPhillips (1) | ** | 16 | % | 16 | % | ||||||||
J.P. Morgan Ventures Energy Corp. | ** | ** | 10 | % | |||||||||
** | less than 10% | ||||||||||||
-1 | 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, 2013 | |||||||||
Callon Properties | ' | ||||||||
Purchase Price Allocation for Acquisition | ' | ||||||||
The following table presents the preliminary purchase price allocation, including estimated adjustments, for the acquisition of the Callon Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 73,176 | |||||||
Unevaluated properties | 9,248 | ||||||||
Sub-total – cash consideration | 82,424 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - current | 90 | ||||||||
Asset retirement obligation - non-current | 4,143 | ||||||||
Sub-total – non-cash consideration | 4,233 | ||||||||
Total consideration | $ | 86,657 | |||||||
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 | 59,073 | 85,378 | |||||||
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 | 2012 | ||||||||
Revenues (a) | $ | 34,030 | $ | 48,559 | |||||
Direct operating expenses (a) | 6,405 | 8,525 | |||||||
DD&A (b) | 14,856 | 17,492 | |||||||
G&A (c) | (361 | ) | — | ||||||
Interest expense (d) | 1,374 | 1,648 | |||||||
Capitalized interest (e) | (168 | ) | 288 | ||||||
Income tax expense (f) | 4,173 | 7,212 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | ||||||||
(b) | 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. | ||||||||
(c) | 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. | ||||||||
(d) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $82.4 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. | ||||||||
(e) | 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. Positive amounts represent increases to net expenses. The negative amount represents a decrease to net expenses. | ||||||||
(f) | 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 | ' | ||||||||
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 obligation - current | 7,250 | ||||||||
Asset retirement obligation - 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 December 31, | |||||||||
2012 | 2011 | ||||||||
Revenue | $ | 980,196 | $ | 1,187,808 | |||||
Net income | 77,036 | 220,835 | |||||||
Basic and diluted earnings per common share | 1.01 | 2.92 | |||||||
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 | 2011 | ||||||||
Revenues (a) | $ | 105,705 | $ | 216,761 | |||||
Direct operating expenses (a) | 33,186 | 24,563 | |||||||
Insurance costs (b) | 475 | 633 | |||||||
DD&A (c) | 53,408 | 102,713 | |||||||
G&A (d) | (553 | ) | — | ||||||
Interest expense (e) | 12,060 | 15,846 | |||||||
Capitalized interest (f) | (643 | ) | (868 | ) | |||||
Income tax expense (g) | 2,720 | 25,856 | |||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | ||||||||
(b) | 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. | ||||||||
(c) | 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. | ||||||||
(d) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | ||||||||
(e) | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.7 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. | ||||||||
(f) | 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. | ||||||||
(g) | 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. | |||||||||
Opal Properties | ' | ||||||||
Purchase Price Allocation for Acquisition | ' | ||||||||
The following table presents the purchase price allocation, including adjustments, for the acquisition of the Opal Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 313,165 | |||||||
Unevaluated properties | 81,212 | ||||||||
Sub-total – cash consideration | 394,377 | ||||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - non-current | 382 | ||||||||
Long-term liability | 2,143 | ||||||||
Sub-total – non-cash consideration | 2,525 | ||||||||
Total consideration | $ | 396,902 | |||||||
Fairway Properties | ' | ||||||||
Purchase Price Allocation for Acquisition | ' | ||||||||
The following table presents the purchase price allocation, including adjustments, for the acquisition of the Fairway Properties (in thousands): | |||||||||
Cash consideration: | |||||||||
Evaluated properties including equipment | $ | 42,870 | |||||||
Non-cash consideration: | |||||||||
Asset retirement obligation - non-current | 7,812 | ||||||||
Total consideration | $ | 50,682 | |||||||
Opal Properties And Fairway Properties | ' | ||||||||
Summary of Proforma Financial Information for Acquisition | ' | ||||||||
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Opal Properties and the Fairway Properties. The pro forma financial information is not necessarily indicative of the results of operations had the respective purchases occurred on January 1, 2010. If the transactions 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 the sellers. Realized sales prices for oil, NGLs and natural gas may have been different and costs of operating the 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, | |||||||||
2011 | |||||||||
Revenue | $ | 1,023,430 | |||||||
Net income | 180,779 | ||||||||
Basic and diluted earnings per common share | 2.39 | ||||||||
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 Opal Properties and the Fairway Properties (in thousands): | |||||||||
(unaudited) | |||||||||
Year Ended | |||||||||
December 31, | |||||||||
2011 | |||||||||
Revenues (a) | $ | 52,383 | |||||||
Direct operating expenses (a) | 16,368 | ||||||||
DD&A (b) | 21,836 | ||||||||
G&A (c) | (1,596 | ) | |||||||
Interest expense (d) | 4,612 | ||||||||
Capitalized interest (e) | (1,086 | ) | |||||||
Income tax expense (f) | 4,287 | ||||||||
The sources of information and significant assumptions are described below: | |||||||||
(a) | Revenues and direct operating expenses for the Opal Properties and the Fairway Properties were derived from the historical records of the sellers up to the respective closing dates. | ||||||||
(b) | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Opal Properties and Fairway 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 were estimated by W&T management. | ||||||||
(c) | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2011 results. | ||||||||
(d) | The acquisitions were assumed to be funded entirely with borrowed funds and that borrow capacity would have been available on the revolving bank credit facility due to the increase in reserves. Interest expense was computed using assumed borrowings of $437.2 million, which equates to the cash component of the transactions, and an interest rate ranging from 2.6% to 3.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | ||||||||
(e) | 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. | ||||||||
(f) | 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, 2013 | |||||||||
Reconciliation of Asset Retirement Obligations Liability | ' | ||||||||
The following is a reconciliation of our ARO liability (in thousands): | |||||||||
2013 | 2012 | ||||||||
Asset retirement obligations, beginning of period | $ | 384,053 | $ | 393,880 | |||||
Liabilities settled | (81,543 | ) | (112,827 | ) | |||||
Accretion of discount | 20,918 | 20,055 | |||||||
Disposition of properties | (19,564 | ) | (3,993 | ) | |||||
Liabilities assumed through acquisition | 4,233 | 31,664 | |||||||
Liabilities incurred | 1,745 | 1,815 | |||||||
Revisions of estimated liabilities due to Hurricane Ike | 6,801 | (20,616 | ) | ||||||
Revisions of estimated liabilities—all other | 37,779 | 74,075 | |||||||
Asset retirement obligations, end of period | 354,422 | 384,053 | |||||||
Less current portion | 77,785 | 92,630 | |||||||
Long-term | $ | 276,637 | $ | 291,423 | |||||
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | ||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||
Open Commodity Derivatives | ' | ||||||||||||||||||||||||||
As of December 31, 2013, our open commodity derivative contracts were as follows: | |||||||||||||||||||||||||||
Swaps – Oil | |||||||||||||||||||||||||||
Priced off Brent | Priced off WTI | Priced off LLS | |||||||||||||||||||||||||
(ICE) | (NYMEX) | (ARGUS) | |||||||||||||||||||||||||
Termination Period | Notional | Weighted | Notional | Weighted | Notional | Weighted | |||||||||||||||||||||
Quantity | Average | Quantity | Average | Quantity | Average | ||||||||||||||||||||||
(Bbls) | Contract | (Bbls) | Contract | (Bbls) | Contract | ||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||||
2014:00:00 | 1st Qtr | 180,000 | $ | 97.38 | 762,000 | $ | 97.39 | 180,000 | $ | 98.2 | |||||||||||||||||
2nd Qtr | 172,900 | 97.38 | 455,000 | 97.17 | 364,000 | 97.88 | |||||||||||||||||||||
3rd Qtr | 165,600 | 97.38 | 155,000 | 97 | 552,000 | 97.65 | |||||||||||||||||||||
4th Qtr | 156,400 | 97.37 | — | — | 368,000 | 97.88 | |||||||||||||||||||||
674,900 | $ | 97.38 | 1,372,000 | $ | 97.27 | 1,464,000 | $ | 97.83 | |||||||||||||||||||
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, | |||||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||||
Prepaid and other assets | $ | 141 | $ | — | |||||||||||||||||||||||
Accrued liabilities | 9,423 | 6,355 | |||||||||||||||||||||||||
Other liabilities (noncurrent) | — | 3,046 | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||||
Derivative (gain) loss: | 2013 | 2012 | 2011 | ||||||||||||||||||||||||
Realized | $ | 8,589 | $ | 7,665 | $ | 9,873 | |||||||||||||||||||||
Unrealized | (119 | ) | 6,289 | (11,769 | ) | ||||||||||||||||||||||
Total | $ | 8,470 | $ | 13,954 | $ | (1,896 | ) | ||||||||||||||||||||
Reconciliation of Gross Assets and Liabilities and Netting Agreements on Fair Value of Open Derivative Contracts | ' | ||||||||||||||||||||||||||
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): | |||||||||||||||||||||||||||
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, 2013 | |||||||||
Long-Term Debt | ' | ||||||||
As of December 31, 2013 and 2012 our long-term debt was as follows (in thousands): | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
8.50% Senior Notes, due June 2019 | $ | 900,000 | $ | 900,000 | |||||
Debt premiums, net of amortization | 15,421 | 17,611 | |||||||
Revolving bank credit facility, due Nov 2018 | 290,000 | 170,000 | |||||||
Total long-term debt (1) | 1,205,421 | 1,087,611 | |||||||
Current maturities of long-term debt | — | — | |||||||
Long-term debt, less current maturities | $ | 1,205,421 | $ | 1,087,611 | |||||
-1 | Aggregate annual maturities of long-term debt as of December 31, 2013 are as follows (in millions): 2014–$0.0; 2015–$0.0; 2016–$0.0; 2017–$0.0; thereafter–$1,190.0. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
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). | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
Hierarchy | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
Derivatives | Level 2 | $ | 141 | $ | 9,423 | $ | — | $ | 9,401 | ||||||||||||
8.50% Senior Notes | Level 2 | — | 962,460 | — | 963,000 | ||||||||||||||||
Revolving bank credit facility | Level 2 | — | 290,000 | — | 170,000 | ||||||||||||||||
ShareBased_and_CashBased_Incen1
Share-Based and Cash-Based Incentive Compensation (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | ' | ||||||||||||||||||||||||
A summary of activity related to restricted stock is as follows: | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Restricted | Weighted | Restricted | Weighted | Restricted | Weighted | ||||||||||||||||||||
Shares | Average | Shares | Average | Shares | Average | ||||||||||||||||||||
Grant Date | Grant Date | Grant Date | |||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||
Per Share | Per Share | Per Share | |||||||||||||||||||||||
Nonvested, beginning of period | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | 470,392 | $ | 7.42 | ||||||||||||||||
Granted | 27,450 | 12.75 | 21,954 | 19.13 | 20,433 | 25.45 | |||||||||||||||||||
Vested | (27,297 | ) | 17.09 | (27,475 | ) | 13.59 | (404,422 | ) | 7.31 | ||||||||||||||||
Forfeited | — | — | (2,662 | ) | 18.78 | (34,533 | ) | 6.83 | |||||||||||||||||
Nonvested, end of period | 43,840 | $ | 15.96 | 43,687 | $ | 18.69 | 51,870 | $ | 15.81 | ||||||||||||||||
Schedule of Restricted Stock Awards Outstanding | ' | ||||||||||||||||||||||||
Subject to the satisfaction of service conditions, the restricted shares outstanding as of December 31, 2013 are expected to vest as follows: | |||||||||||||||||||||||||
Shares | |||||||||||||||||||||||||
2014 | 19,445 | ||||||||||||||||||||||||
2015 | 15,245 | ||||||||||||||||||||||||
2016 | 9,150 | ||||||||||||||||||||||||
Total | 43,840 | ||||||||||||||||||||||||
Summary of Share Activity Related to Restricted Stock Units | ' | ||||||||||||||||||||||||
A summary of activity related to RSUs is as follows: | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
RSUs | Weighted | RSUs | Weighted | Weighted | |||||||||||||||||||||
Average | Average | RSUs | Average | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | |||||||||||||||||||||||
Price | Price | Price | |||||||||||||||||||||||
Per RSU | Per RSU | Per RSU | |||||||||||||||||||||||
Nonvested, beginning of period | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | 1,266,617 | $ | 9.36 | ||||||||||||||||
Granted | 969,919 | 13.23 | 764,654 | 18.64 | 534,375 | 26.93 | |||||||||||||||||||
Vested | (468,925 | ) | 26.93 | (1,198,208 | ) | 9.36 | — | — | |||||||||||||||||
Forfeited | (139,061 | ) | 16.5 | (329,329 | ) | 19.56 | (68,289 | ) | 12.03 | ||||||||||||||||
Nonvested, end of period | 1,331,753 | $ | 14.96 | 969,820 | $ | 22.7 | 1,732,703 | $ | 14.67 | ||||||||||||||||
Schedule of Restricted Stock Awards Outstanding | ' | ||||||||||||||||||||||||
Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2013 are eligible to vest in the year indicated in the table below: | |||||||||||||||||||||||||
RSUs | |||||||||||||||||||||||||
2014 – subject to service requirements | 359,785 | ||||||||||||||||||||||||
2014 – subject to service and other requirements (1) | 67,877 | ||||||||||||||||||||||||
2015 – subject to service requirements | 719,971 | ||||||||||||||||||||||||
2015 – subject to service and other requirements (1) | 184,120 | ||||||||||||||||||||||||
Total | 1,331,753 | ||||||||||||||||||||||||
-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, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Share-based compensation expense from: | |||||||||||||||||||||||||
Restricted stock | $ | 397 | $ | 399 | $ | 2,377 | |||||||||||||||||||
Restricted stock units | 11,128 | 11,999 | 7,333 | ||||||||||||||||||||||
Total | $ | 11,525 | $ | 12,398 | $ | 9,710 | |||||||||||||||||||
Share-based compensation tax benefit: | |||||||||||||||||||||||||
Tax benefit computed at the statutory rate | $ | 4,034 | $ | 4,339 | $ | 3,399 | |||||||||||||||||||
Summary of Incentive Compensation Expense | ' | ||||||||||||||||||||||||
A summary of incentive compensation expense is as follows (in thousands): | |||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Share-based compensation expense included in: | |||||||||||||||||||||||||
Lease operating expense | $ | — | $ | — | $ | 466 | |||||||||||||||||||
General and administrative | 11,525 | 12,398 | 9,244 | ||||||||||||||||||||||
Total charged to operating income | 11,525 | 12,398 | 9,710 | ||||||||||||||||||||||
Cash-based incentive compensation included in: | |||||||||||||||||||||||||
Lease operating expense | 3,482 | 3,787 | 3,700 | ||||||||||||||||||||||
General and administrative | 8,817 | 6,558 | 12,213 | ||||||||||||||||||||||
Total charged to operating income | 12,299 | 10,345 | 15,913 | ||||||||||||||||||||||
Total incentive compensation charged to operating income | $ | 23,824 | $ | 22,743 | $ | 25,623 | |||||||||||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Components of Income Tax Expense | ' | ||||||||||||||||||||||||
Components of income tax expense were as follows (in thousands): | |||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Current | $ | (2,146 | ) | $ | (40,562 | ) | $ | 29,682 | |||||||||||||||||
Deferred | 30,920 | 88,109 | 61,835 | ||||||||||||||||||||||
$ | 28,774 | $ | 47,547 | $ | 91,517 | ||||||||||||||||||||
Reconciliation of Income Taxes Computed to Income Tax Expense | ' | ||||||||||||||||||||||||
The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense is as follows (in thousands): | |||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Income tax expense at the federal statutory rate | $ | 28,033 | 35 | % | $ | 41,836 | 35 | % | $ | 92,517 | 35 | % | |||||||||||||
Qualified domestic production activities | — | — | 4,256 | 3.5 | (1,823 | ) | (0.7 | ) | |||||||||||||||||
State income taxes | 343 | 0.4 | 750 | 0.7 | 603 | 0.2 | |||||||||||||||||||
Other | 398 | 0.5 | 705 | 0.6 | 220 | 0.1 | |||||||||||||||||||
$ | 28,774 | 35.9 | % | $ | 47,547 | 39.8 | % | $ | 91,517 | 34.6 | % | ||||||||||||||
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, | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Deferred tax liabilities: | |||||||||||||||||||||||||
Property and equipment | $ | 297,942 | $ | 186,599 | |||||||||||||||||||||
Other | 3,602 | 4,822 | |||||||||||||||||||||||
Total deferred tax liabilities | 301,544 | 191,421 | |||||||||||||||||||||||
Deferred tax assets: | |||||||||||||||||||||||||
Minimum tax credit | 20,486 | 22,314 | |||||||||||||||||||||||
Federal net operating losses | 91,472 | 12,389 | |||||||||||||||||||||||
State net operating losses | 5,028 | 5,057 | |||||||||||||||||||||||
Derivatives | 3,270 | 3,312 | |||||||||||||||||||||||
Valuation allowance (state) | (4,490 | ) | (4,674 | ) | |||||||||||||||||||||
Accrued cash-based bonus | 3,873 | 2,455 | |||||||||||||||||||||||
Stock-based compensation | 3,703 | 4,256 | |||||||||||||||||||||||
Other | 643 | 1,330 | |||||||||||||||||||||||
Total deferred tax assets | 123,985 | 46,439 | |||||||||||||||||||||||
Net deferred tax liabilities | $ | 177,559 | $ | 144,982 | |||||||||||||||||||||
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, 2013 (in thousands): | |||||||||||||||||||||||||
Amount | Expiration Year | ||||||||||||||||||||||||
Federal net operating loss | $ | 263,388 | 2033 | ||||||||||||||||||||||
State net operating losses | 95,912 | 2017-2028 | |||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Balance at beginning of period | $ | — | $ | — | |||||||||||||||||||||
Increases related to carryback positions | 9,482 | — | |||||||||||||||||||||||
Balance at end of period | $ | 9,482 | $ | — | |||||||||||||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Net income | $ | 51,322 | $ | 71,984 | $ | 172,817 | |||||||
Less portion allocated to nonvested shares | 303 | 983 | 3,211 | ||||||||||
Net income allocated to common shares | $ | 51,019 | $ | 71,001 | $ | 169,606 | |||||||
75,239 | 74,354 | 74,033 | |||||||||||
Weighted average common shares outstanding | |||||||||||||
$ | 0.68 | $ | 0.95 | $ | 2.29 | ||||||||
Basic and diluted earnings per common share | |||||||||||||
— | 1,923 | 1,873 | |||||||||||
Shares excluded due to being anti-dilutive | |||||||||||||
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Supplemental Cash Flow Information | ' | ||||||||||||
The following reflects our supplemental cash flow information (in thousands): | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Cash paid for interest, net of interest capitalized of $10,058 in 2013, $13,274 in 2012 and $9,877 in 2011 | $ | 73,909 | $ | 46,247 | $ | 39,772 | |||||||
Cash paid for income taxes | 3,000 | 16,056 | 35,655 | ||||||||||
Cash refunds received for income taxes | 59,126 | 479 | 379 | ||||||||||
Cash paid for share-based compensation (1) | 466 | 1,531 | 1,062 | ||||||||||
Cash tax benefit related to share-based compensation (2) | — | 5,962 | 3,125 | ||||||||||
-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 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, 2013 | |||||||||||||||||
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, 2013 (1) | |||||||||||||||||
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 (2) | 0.35 | 0.29 | 0.19 | (0.16 | ) | ||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Revenues | $ | 235,886 | $ | 215,513 | $ | 185,946 | $ | 237,146 | |||||||||
Operating income | 15,913 | 99,100 | 7,560 | 46,737 | |||||||||||||
Net income | 3,218 | 53,567 | (1,471 | ) | 16,670 | ||||||||||||
Basic and diluted earnings (loss) per common share (2) | 0.04 | 0.7 | (0.02 | ) | 0.21 | ||||||||||||
-1 | 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. | |||||||||||||||||
-2 | 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. |
Supplemental_Guarantor_Informa1
Supplemental Guarantor Information (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Condensed Consolidating Balance Sheet | ' | ||||||||||||||||
The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. (the “Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. | |||||||||||||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Current assets: | |||||||||||||||||
Cash and cash equivalents | $ | 15,800 | $ | — | $ | — | $ | 15,800 | |||||||||
Receivables: | |||||||||||||||||
Oil and natural gas sales | 75,486 | 21,266 | — | 96,752 | |||||||||||||
Joint interest and other | 27,984 | — | — | 27,984 | |||||||||||||
Income taxes | 124,393 | — | (121,273 | ) | 3,120 | ||||||||||||
Total receivables | 227,863 | 21,266 | (121,273 | ) | 127,856 | ||||||||||||
Prepaid expenses and other assets | 23,674 | 6,272 | — | 29,946 | |||||||||||||
Total current assets | 267,337 | 27,538 | (121,273 | ) | 173,602 | ||||||||||||
Property and equipment—at cost: | |||||||||||||||||
Oil and natural gas properties and equipment | 6,770,396 | 568,701 | — | 7,339,097 | |||||||||||||
Furniture, fixtures and other | 21,431 | — | — | 21,431 | |||||||||||||
Total property and equipment | 6,791,827 | 568,701 | — | 7,360,528 | |||||||||||||
Less accumulated depreciation, depletion and amortization | 4,784,932 | 299,772 | — | 5,084,704 | |||||||||||||
Net property and equipment | 2,006,895 | 268,929 | — | 2,275,824 | |||||||||||||
Restricted deposits for asset retirement obligations | 37,421 | — | — | 37,421 | |||||||||||||
Other assets | 574,280 | 427,619 | (981,444 | ) | 20,455 | ||||||||||||
Total assets | $ | 2,885,933 | $ | 724,086 | $ | (1,102,717 | ) | $ | 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 | 75,977 | 1,808 | — | 77,785 | |||||||||||||
Accrued liabilities | 28,000 | 121,273 | (121,273 | ) | 28,000 | ||||||||||||
Total current liabilities | 290,204 | 124,173 | (121,273 | ) | 293,104 | ||||||||||||
Long-term debt, less current maturities | 1,205,421 | — | — | 1,205,421 | |||||||||||||
Asset retirement obligations, less current portion | 238,270 | 38,367 | — | 276,637 | |||||||||||||
Deferred income taxes | 170,419 | 7,723 | — | 178,142 | |||||||||||||
Other liabilities | 441,009 | — | (427,621 | ) | 13,388 | ||||||||||||
Commitments and contingencies | |||||||||||||||||
Shareholders’ equity: | |||||||||||||||||
Common stock | 1 | — | — | 1 | |||||||||||||
Additional paid-in capital | 403,564 | 317,776 | (317,776 | ) | 403,564 | ||||||||||||
Retained earnings | 161,212 | 236,047 | (236,047 | ) | 161,212 | ||||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | |||||||||||
Total shareholders’ equity | 540,610 | 553,823 | (553,823 | ) | 540,610 | ||||||||||||
Total liabilities and shareholders’ equity | $ | 2,885,933 | $ | 724,086 | $ | (1,102,717 | ) | $ | 2,507,302 | ||||||||
Condensed Consolidating Balance Sheet as of December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Current assets: | |||||||||||||||||
Cash and cash equivalents | $ | 12,245 | $ | — | $ | — | $ | 12,245 | |||||||||
Receivables: | |||||||||||||||||
Oil and natural gas sales | 80,729 | 17,004 | — | 97,733 | |||||||||||||
Joint interest and other | 56,439 | — | — | 56,439 | |||||||||||||
Income taxes | 163,750 | — | (115,866 | ) | 47,884 | ||||||||||||
Total receivables | 300,918 | 17,004 | (115,866 | ) | 202,056 | ||||||||||||
Prepaid expenses and other assets | 25,822 | — | — | 25,822 | |||||||||||||
Total current assets | 338,985 | 17,004 | (115,866 | ) | 240,123 | ||||||||||||
Property and equipment—at cost: | |||||||||||||||||
Oil and natural gas properties and equipment | 6,356,529 | 337,981 | — | 6,694,510 | |||||||||||||
Furniture, fixtures and other | 21,786 | — | — | 21,786 | |||||||||||||
Total property and equipment | 6,378,315 | 337,981 | — | 6,716,296 | |||||||||||||
Less accumulated depreciation, depletion and amortization | 4,461,886 | 193,955 | — | 4,655,841 | |||||||||||||
Net property and equipment | 1,916,429 | 144,026 | — | 2,060,455 | |||||||||||||
Restricted deposits for asset retirement obligations | 28,466 | — | — | 28,466 | |||||||||||||
Other assets | 442,540 | 407,008 | (829,605 | ) | 19,943 | ||||||||||||
Total assets | $ | 2,726,420 | $ | 568,038 | $ | (945,471 | ) | $ | 2,348,987 | ||||||||
Liabilities and Shareholders’ Equity | |||||||||||||||||
Current liabilities: | |||||||||||||||||
Accounts payable | $ | 123,792 | $ | 93 | $ | — | $ | 123,885 | |||||||||
Undistributed oil and natural gas proceeds | 36,791 | 282 | — | 37,073 | |||||||||||||
Asset retirement obligations | 92,595 | — | 35 | 92,630 | |||||||||||||
Accrued liabilities | 20,755 | 116,132 | (115,866 | ) | 21,021 | ||||||||||||
Total current liabilities | 273,933 | 116,507 | (115,831 | ) | 274,609 | ||||||||||||
Long-term debt | 1,087,611 | — | — | 1,087,611 | |||||||||||||
Asset retirement obligations, less current portion | 262,524 | 28,934 | (35 | ) | 291,423 | ||||||||||||
Deferred income taxes | 158,758 | — | (13,509 | ) | 145,249 | ||||||||||||
Other liabilities | 402,407 | — | (393,499 | ) | 8,908 | ||||||||||||
Commitments and contingencies | |||||||||||||||||
Shareholders’ equity: | |||||||||||||||||
Common stock | 1 | — | — | 1 | |||||||||||||
Additional paid-in capital | 396,186 | 231,759 | (231,759 | ) | 396,186 | ||||||||||||
Retained earnings | 169,167 | 190,838 | (190,838 | ) | 169,167 | ||||||||||||
Treasury stock, at cost | (24,167 | ) | — | — | (24,167 | ) | |||||||||||
Total shareholders’ equity | 541,187 | 422,597 | (422,597 | ) | 541,187 | ||||||||||||
Total liabilities and shareholders’ equity | $ | 2,726,420 | $ | 568,038 | $ | (945,471 | ) | $ | 2,348,987 | ||||||||
Condensed Consolidating Statement of Income | ' | ||||||||||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 780,442 | $ | 203,646 | $ | — | $ | 984,088 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 252,511 | 18,328 | — | 270,839 | |||||||||||||
Production taxes | 7,135 | — | — | 7,135 | |||||||||||||
Gathering and transportation | 13,747 | 3,763 | — | 17,510 | |||||||||||||
Depreciation, depletion and amortization | 324,794 | 105,817 | — | 430,611 | |||||||||||||
Asset retirement obligation accretion | 18,152 | 2,766 | — | 20,918 | |||||||||||||
General and administrative expenses | 78,649 | 3,225 | — | 81,874 | |||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | |||||||||||||
Total costs and expenses | 703,458 | 133,899 | — | 837,357 | |||||||||||||
Operating income | 76,984 | 69,747 | — | 146,731 | |||||||||||||
Earnings of affiliates | 45,209 | — | (45,209 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 85,531 | 108 | — | 85,639 | |||||||||||||
Capitalized | (9,950 | ) | (108 | ) | — | (10,058 | ) | ||||||||||
Loss on extinguishment of debt | 128 | — | — | 128 | |||||||||||||
Other income | 9,074 | — | — | 9,074 | |||||||||||||
Income before income tax expense | 55,558 | 69,747 | (45,209 | ) | 80,096 | ||||||||||||
Income tax expense | 4,236 | 24,538 | — | 28,774 | |||||||||||||
Net income | $ | 51,322 | $ | 45,209 | $ | (45,209 | ) | $ | 51,322 | ||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 659,203 | $ | 215,288 | $ | — | $ | 874,491 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 209,581 | 22,679 | — | 232,260 | |||||||||||||
Production taxes | 5,840 | — | — | 5,840 | |||||||||||||
Gathering and transportation | 11,703 | 3,175 | — | 14,878 | |||||||||||||
Depreciation, depletion and amortization | 253,807 | 82,370 | — | 336,177 | |||||||||||||
Asset retirement obligation accretion | 17,463 | 2,592 | — | 20,055 | |||||||||||||
General and administrative expenses | 79,424 | 2,593 | — | 82,017 | |||||||||||||
Derivative loss | 13,954 | — | — | 13,954 | |||||||||||||
Total costs and expenses | 591,772 | 113,409 | — | 705,181 | |||||||||||||
Operating income | 67,431 | 101,879 | — | 169,310 | |||||||||||||
Earnings of affiliates | 66,195 | — | (66,195 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 63,268 | — | — | 63,268 | |||||||||||||
Capitalized | (13,274 | ) | — | — | (13,274 | ) | |||||||||||
Other income | 215 | — | — | 215 | |||||||||||||
Income before income tax expense | 83,847 | 101,879 | (66,195 | ) | 119,531 | ||||||||||||
Income tax expense | 11,863 | 35,684 | — | 47,547 | |||||||||||||
Net income | $ | 71,984 | $ | 66,195 | $ | (66,195 | ) | $ | 71,984 | ||||||||
Condensed Consolidating Statement of Income for the Twelve Months Ended December 31, 2011 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Revenues | $ | 697,899 | $ | 273,148 | $ | — | $ | 971,047 | |||||||||
Operating costs and expenses: | |||||||||||||||||
Lease operating expenses | 182,165 | 37,041 | — | 219,206 | |||||||||||||
Production taxes | 4,275 | — | — | 4,275 | |||||||||||||
Gathering and transportation | 12,676 | 4,244 | — | 16,920 | |||||||||||||
Depreciation, depletion and amortization | 214,740 | 84,275 | — | 299,015 | |||||||||||||
Asset retirement obligation accretion | 26,947 | 2,824 | — | 29,771 | |||||||||||||
General and administrative expenses | 71,714 | 2,582 | — | 74,296 | |||||||||||||
Derivative gain | (1,896 | ) | — | — | (1,896 | ) | |||||||||||
Total costs and expenses | 510,621 | 130,966 | — | 641,587 | |||||||||||||
Operating income | 187,278 | 142,182 | — | 329,460 | |||||||||||||
Earnings of affiliates | 92,533 | — | (92,533 | ) | — | ||||||||||||
Interest expense: | |||||||||||||||||
Incurred | 52,393 | — | — | 52,393 | |||||||||||||
Capitalized | (9,877 | ) | — | — | (9,877 | ) | |||||||||||
Loss on extinguishment of debt | 22,694 | — | — | 22,694 | |||||||||||||
Other income | 84 | — | — | 84 | |||||||||||||
Income before income tax expense | 214,685 | 142,182 | (92,533 | ) | 264,334 | ||||||||||||
Income tax expense | 41,868 | 49,649 | — | 91,517 | |||||||||||||
Net income | $ | 172,817 | $ | 92,533 | $ | (92,533 | ) | $ | 172,817 | ||||||||
Condensed Consolidating Statement of Cash Flows | ' | ||||||||||||||||
Condensed Consolidating Statement of Cash Flows for the Twelve Months Ended December 31, 2013 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 51,322 | $ | 45,209 | $ | (45,209 | ) | $ | 51,322 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 342,946 | 108,583 | — | 451,529 | |||||||||||||
Amortization of debt issuance costs and premium | 1,645 | — | — | 1,645 | |||||||||||||
Loss on extinguishment of debt | 128 | — | — | 128 | |||||||||||||
Share-based compensation | 11,525 | — | — | 11,525 | |||||||||||||
Derivative loss | 8,470 | — | — | 8,470 | |||||||||||||
Cash payments on derivative settlements (realized) | (8,589 | ) | — | — | (8,589 | ) | |||||||||||
Deferred income taxes | 11,522 | 19,398 | — | 30,920 | |||||||||||||
Earnings of affiliates | (45,209 | ) | — | 45,209 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | 5,242 | (4,262 | ) | — | 980 | ||||||||||||
Joint interest and other receivables | 28,566 | — | — | 28,566 | |||||||||||||
Insurance proceeds | 5,691 | — | — | 5,691 | |||||||||||||
Income taxes | 39,188 | 5,140 | — | 44,328 | |||||||||||||
Prepaid expenses and other assets | (5,606 | ) | (38,558 | ) | 34,120 | (10,044 | ) | ||||||||||
Asset retirement obligations | (79,950 | ) | (1,593 | ) | — | (81,543 | ) | ||||||||||
Accounts payable and accrued liabilities | 27,415 | 717 | — | 28,132 | |||||||||||||
Other | 32,418 | — | (34,120 | ) | (1,702 | ) | |||||||||||
Net cash provided by operating activities | 426,724 | 134,634 | — | 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 | (331,303 | ) | (220,651 | ) | — | (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, misc. sales and other | (1,435 | ) | — | — | (1,435 | ) | |||||||||||
Net cash used in investing activities | (480,171 | ) | (220,651 | ) | 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 provided by 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 Twelve Months Ended December 31, 2012 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 71,984 | $ | 66,195 | $ | (66,195 | ) | $ | 71,984 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 271,270 | 84,962 | — | 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 (realized) | (7,664 | ) | — | — | (7,664 | ) | |||||||||||
Deferred income taxes | 83,981 | 4,128 | — | 88,109 | |||||||||||||
Earnings of affiliates | (66,195 | ) | — | 66,195 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | (2,597 | ) | 3,415 | — | 818 | ||||||||||||
Joint interest and other receivables | (31,399 | ) | — | — | (31,399 | ) | |||||||||||
Insurance proceeds | 2,576 | — | — | 2,576 | |||||||||||||
Income taxes | (89,568 | ) | 31,557 | — | (58,011 | ) | |||||||||||
Prepaid expenses and other assets | 7,442 | (118,320 | ) | 118,318 | 7,440 | ||||||||||||
Asset retirement obligations | (112,199 | ) | (628 | ) | — | (112,827 | ) | ||||||||||
Accounts payable and accrued liabilities | 40,530 | (2,504 | ) | — | 38,026 | ||||||||||||
Other | 119,244 | — | (118,318 | ) | 926 | ||||||||||||
Net cash provided by operating activities | 316,332 | 68,805 | — | 385,137 | |||||||||||||
Investing activities: | |||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (205,550 | ) | — | — | (205,550 | ) | |||||||||||
Investment in oil and natural gas properties and equipment | (410,508 | ) | (68,805 | ) | — | (479,313 | ) | ||||||||||
Proceeds from sales of assets and other, net | 30,453 | — | — | 30,453 | |||||||||||||
Purchases of furniture, fixtures, misc. sales and other | (3,031 | ) | — | — | (3,031 | ) | |||||||||||
Net cash used in investing activities | (588,636 | ) | (68,805 | ) | — | (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 | ) | |||||||||||
Other | 379 | — | — | 379 | |||||||||||||
Net cash provided by financing activities | 280,037 | — | — | 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 | |||||||||
Condensed Consolidating Statement of Cash Flows for the Twelve Months Ended December 31, 2011 | |||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | ||||||||||||||
Company | Subsidiaries | W&T | |||||||||||||||
Offshore, Inc. | |||||||||||||||||
(In thousands) | |||||||||||||||||
Operating activities: | |||||||||||||||||
Net income | $ | 172,817 | $ | 92,533 | $ | (92,533 | ) | $ | 172,817 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, depletion, amortization and accretion | 241,687 | 87,099 | — | 328,786 | |||||||||||||
Amortization of debt issuance costs | 2,010 | — | — | 2,010 | |||||||||||||
Loss on extinguishment of debt | 22,694 | — | — | 22,694 | |||||||||||||
Share-based compensation | 9,710 | — | — | 9,710 | |||||||||||||
Derivative gain | (1,896 | ) | — | — | (1,896 | ) | |||||||||||
Cash payments on derivative settlements (realized) | (9,873 | ) | — | — | (9,873 | ) | |||||||||||
Deferred income taxes | 76,717 | (14,882 | ) | — | 61,835 | ||||||||||||
Earnings of affiliates | (92,533 | ) | — | 92,533 | — | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Oil and natural gas receivables | (27,709 | ) | 9,070 | — | (18,639 | ) | |||||||||||
Joint interest and other receivables | 375 | — | — | 375 | |||||||||||||
Insurance proceeds | 20,771 | — | — | 20,771 | |||||||||||||
Income taxes | (71,655 | ) | 64,531 | — | (7,124 | ) | |||||||||||
Prepaid expenses and other assets | (8,003 | ) | (228,020 | ) | 228,214 | (7,809 | ) | ||||||||||
Asset retirement obligations | (59,958 | ) | — | — | (59,958 | ) | |||||||||||
Accounts payable and accrued liabilities | 8,589 | (514 | ) | (194 | ) | 7,881 | |||||||||||
Other | 227,918 | — | (228,020 | ) | (102 | ) | |||||||||||
Net cash provided by operating activities | 511,661 | 9,817 | — | 521,478 | |||||||||||||
Investing activities: | |||||||||||||||||
Acquisition of property interest in oil and natural gas properties | (437,247 | ) | — | — | (437,247 | ) | |||||||||||
Investment in oil and natural gas properties and equipment | (277,147 | ) | (4,632 | ) | — | (281,779 | ) | ||||||||||
Investment in subsidiary | 5,185 | — | (5,185 | ) | — | ||||||||||||
Proceeds from sales of assets and other, net | 15 | — | — | 15 | |||||||||||||
Purchases of furniture, fixtures, misc. sales and other | (3,660 | ) | — | — | (3,660 | ) | |||||||||||
Net cash used in investing activities | (712,854 | ) | (4,632 | ) | (5,185 | ) | (722,671 | ) | |||||||||
Financing activities: | |||||||||||||||||
Issuance of 8.50% Senior Notes | 600,000 | — | — | 600,000 | |||||||||||||
Repurchase of 8.25% Senior Notes | (450,000 | ) | — | — | (450,000 | ) | |||||||||||
Borrowings of long-term debt - revolving bank credit facility | 623,000 | — | — | 623,000 | |||||||||||||
Repayments of long-term debt - revolving bank credit facility | (506,000 | ) | — | — | (506,000 | ) | |||||||||||
Repurchase premium and debt issuance costs | (32,288 | ) | — | — | (32,288 | ) | |||||||||||
Dividends to shareholders | (58,756 | ) | — | — | (58,756 | ) | |||||||||||
Investment from parent | — | (5,185 | ) | 5,185 | — | ||||||||||||
Other | 1,094 | — | — | 1,094 | |||||||||||||
Net cash provided by (used in) financing activities | 177,050 | (5,185 | ) | 5,185 | 177,050 | ||||||||||||
Decrease in cash and cash equivalents | (24,143 | ) | — | — | (24,143 | ) | |||||||||||
Cash and cash equivalents, beginning of period | 28,655 | — | — | 28,655 | |||||||||||||
Cash and cash equivalents, end of period | $ | 4,512 | $ | — | $ | — | $ | 4,512 | |||||||||
Supplemental_Oil_and_Gas_Discl1
Supplemental Oil and Gas Disclosures-unaudited (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Net capitalized cost: | |||||||||||||||||||||
Proved oil and natural gas properties and equipment | $ | 7,207.10 | $ | 6,551.50 | $ | 5,775.40 | |||||||||||||||
Unproved oil and natural gas properties and equipment | 132 | 143 | 183.6 | ||||||||||||||||||
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | (5,069.2 | ) | (4,640.8 | ) | (4,307.1 | ) | |||||||||||||||
Net capitalized costs related to producing activities | $ | 2,269.90 | $ | 2,053.70 | $ | 1,651.90 | |||||||||||||||
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, 2013, by the year in which the costs were incurred (in millions): | |||||||||||||||||||||
Total | 2013 | 2012 | 2011 | Prior to | |||||||||||||||||
2011 | |||||||||||||||||||||
Costs excluded by year incurred: | |||||||||||||||||||||
Acquisition costs | $ | 87.3 | $ | 9.2 | $ | 8.7 | $ | 50.1 | $ | 19.3 | |||||||||||
Capitalized interest not subject to amortization | 29.3 | 8.4 | 7.4 | 5.1 | 8.4 | ||||||||||||||||
Total costs not subject to amortization | $ | 116.6 | $ | 17.6 | $ | 16.1 | $ | 55.2 | $ | 27.7 | |||||||||||
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): | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Costs incurred (1): | |||||||||||||||||||||
Proved property acquisitions | $ | 96.9 | $ | 239.8 | $ | 369.9 | |||||||||||||||
Exploration (2) (3) | 215.3 | 151.3 | 92.7 | ||||||||||||||||||
Development | 352.9 | 363.7 | 203.7 | ||||||||||||||||||
Unproved property acquisitions (4) | 26.3 | 26.5 | 95.1 | ||||||||||||||||||
Total costs incurred in oil and gas property acquisition, exploration and development activities | $ | 691.4 | $ | 781.3 | $ | 761.4 | |||||||||||||||
-1 | Includes net additions to our ARO of $50.6 million, $86.9 million and $32.8 million during 2013, 2012 and 2011, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5. | ||||||||||||||||||||
-2 | Includes seismic costs of $8.9 million, $6.2 million and $8.0 million incurred during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||
-3 | Includes geological and geophysical costs charged to expense of $5.9 million, $6.2 million and $6.8 million during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||
-4 | The amounts for unproved property acquisitions include capitalized interest associated with properties classified as unproved as of the end of the period. | ||||||||||||||||||||
Schedule of Depreciation, Depletion, Amortization and Accretion Expense | ' | ||||||||||||||||||||
The following table presents our depreciation, depletion, amortization and accretion expense per thousand cubic feet equivalent (“Mcfe”) of products sold. | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Depreciation, depletion, amortization and accretion per Mcfe | $ | 4.18 | $ | 3.47 | $ | 3.24 | |||||||||||||||
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 and the majority of the reserves are located in the Gulf of Mexico. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. Estimated reserves for the periods presented are 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. | |||||||||||||||||||||
Total Equivalent Reserves | |||||||||||||||||||||
Oil | NGLs | Natural Gas | Oil | Natural Gas | |||||||||||||||||
(MMBbls) | (MMBbls) | (Bcf) | Equivalent | Equivalent | |||||||||||||||||
(MMBoe) (1) | (Bcfe) (1) | ||||||||||||||||||||
Proved reserves as of December 31, 2010 | 34 | 4.2 | 256.3 | 80.9 | 485.4 | ||||||||||||||||
Revisions of previous estimates (2) | 0.8 | 5.5 | 13.5 | 8.6 | 51.1 | ||||||||||||||||
Extensions and discoveries (3) | 2 | 0.4 | 17.7 | 5.3 | 32 | ||||||||||||||||
Purchase of minerals in place (4) | 20.7 | 8.9 | 55.9 | 39 | 234.1 | ||||||||||||||||
Production | (6.1 | ) | (1.9 | ) | (53.7 | ) | (16.9 | ) | (101.5 | ) | |||||||||||
Proved reserves as of December 31, 2011 | 51.4 | 17.1 | 289.7 | 116.9 | 701.1 | ||||||||||||||||
Revisions of previous estimates (5) | (1.1 | ) | (2.6 | ) | (4.8 | ) | (4.6 | ) | (27.5 | ) | |||||||||||
Extensions and discoveries (6) | 8.2 | 2.6 | 29.6 | 15.7 | 94.5 | ||||||||||||||||
Purchase of minerals in place (7) | 2.5 | 0.2 | 25.5 | 7 | 42 | ||||||||||||||||
Sales of reserves (8) | (0.2 | ) | — | (1.1 | ) | (0.4 | ) | (2.2 | ) | ||||||||||||
Production | (6.0 | ) | (2.1 | ) | (53.8 | ) | (17.1 | ) | (102.8 | ) | |||||||||||
Proved reserves as of December 31, 2012 | 54.8 | 15.2 | 285.1 | 117.5 | 705.1 | ||||||||||||||||
Revisions of previous estimates (9) | (4.3 | ) | 0.2 | 2.1 | (3.8 | ) | (22.8 | ) | |||||||||||||
Extensions and discoveries (10) | 13.9 | 2.6 | 22 | 20.2 | 121 | ||||||||||||||||
Purchase of minerals in place (11) | 1.5 | — | 4.4 | 2.3 | 13.7 | ||||||||||||||||
Sales of reserves (12) | (0.4 | ) | — | (0.4 | ) | (0.5 | ) | (3.2 | ) | ||||||||||||
Production | (7.0 | ) | (2.1 | ) | (53.3 | ) | (18.0 | ) | (107.9 | ) | |||||||||||
Proved reserves as of December 31, 2013 | 58.5 | 15.9 | 259.9 | 117.7 | 705.9 | ||||||||||||||||
Year-end proved developed reserves: | |||||||||||||||||||||
2013 | 36.2 | 11.1 | 232.7 | 86.1 | 516.1 | ||||||||||||||||
2012 | 35.3 | 11 | 243.5 | 86.9 | 521.2 | ||||||||||||||||
2011 | 23.4 | 11 | 251.4 | 76.4 | 458.2 | ||||||||||||||||
Year-end proved undeveloped reserves: | |||||||||||||||||||||
2013 | 22.3 | 4.8 | 27.2 | 31.6 | 189.8 | ||||||||||||||||
2012 | 19.5 | 4.2 | 41.6 | 30.6 | 183.9 | ||||||||||||||||
2011 | 28 | 6.1 | 38.3 | 40.5 | 242.9 | ||||||||||||||||
-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 revision of 6.3 Bcfe due to an increase in average prices; 16.5 Bcfe for a change in NGLs marketing arrangements; 11.3 Bcfe increase due to additional compression at our Tahoe field that increases production and ultimate recoveries; and 10.6 Bcfe at our Fairway field for revisions to reserve estimates from the acquisition date to year end. | ||||||||||||||||||||
-3 | Includes discoveries of 13.9 Bcfe at our Main Pass 98 field and 8.0 Bcfe at our Ship Shoal 349/359 field and extensions of 3.7 Bcfe at our Main Pass 108 field. | ||||||||||||||||||||
-4 | Primarily due to the acquisition of the Opal Properties and the Fairway Properties. | ||||||||||||||||||||
-5 | Includes downward revisions due to price of 8.0 Bcfe and negative performance revisions of 17.9 Bcfe at our Spraberry field. | ||||||||||||||||||||
-6 | Includes extensions and discoveries of 69.5 Bcfe at our Spraberry field and extensions and discoveries of 16.2 Bcfe at our High Island 21/22 field. | ||||||||||||||||||||
-7 | Due to the acquisition of the Newfield Properties. | ||||||||||||||||||||
-8 | Due to the sale of our interest in the South Timbalier 41 field. | ||||||||||||||||||||
-9 | Includes upward revision due to price of 11.3 Bcfe; negative revisions of 29.6 Bcfe at our Spraberry field for performance and technical changes, 13.9 Bcfe at our High Island 21/22 field for performance, 7.9 Bcfe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 4.3 Bcfe at our Main Pass 98 field, 4.0 Bcfe at our South Timbalier 314, 3.5 Bcfe at our Main Pass 108 field and 3.2 at our South Timbalier 176 field. | ||||||||||||||||||||
-10 | Includes extensions and discoveries of 75.4 Bcfe at our Spraberry field, 25.3 Bcfe at our Ship Shoal 349/359 field and 11.5 Bcfe at our Mississippi Canyon 698 field. | ||||||||||||||||||||
-11 | Primarily due to the acquisition of the Callon Properties. | ||||||||||||||||||||
-12 | 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. | ||||||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | 2010 | ||||||||||||||||||
Oil – per barrel | $ | 99.65 | $ | 98.13 | $ | 97.36 | $ | 76.28 | |||||||||||||
NGLs – per barrel | 35.21 | 47.3 | 51.3 | 44.92 | |||||||||||||||||
Natural gas – per Mcf | 3.8 | 2.77 | 4.11 | 4.57 | |||||||||||||||||
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, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | |||||||||||||||||||||
Future cash inflows | $ | 7,376.70 | $ | 6,888.40 | $ | 7,077.20 | |||||||||||||||
Future costs: | |||||||||||||||||||||
Production | (2,142.8 | ) | (1,858.3 | ) | (1,862.5 | ) | |||||||||||||||
Development | (1,001.4 | ) | (655.4 | ) | (543.0 | ) | |||||||||||||||
Dismantlement and abandonment | (441.6 | ) | (508.0 | ) | (513.6 | ) | |||||||||||||||
Income taxes | (986.9 | ) | (1,002.1 | ) | (1,126.6 | ) | |||||||||||||||
Future net cash inflows before 10% discount | 2,804.00 | 2,864.60 | 3,031.50 | ||||||||||||||||||
10% annual discount factor | (1,129.4 | ) | (1,018.2 | ) | (1,025.1 | ) | |||||||||||||||
Total | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | |||||||||||||||
Schedule of Changes In Standardized Measure | ' | ||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Changes in Standardized Measure | |||||||||||||||||||||
Standardized measure, beginning of year | $ | 1,846.40 | $ | 2,006.40 | $ | 1,179.10 | |||||||||||||||
Increases (decreases): | |||||||||||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (686.1 | ) | (620.4 | ) | (729.6 | ) | |||||||||||||||
Net changes in price, net of future production costs | (65.2 | ) | (224.3 | ) | 634.2 | ||||||||||||||||
Extensions and discoveries, net of future production and development costs | 393.8 | 181.9 | 219.9 | ||||||||||||||||||
Changes in estimated future development costs | (91.1 | ) | (103.3 | ) | (4.6 | ) | |||||||||||||||
Previously estimated development costs incurred | 262.1 | 332.9 | 173.9 | ||||||||||||||||||
Revisions of quantity estimates | (91.6 | ) | (128.1 | ) | 205 | ||||||||||||||||
Accretion of discount | 202.2 | 231.1 | 135.8 | ||||||||||||||||||
Net change in income taxes | 56.6 | 99.7 | (398.2 | ) | |||||||||||||||||
Purchases of reserves in-place | 79.6 | 270.2 | 483.3 | ||||||||||||||||||
Sales of reserves in-place | (53.1 | ) | (16.1 | ) | — | ||||||||||||||||
Changes in production rates due to timing and other | (179.0 | ) | (183.6 | ) | 107.6 | ||||||||||||||||
Net increase (decrease) in standardized measure | (171.8 | ) | (160.0 | ) | 827.3 | ||||||||||||||||
Standardized measure, end of year | $ | 1,674.60 | $ | 1,846.40 | $ | 2,006.40 | |||||||||||||||
Percentage_of_Revenue_by_Major
Percentage of Revenue by Major Customers (Detail) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | 10.00% | ' | ' | |||
Shell Trading (US) Co. | ' | ' | ' | |||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | 48.00% | 35.00% | 36.00% | |||
ConocoPhillips | ' | ' | ' | |||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | ' | [1],[2] | 16.00% | [1] | 16.00% | [1] |
J.P. Morgan Ventures Energy Corp. | ' | ' | ' | |||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | ' | [2] | ' | [2] | 10.00% | |
[1] | ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. | |||||
[2] | less than 10% |
Percentage_of_Revenue_by_Major1
Percentage of Revenue by Major Customers (Parenthetical) (Detail) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | 10.00% | ' | ' | |||
ConocoPhillips | ' | ' | ' | |||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | ' | [1],[2] | 16.00% | [1] | 16.00% | [1] |
ConocoPhillips | Companies Separated Into Two | ' | ' | ' | |||
Entity Wide Revenue Major Customer [Line Items] | ' | ' | ' | |||
Percentage of receipts | ' | 8.00% | ' | |||
Number of companies separated | ' | 2 | ' | |||
[1] | ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each. | |||||
[2] | less than 10% |
Significant_Accounting_Policie3
Significant Accounting Policies - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
MMcf | MMcf | |||
Significant Accounting Policies [Line Items] | ' | ' | ' | ' |
Increase in production | 2,600 | 1,900 | ' | ' |
Natural gas imbalances | $6.40 | $6.40 | $6 | ' |
Percentage of discount from proved reserves | ' | 10.00% | ' | ' |
Ceiling test impairment | ' | 0 | 0 | 0 |
Payments received related to break-up fee and termination of certain purchase and sale agreement | ' | 9.2 | ' | ' |
Third-party expenses related to the cancelled transaction | ' | 0.1 | ' | ' |
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 | 7.1 | 5 | ' | ' |
Reduction in net income | $4.60 | $3.20 | ' | ' |
Purchase_Price_Allocation_for_
Purchase Price Allocation for Acquisition of Properties (Detail) (USD $) | Oct. 17, 2013 | Oct. 17, 2013 | Oct. 17, 2013 | Oct. 05, 2012 | Oct. 05, 2012 | Oct. 05, 2012 | 11-May-11 | 11-May-11 | 11-May-11 | Aug. 10, 2011 | Aug. 10, 2011 |
In Thousands, unless otherwise specified | Callon Properties | Callon Properties | Callon Properties | Newfield Properties | Newfield Properties | Newfield Properties | Opal Properties | Opal Properties | Opal Properties | Fairway Properties | Fairway Properties |
Evaluated properties including equipment | Unevaluated properties | Evaluated properties including equipment | Unevaluated properties | Evaluated properties including equipment | Unevaluated properties | Evaluated properties including equipment | |||||
Cash consideration: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Oil and natural gas properties and equipment | $82,424 | $73,176 | $9,248 | $205,788 | $192,723 | $13,065 | $394,377 | $313,165 | $81,212 | ' | $42,870 |
Non-cash consideration: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset retirement obligation - current | 90 | ' | ' | 7,250 | ' | ' | ' | ' | ' | ' | ' |
Asset retirement obligation - non-current | 4,143 | ' | ' | 24,414 | ' | ' | 382 | ' | ' | 7,812 | ' |
Sub-total – non-cash consideration | 4,233 | ' | ' | 31,664 | ' | ' | 2,525 | ' | ' | ' | ' |
Long-term liability | ' | ' | ' | ' | ' | ' | 2,143 | ' | ' | ' | ' |
Total consideration | $86,657 | ' | ' | $237,452 | ' | ' | $396,902 | ' | ' | $50,682 | ' |
Summary_of_Proforma_Financial_
Summary of Proforma Financial Information for Acquisition (Detail) (USD $) | 12 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 |
Callon Properties | Callon Properties | Newfield Properties | Newfield Properties | Opal Properties And Fairway Properties | |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' |
Revenue | $1,018,118 | $923,050 | $980,196 | $1,187,808 | $1,023,430 |
Net income | $59,073 | $85,378 | $77,036 | $220,835 | $180,779 |
Basic and diluted earnings per common share | $0.78 | $1.12 | $1.01 | $2.92 | $2.39 |
Business_Acquisition_Pro_Forma
Business Acquisition Pro Forma Information Incremental Items (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | $244,928 | [1] | $244,555 | [1] | $235,383 | [1] | $259,222 | [1] | $237,146 | $185,946 | $215,513 | $235,886 | $984,088 | $874,491 | $971,047 | |||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 270,839 | 232,260 | 219,206 | |||||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | 451,529 | 356,232 | 328,786 | |||||||
G&A | ' | ' | ' | ' | ' | ' | ' | ' | 81,874 | 82,017 | 74,296 | |||||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 85,639 | 63,268 | 52,393 | |||||||
Capitalized interest | ' | ' | ' | ' | ' | ' | ' | ' | 10,058 | 13,274 | 9,877 | |||||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 28,774 | 47,547 | 91,517 | |||||||
Callon Properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | 5,800 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Lease operating expenses | 1,300 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Depreciation, depletion, amortization and accretion | 2,400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Income tax expense | 700 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Callon Properties | Pro Forma | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 34,030 | [2] | 48,559 | [2] | ' | |||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 6,405 | [2] | 8,525 | [2] | ' | |||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | 14,856 | [3] | 17,492 | [3] | ' | |||||
G&A | ' | ' | ' | ' | ' | ' | ' | ' | -361 | [4] | ' | ' | ||||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 1,374 | [5] | 1,648 | [5] | ' | |||||
Capitalized interest | ' | ' | ' | ' | ' | ' | ' | ' | -168 | [6] | 288 | [6] | ' | |||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 4,173 | [7] | 7,212 | [7] | ' | |||||
Newfield Properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | ' | ' | ' | ' | 29,600 | ' | ' | ' | ' | ' | ' | |||||||
Lease operating expenses | ' | ' | ' | ' | 5,400 | ' | ' | ' | ' | ' | ' | |||||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | 11,900 | ' | ' | ' | ' | ' | ' | |||||||
Income tax expense | ' | ' | ' | ' | 4,300 | ' | ' | ' | ' | ' | ' | |||||||
Newfield Properties | Pro Forma | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,705 | [8] | 216,761 | [8] | |||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,186 | [8] | 24,563 | [8] | |||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53,408 | [9] | 102,713 | [9] | |||||
G&A | ' | ' | ' | ' | ' | ' | ' | ' | ' | -553 | [10] | ' | ||||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,060 | [11] | 15,846 | [11] | |||||
Capitalized interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | -643 | [12] | -868 | [12] | |||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,720 | [7] | 25,856 | [7] | |||||
Insurance costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | 475 | [13] | 633 | [13] | |||||
Opal Properties And Fairway Properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 64,000 | |||||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,500 | |||||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,500 | |||||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,300 | |||||||
Opal Properties And Fairway Properties | Pro Forma | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 52,383 | [14] | ||||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,368 | [14] | ||||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,836 | [15] | ||||||
G&A | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,596 | [16] | ||||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,612 | [17] | ||||||
Capitalized interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,086 | [18] | ||||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $4,287 | [7] | ||||||
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. | |||||||||||||||||
[2] | Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. | |||||||||||||||||
[3] | 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. | |||||||||||||||||
[4] | 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. | |||||||||||||||||
[5] | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $82.4 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. | |||||||||||||||||
[6] | 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. Positive amounts represent increases to net expenses. The negative amount represents a decrease to net expenses. | |||||||||||||||||
[7] | Income tax expense was computed using the 35% federal statutory rate. | |||||||||||||||||
[8] | Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. | |||||||||||||||||
[9] | 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. | |||||||||||||||||
[10] | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results. | |||||||||||||||||
[11] | The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.7 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. | |||||||||||||||||
[12] | 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. | |||||||||||||||||
[13] | 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. | |||||||||||||||||
[14] | Revenues and direct operating expenses for the Opal Properties and the Fairway Properties were derived from the historical records of the sellers up to the respective closing dates. | |||||||||||||||||
[15] | DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Opal Properties and Fairway 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 were estimated by W&T management. | |||||||||||||||||
[16] | G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2011 results. | |||||||||||||||||
[17] | The acquisitions were assumed to be funded entirely with borrowed funds and that borrow capacity would have been available on the revolving bank credit facility due to the increase in reserves. Interest expense was computed using assumed borrowings of $437.2 million, which equates to the cash component of the transactions, and an interest rate ranging from 2.6% to 3.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. | |||||||||||||||||
[18] | 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. |
Acquisitions_and_Divestitures_1
Acquisitions and Divestitures - Additional Information (Detail) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||||||||||||||
Jul. 11, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Oct. 17, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 26, 2013 | Oct. 05, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | 15-May-12 | Aug. 10, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | 11-May-11 | |||||
Callon Properties | Callon Properties | West Delta Area Block Twenty Nine | Newfield Properties | Newfield Properties | Newfield Properties | Newfield Properties | South Timbalier 41 | Fairway Properties | Opal Properties And Fairway Properties | Opal Properties And Fairway Properties | Opal Properties And Fairway Properties | Opal Properties | ||||||||||||||||||
acre | Minimum | Maximum | acre | |||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of working interest include in producing interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | 64.30% | ' | ' | ' | ' | ||||
Expenses associated with acquisition activities and transition activities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $400,000 | ' | ' | ' | ' | $600,000 | ' | ' | $1,600,000 | ' | ' | ' | ||||
Revenues | ' | 244,928,000 | [1] | 244,555,000 | [1] | 235,383,000 | [1] | 259,222,000 | [1] | 237,146,000 | 185,946,000 | 215,513,000 | 235,886,000 | 984,088,000 | 874,491,000 | 971,047,000 | ' | 5,800,000 | ' | ' | ' | 29,600,000 | ' | ' | ' | ' | 64,000,000 | ' | ' | ' |
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 270,839,000 | 232,260,000 | 219,206,000 | ' | 1,300,000 | ' | ' | ' | 5,400,000 | ' | ' | ' | ' | 25,500,000 | ' | ' | ' | ||||
Depreciation, depletion, amortization and accretion | ' | ' | ' | ' | ' | ' | ' | ' | ' | 451,529,000 | 356,232,000 | 328,786,000 | ' | 2,400,000 | ' | ' | ' | 11,900,000 | ' | ' | ' | ' | 20,500,000 | ' | ' | ' | ||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,774,000 | 47,547,000 | 91,517,000 | ' | 700,000 | ' | ' | ' | 4,300,000 | ' | ' | ' | ' | 6,300,000 | ' | ' | ' | ||||
Net income | ' | -11,886,000 | [1] | 14,194,000 | [1] | 22,396,000 | [1] | 26,618,000 | [1] | 16,670,000 | -1,471,000 | 53,567,000 | 3,218,000 | 51,322,000 | 71,984,000 | 172,817,000 | ' | 1,400,000 | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | 11,700,000 | ' | ' | ' |
Long-term debt, less current maturities | ' | 1,205,421,000 | ' | ' | ' | 1,087,611,000 | ' | ' | ' | 1,205,421,000 | 1,087,611,000 | ' | ' | 82,400,000 | 82,400,000 | ' | ' | 205,700,000 | ' | 205,700,000 | ' | ' | 437,200,000 | ' | ' | ' | ||||
Effective interest rate | ' | 8.40% | ' | ' | ' | ' | ' | ' | ' | 8.40% | ' | ' | ' | 2.00% | 2.00% | ' | ' | 7.70% | ' | 7.70% | ' | ' | ' | 2.60% | 3.00% | ' | ||||
Federal statutory income tax rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35.00% | 35.00% | 35.00% | ' | ' | 35.00% | ' | ' | ' | ' | 35.00% | ' | ' | 35.00% | ' | ' | ' | ||||
Reversal of asset retirement obligation | 15,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000 | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ||||
Adjustment for effective date to sell properties | 4,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Proceeds from sale of non-operating working interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,500,000 | ' | ' | ' | ' | 30,500,000 | ' | ' | ' | ' | ' | ||||
Number of federal offshore blocks | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Leasehold interest acres acquired, gross | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 416,000 | ' | ' | ' | ' | ' | ' | ' | ' | 24,500 | ||||
Leasehold interest acres acquired, net | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 268,000 | ' | ' | ' | ' | ' | ' | ' | ' | 21,900 | ||||
Adjustments to purchase price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $200,000 | ' | ' | ' | ' | ' | ' | ' | ||||
Percentage of non-operating working interest sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40.00% | ' | ' | ' | ' | ' | ||||
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. |
Hurricane_Remediation_and_Insu1
Hurricane Remediation and Insurance Claims - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2008 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Business Interruption Loss [Line Items] | ' | ' | ' | ' |
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 | ' | 6.7 | 2.9 | 20.9 |
Cumulative insurance recoveries related to hurricanes | ' | $148.90 | ' | ' |
Reconciliation_of_Asset_Retire
Reconciliation of Asset Retirement Obligations Liability (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' | ' |
Asset retirement obligations, beginning of period | $384,053 | $393,880 | ' |
Liabilities settled | -81,543 | -112,827 | ' |
Accretion of discount | 20,918 | 20,055 | 29,771 |
Disposition of properties | -19,564 | -3,993 | ' |
Liabilities assumed through acquisition | 4,233 | 31,664 | ' |
Liabilities incurred | 1,745 | 1,815 | ' |
Asset retirement obligations, end of period | 354,422 | 384,053 | 393,880 |
Less current portion | 77,785 | 92,630 | ' |
Long-term | 276,637 | 291,423 | ' |
Hurricane Ike | ' | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' | ' |
Revisions of estimated liabilities | 6,801 | -20,616 | ' |
All Other | ' | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' | ' |
Revisions of estimated liabilities | $37,779 | $74,075 | ' |
Asset_Retirement_Obligations_A
Asset Retirement Obligations - Additional Information (Detail) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Asset Retirement Obligations [Line Items] | ' | ' |
Reduction in asset retirement obligations | $81,543,000 | $112,827,000 |
Reduction in asset retirement obligations including plug and abandon wells and facilities damaged by hurricane | 11,600,000 | 29,600,000 |
Liabilities assumed through acquisition | 4,233,000 | 31,664,000 |
Liabilities settled | -81,543,000 | -112,827,000 |
Hurricane Ike | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' |
Revisions of estimated liabilities | 6,801,000 | -20,616,000 |
All Other | ' | ' |
Asset Retirement Obligations [Line Items] | ' | ' |
Revisions of estimated liabilities | $37,779,000 | $74,075,000 |
Open_Commodity_Derivatives_Det
Open Commodity Derivatives (Detail) (Swaps - Oil) | 12 Months Ended |
Dec. 31, 2013 | |
Ice Brent Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 674,900 |
Weighted Average Contract Price | 97.38 |
Nymex Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 1,372,000 |
Weighted Average Contract Price | 97.27 |
Argus Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 1,464,000 |
Weighted Average Contract Price | 97.83 |
2014: 1st Quarter | ' |
Derivatives Fair Value [Line Items] | ' |
Termination Period | '1st quarter |
2014: 1st Quarter | Ice Brent Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 180,000 |
Weighted Average Contract Price | 97.38 |
2014: 1st Quarter | Nymex Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 762,000 |
Weighted Average Contract Price | 97.39 |
2014: 1st Quarter | Argus Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 180,000 |
Weighted Average Contract Price | 98.2 |
2014: 2nd Quarter | ' |
Derivatives Fair Value [Line Items] | ' |
Termination Period | '2nd quarter |
2014: 2nd Quarter | Ice Brent Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 172,900 |
Weighted Average Contract Price | 97.38 |
2014: 2nd Quarter | Nymex Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 455,000 |
Weighted Average Contract Price | 97.17 |
2014: 2nd Quarter | Argus Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 364,000 |
Weighted Average Contract Price | 97.88 |
2014: 3rd Quarter | ' |
Derivatives Fair Value [Line Items] | ' |
Termination Period | '3rd quarter |
2014: 3rd Quarter | Ice Brent Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 165,600 |
Weighted Average Contract Price | 97.38 |
2014: 3rd Quarter | Nymex Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 155,000 |
Weighted Average Contract Price | 97 |
2014: 3rd Quarter | Argus Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 552,000 |
Weighted Average Contract Price | 97.65 |
2014: 4th Quarter | ' |
Derivatives Fair Value [Line Items] | ' |
Termination Period | '4th quarter |
2014: 4th Quarter | Ice Brent Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 156,400 |
Weighted Average Contract Price | 97.37 |
2014: 4th Quarter | Nymex Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | ' |
Weighted Average Contract Price | ' |
2014: 4th Quarter | Argus Crude Oil Futures | ' |
Derivatives Fair Value [Line Items] | ' |
Notional Quantity (Bbls) | 368,000 |
Weighted Average Contract Price | 97.88 |
Estimated_Fair_Value_of_Deriva
Estimated Fair Value of Derivative Contracts (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
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 | 6,355 |
Other Liabilities (noncurrent) | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Fair value of commodity derivative contracts | ' | $3,046 |
Changes_in_Fair_Value_of_Commo
Changes in Fair Value of Commodity Derivative Contracts Recognized in Earnings (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Derivative (gain) loss: | ' | ' | ' |
Realized | $8,589 | $7,665 | $9,873 |
Unrealized | -119 | 6,289 | -11,769 |
Total | $8,470 | $13,954 | ($1,896) |
Reconciliation_of_Gross_Assets
Reconciliation of Gross Assets and Liabilities and Netting Agreements on Fair Value of Open Derivative Contracts (Detail) (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 |
Net amounts | ' |
Derivative Liabilities | ' |
Fair value of commodity derivative contracts | 9,423 |
Amounts not offset in the balance sheet | -141 |
Net amounts | $9,282 |
Schedule_of_LongTerm_Debt_Deta
Schedule of Long-Term Debt (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | ||||
Debt Instrument [Line Items] | ' | ' | ||
Long-term Debt unsecured | $900,000 | $900,000 | ||
Debt premiums, net of amortization | 15,421 | 17,611 | ||
Long-term debt secured | 290,000 | 170,000 | ||
Total long-term debt | 1,205,421 | [1] | 1,087,611 | [1] |
Current maturities of long-term debt | ' | ' | ||
Long-term debt, less current maturities | $1,205,421 | $1,087,611 | ||
[1] | Aggregate annual maturities of long-term debt as of December 31, 2013 are as follows (in millions): 2014–$0.0; 2015–$0.0; 2016–$0.0; 2017–$0.0; thereafter–$1,190.0. |
Schedule_of_LongTerm_Debt_Pare
Schedule of Long-Term Debt (Parenthetical) (Detail) (USD $) | 1 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Oct. 24, 2012 | Jun. 10, 2011 | Dec. 31, 2013 |
Debt Instrument [Line Items] | ' | ' | ' |
Aggregate annual maturities of long-term debt, 2014 | ' | ' | 0 |
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, thereafter | ' | ' | 1,190 |
Senior notes interest rate | ' | ' | 8.50% |
Senior notes maturity date | ' | ' | 15-Jun-19 |
8.50% Senior Notes, due June 2019 | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' |
Senior notes interest rate | 8.50% | 8.50% | 8.50% |
Senior notes maturity date | 15-Jun-19 | 15-Jun-19 | 15-Jun-19 |
Revolving Bank Credit Facility Due November 2018 | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' |
Senior notes maturity date | ' | ' | 8-Nov-18 |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Detail) (USD $) | 12 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 24, 2012 | Jun. 10, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Nov. 30, 2013 | Dec. 31, 2013 | Nov. 08, 2013 | Dec. 31, 2012 | |||
Minimum | Maximum | 8.50% Senior Notes, due June 15, 2019 | 8.50% Senior Notes, due June 15, 2019 | 8.50% Senior Notes, due June 15, 2019 | 8.50% Senior Notes, due June 15, 2019 | 8.50% Senior Notes, due June 15, 2019 | Revolving Bank Credit Facility Due November 8, 2018 | Revolving Bank Credit Facility Due November 8, 2018 | Revolving Bank Credit Facility Due November 8, 2018 | Revolving Bank Credit Facility Due November 8, 2018 | |||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Long-term Debt unsecured | $900,000,000 | $900,000,000 | ' | ' | $300,000,000 | $600,000,000 | $900,000,000 | $900,000,000 | ' | ' | ' | ' | ' | ||
Debt issuance, premium percentage | ' | ' | ' | ' | 106.00% | ' | ' | ' | ' | ' | ' | ' | ' | ||
Senior notes interest rate | 8.50% | ' | ' | ' | 8.50% | 8.50% | 8.50% | ' | 8.25% | ' | ' | ' | ' | ||
Senior notes maturity date | 15-Jun-19 | ' | ' | ' | 15-Jun-19 | 15-Jun-19 | 15-Jun-19 | ' | 1-Jun-14 | ' | 8-Nov-18 | ' | ' | ||
Net proceeds after fees and expenses | ' | ' | ' | ' | 312,000,000 | 593,500,000 | ' | ' | ' | ' | ' | ' | ' | ||
Effective interest rate | 8.40% | ' | ' | ' | 7.70% | ' | ' | ' | ' | ' | 3.80% | ' | ' | ||
Senior notes | 1,205,421,000 | [1] | 1,087,611,000 | [1] | ' | ' | ' | ' | ' | ' | 450,000,000 | ' | ' | ' | ' |
Cost related to repurchase of senior notes | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | ' | ' | ' | ' | ||
Senior notes payment terms | 'semi-annually in arrears on June 15 and December 15 of each year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Estimated senior notes fair value | 962,500,000 | 963,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revolving bank credit facility borrowing base | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 800,000,000 | ' | ||
Revolving bank credit facility maximum lender commitment | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000,000 | ' | ' | ' | ||
Letters of credit outstanding | 400,000 | 600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | ' | ||
Credit agreement expiration date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8-Nov-18 | ' | ' | ||
Restriction on payment of dividends | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock and senior note repurchases | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Percentage of hedging contracts | 75.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Percentage adjustment used to adjust the 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 (“LIBORâ€) 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%. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unused portion of the borrowing base commitment fee | ' | ' | 0.38% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Leverage ratio | ' | ' | 1 | 3.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Current ratio | ' | ' | 1 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Long-term debt secured | $290,000,000 | $170,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $290,000,000 | ' | $170,000,000 | ||
[1] | Aggregate annual maturities of long-term debt as of December 31, 2013 are as follows (in millions): 2014–$0.0; 2015–$0.0; 2016–$0.0; 2017–$0.0; thereafter–$1,190.0. |
Schedule_of_Fair_Value_of_Deri
Schedule of Fair Value of Derivatives Financial Instruments and Senior Notes (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
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 | ' |
Derivative liabilities | 9,423 | 9,401 |
8.50% Senior Notes | 962,460 | 963,000 |
Revolving bank credit facility | $290,000 | $170,000 |
Fair_Value_Measurements_Additi
Fair Value Measurements - Additional Information (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
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 | 290,000 | 170,000 |
Fair Value, Inputs, Level 2 | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Revolving bank credit facility | $290,000 | $170,000 |
Equity_Structure_and_Transacti1
Equity Structure and Transactions - Additional Information (Detail) (USD $) | 12 Months Ended | 1 Months Ended | ||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Mar. 06, 2014 |
Common Stock, Regular | Common Stock, Regular | Common Stock, Regular | Common Stock, Special | Common Stock, Special | Common Stock, Special | Subsequent Event | ||||
Equity Structure And Transactions [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, shares authorized | 20,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, par value | $0.00 | $0.00 | ' | ' | ' | ' | ' | ' | ' | ' |
Paid cash dividends, per share | ' | ' | ' | $0.36 | $0.32 | $0.16 | $0.42 | $0.79 | $0.63 | ' |
Cash dividends paid | $58,846 | $82,832 | $58,756 | ' | ' | ' | $31,800 | $59,000 | $46,900 | ' |
Dividends declared, per common share | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0.10 |
Dividend payable date | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31-Mar-14 |
Dividend record date | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18-Mar-14 |
Incentive_Compensation_Plan_Ad
Incentive Compensation Plan - Additional Information (Detail) | 12 Months Ended | ||||||
Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | |
Adjusted EBITDA and Adjusted EBITDA Margin | Total Shareholder Return | Total Shareholder Return | Earnings Per Share Targets | Earnings Per Share Targets | |||
Compensation Plan [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Restricted stock units earning per share, minimum | ' | ' | 0.00% | 0.00% | 0.00% | 0.00% | 0.00% |
Restricted stock units earning per share, maximum | ' | ' | 150.00% | 200.00% | 150.00% | 100.00% | 100.00% |
Percentage of restricted stock units granted not subject to performance criteria | 3.00% | ' | ' | ' | ' | ' | ' |
Percentage of RSUs affected by performance | ' | 100.00% | ' | ' | ' | ' | ' |
Expected vesting month and year | ' | '2013-12 | ' | ' | ' | ' | ' |
Summary_of_Share_Activity_Rela
Summary of Share Activity Related to Restricted Stock (Detail) (Restricted Stock, USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Shares, Nonvested, beginning of period | 43,687 | 51,870 | 470,392 |
Shares, Granted | 27,450 | 21,954 | 20,433 |
Shares, Vested | -27,297 | -27,475 | -404,422 |
Shares, Forfeited | ' | -2,662 | -34,533 |
Shares, Nonvested, end of period | 43,840 | 43,687 | 51,870 |
Weighted Average Grant Date Value Per Share, Beginning of period | $18.69 | $15.81 | $7.42 |
Weighted Average Grant Date Fair Value Per Share, Granted | $12.75 | $19.13 | $25.45 |
Weighted Average Grant Date Fair Value Per Share, Vested | $17.09 | $13.59 | $7.31 |
Weighted Average Grant Date Fair Value Per Share, Forfeited | ' | $18.78 | $6.83 |
Weighted Average Grant Date Value Per Share, End of period | $15.96 | $18.69 | $15.81 |
Outstanding_Restricted_Shares_
Outstanding Restricted Shares Issued to Non-employee Directors (Detail) (Restricted Stock) | 12 Months Ended |
Dec. 31, 2013 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Awards expected to vest by period | 43,840 |
2014 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Awards expected to vest by period | 19,445 |
2015 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Awards expected to vest by period | 15,245 |
2016 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Awards expected to vest by period | 9,150 |
Summary_of_Share_Activity_Rela1
Summary of Share Activity Related to Restricted Stock Units (Detail) (Restricted Stock Units (RSUs), USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock Units (RSUs) | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Shares, Nonvested, beginning of period | 969,820 | 1,732,703 | 1,266,617 |
Shares, Granted | 969,919 | 764,654 | 534,375 |
Shares, Vested | -468,925 | -1,198,208 | ' |
Shares, Forfeited | -139,061 | -329,329 | -68,289 |
Shares, Nonvested, end of period | 1,331,753 | 969,820 | 1,732,703 |
Weighted Average Grant Date Value Per Share, Beginning of period | $22.70 | $14.67 | $9.36 |
Weighted Average Grant Date Fair Value Per Share, Granted | $13.23 | $18.64 | $26.93 |
Weighted Average Grant Date Fair Value Per Share, Vested | $26.93 | $9.36 | ' |
Weighted Average Grant Date Fair Value Per Share, Forfeited | $16.50 | $19.56 | $12.03 |
Weighted Average Grant Date Value Per Share, End of period | $14.96 | $22.70 | $14.67 |
Restricted_Stock_Unit_Outstand
Restricted Stock Unit Outstanding (Detail) (Restricted Stock Units (RSUs)) | 12 Months Ended | |
Dec. 31, 2013 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | |
Awards expected to vest by period | 1,331,753 | |
2014 | Restricted Stock Units subject to service requirements | ' | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | |
Awards expected to vest by period | 359,785 | |
2014 | 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 | 67,877 | [1] |
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 | 719,971 | |
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 | 184,120 | [1] |
[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_Expens
Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Share-based compensation | $11,525 | $12,398 | $9,710 |
Tax benefit computed at the statutory rate | 4,034 | 4,339 | 3,399 |
Restricted Stock | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Share-based compensation | 397 | 399 | 2,377 |
Restricted Stock Units (RSUs) | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Share-based compensation | $11,128 | $11,999 | $7,333 |
Summary_of_Incentive_Compensat
Summary of Incentive Compensation Expense (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ' | ' | ' |
Share-based compensation charged to operating income | $11,525 | $12,398 | $9,710 |
Cash-based incentive compensation charged to operating income | 12,299 | 10,345 | 15,913 |
Total incentive compensation charged to operating income | 23,824 | 22,743 | 25,623 |
Lease Operating Expense | ' | ' | ' |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ' | ' | ' |
Share-based compensation charged to operating income | ' | ' | 466 |
Cash-based incentive compensation charged to operating income | 3,482 | 3,787 | 3,700 |
General and Administrative Expense | ' | ' | ' |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | ' | ' | ' |
Share-based compensation charged to operating income | 11,525 | 12,398 | 9,244 |
Cash-based incentive compensation charged to operating income | $8,817 | $6,558 | $12,213 |
ShareBased_and_CashBased_Incen2
Share-Based and Cash-Based Incentive Compensation - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Common stock available for award under plans | 5,078,983 | ' | ' |
Additional shares authorized under share based compensation arrangements | 4,000,000 | ' | ' |
Directors Compensation Plan | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Common stock available for award under plans | 519,379 | ' | ' |
Restricted Stock | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Shares granted, grant date fair value | $0.30 | $0.40 | $0.50 |
Shares vested, vested date fair value | 0.4 | 0.5 | 7.9 |
Unrecognized share-based compensation expense | 0.5 | ' | ' |
Recognition period for unrecognized compensation expense | '2016-04 | ' | ' |
Restricted Stock Units (RSUs) | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' |
Shares granted, grant date fair value | 12.8 | 14.3 | 14.4 |
Shares vested, vested date fair value | 7.2 | 20 | ' |
Adjusted EBITDA | 40.00% | ' | ' |
Adjusted EBITDA margin | 30.00% | ' | ' |
TSR ranking totaled | 30.00% | 30.00% | ' |
TSR ranking for each of three-year performance periods | 10.00% | 10.00% | ' |
EPS comprised | ' | 70.00% | ' |
Unrecognized share-based compensation expense | $12.10 | ' | ' |
Recognition period for unrecognized compensation expense | '2015-11 | ' | ' |
Restricted Stock Units (RSUs) | 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 volatility | 30.00% | 33.00% | ' |
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 volatility | 63.00% | 74.00% | ' |
Expected dividend yield | 3.10% | 2.50% | ' |
Correlation of movement of total shareholder return | 95.00% | 94.00% | ' |
Restricted_Stock_Unit_Outstand1
Restricted Stock Unit Outstanding (Parenthetical) (Detail) (Restricted Stock Units (RSUs), Restricted Stock Units subject to service and other requirements) | 12 Months Ended |
Dec. 31, 2013 | |
Minimum | 2014 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Restricted Stock Units adjustments, percentage | 0.00% |
Minimum | 2015 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Restricted Stock Units adjustments, percentage | 0.00% |
Maximum | 2014 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Restricted Stock Units adjustments, percentage | 200.00% |
Maximum | 2015 | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Restricted Stock Units adjustments, percentage | 200.00% |
Employee_Benefit_Plan_Addition
Employee Benefit Plan - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Defined Contribution Pension And Other Postretirement Plans [Line Items] | ' | ' | ' |
Percentage of matching contribution of each participants | 100.00% | 100.00% | 100.00% |
Maximum contribution percentage of participating employees | 6.00% | 6.00% | 5.00% |
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 | $2.10 | $2.10 | $1.80 |
Components_of_Income_Tax_Expen
Components of Income Tax Expense (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ' | ' | ' |
Current | ($2,146) | ($40,562) | $29,682 |
Deferred | 30,920 | 88,109 | 61,835 |
Income tax expense (benefit) | $28,774 | $47,547 | $91,517 |
Reconciliation_of_Income_Taxes
Reconciliation of Income Taxes Computed to Income Tax Expense (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount [Abstract] | ' | ' | ' |
Income tax expense at the federal statutory rate | $28,033 | $41,836 | $92,517 |
Qualified domestic production activities | ' | -4,256 | 1,823 |
State income taxes | 343 | 750 | 603 |
Other | 398 | 705 | 220 |
Income tax expense (benefit) | $28,774 | $47,547 | $91,517 |
Income tax expense at the federal statutory rate, tax rate | 35.00% | 35.00% | 35.00% |
Qualified domestic production activities, tax rate | ' | 3.50% | -0.70% |
State income taxes, tax rate | 0.40% | 0.70% | 0.20% |
Other, tax rate | 0.50% | 0.60% | 0.10% |
Effective income tax rate, total | 35.90% | 39.80% | 34.60% |
Significant_Components_of_Defe
Significant Components of Deferred Tax Assets and Liabilities (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Deferred tax liabilities: | ' | ' |
Property and equipment | $297,942 | $186,599 |
Other | 3,602 | 4,822 |
Total deferred tax liabilities | 301,544 | 191,421 |
Deferred tax assets: | ' | ' |
Minimum tax credit | 20,486 | 22,314 |
Federal net operating losses | 91,472 | 12,389 |
State net operating losses | 5,028 | 5,057 |
Derivatives | 3,270 | 3,312 |
Accrued cash-based bonus | 3,873 | 2,455 |
Stock-based compensation | 3,703 | 4,256 |
Other | 643 | 1,330 |
Total deferred tax assets | 123,985 | 46,439 |
Net deferred tax liabilities | 177,559 | 144,982 |
State and Local Jurisdiction | ' | ' |
Deferred tax assets: | ' | ' |
Valuation allowance | ($4,490) | ($4,674) |
Net_Operating_Loss_and_Tax_Cre
Net Operating Loss and Tax Credit Carryovers (Detail) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2013 |
Internal Revenue Service (IRS) | ' |
Operating Loss Carryforwards [Line Items] | ' |
Net operating loss | $263,388 |
Net operating loss, expiration year | '2033 |
State and Local Jurisdiction | ' |
Operating Loss Carryforwards [Line Items] | ' |
Net operating loss | 95,912 |
State and Local Jurisdiction | Minimum | ' |
Operating Loss Carryforwards [Line Items] | ' |
Net operating loss, expiration year | '2017 |
State and Local Jurisdiction | Maximum | ' |
Operating Loss Carryforwards [Line Items] | ' |
Net operating loss, expiration year | '2028 |
Minimum Tax Credits | ' |
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 | '2027 |
General Business Tax Credit Carryforward | Maximum | ' |
Operating Loss Carryforwards [Line Items] | ' |
Tax credit carryforward, expiration year | '2028 |
Balances_and_Changes_in_Uncert
Balances and Changes in Uncertain Tax Positions (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Uncertainties [Line Items] | ' | ' |
Balance at beginning of period | ' | ' |
Increases related to carryback positions | 9,482 | ' |
Balance at end of period | $9,482 | ' |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Detail) (USD $) | 12 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Tax loss carrybacks to 2010 and 2011 | Tax loss carrybacks to 2010 and 2011 | Tax loss carrybacks to 2010 and 2011 | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash paid for income taxes | $3,000,000 | $16,056,000 | $35,655,000 | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefits | 9,482,000 | ' | ' | ' | ' | ' | 9,500,000 | ' | ' |
Proceeds from income tax refunds | 59,126,000 | 479,000 | 379,000 | ' | ' | ' | 59,100,000 | 500,000 | 400,000 |
Income tax | 3,120,000 | 47,884,000 | ' | ' | ' | ' | ' | ' | ' |
Income tax receivable component from operating loss carryback | ' | ' | ' | ' | 13,800,000 | 29,100,000 | ' | ' | ' |
Income tax receivable component from refund of estimated tax payments | ' | ' | ' | $5,000,000 | ' | ' | ' | ' | ' |
Schedule_of_Calculation_of_Bas
Schedule of Calculation of Basic and Diluted Earnings Per Common Share (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Earnings Per Share Basic and Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net income | ($11,886) | [1] | $14,194 | [1] | $22,396 | [1] | $26,618 | [1] | $16,670 | ($1,471) | $53,567 | $3,218 | $51,322 | $71,984 | $172,817 | ||||
Less portion allocated to nonvested shares | ' | ' | ' | ' | ' | ' | ' | ' | 303 | 983 | 3,211 | ||||||||
Net income allocated to common shares | ' | ' | ' | ' | ' | ' | ' | ' | $51,019 | $71,001 | $169,606 | ||||||||
Weighted average common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | 75,239 | 74,354 | 74,033 | ||||||||
Basic and diluted earnings per common share | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | $0.21 | [2] | ($0.02) | [2] | $0.70 | [2] | $0.04 | [2] | $0.68 | $0.95 | $2.29 |
Shares excluded due to being anti-dilutive | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,923 | 1,873 | ||||||||
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. | ||||||||||||||||||
[2] | 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. |
Supplemental_Cash_Flow_Informa2
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Cash paid for interest, net of interest capitalized of $10,058 in 2013, $13,274 in 2012 and $9,877 in 2011 | $73,909 | $46,247 | $39,772 | |||
Cash paid for income taxes | 3,000 | 16,056 | 35,655 | |||
Cash refunds received for income taxes | 59,126 | 479 | 379 | |||
Cash paid for share-based compensation | 466 | [1] | 1,531 | [1] | 1,062 | [1] |
Cash tax benefit related to share-based compensation | ' | [2] | $5,962 | [2] | $3,125 | [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 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) (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Cash paid, interest capitalized | $10,058 | $13,274 | $9,877 |
Commitments_Additional_Informa
Commitments - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Commitments [Line Items] | ' | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2014 | $1.30 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2015 | 1.3 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2016 | 1.3 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2017 | 1.4 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, thereafter | 8 | ' | ' |
Total rent expense | 2.6 | 1.7 | 1.9 |
Security amount requirement | 55 | ' | ' |
Additional security requirements for 2014 | 9 | ' | ' |
Additional security requirements for 2015 | 9 | ' | ' |
Additional security requirements for 2016 | 6 | ' | ' |
Additional security requirements for 2017 | 6 | ' | ' |
Additional security requirements for 2018 to 2023 | 18 | ' | ' |
Total security requirement | 103 | ' | ' |
Fees related to bonds | 5 | 2.9 | 2.6 |
Future estimated costs, 2014 | 5.5 | ' | ' |
Future estimated costs, 2015 | 5.7 | ' | ' |
Future estimated costs, 2016 | 5.8 | ' | ' |
Future estimated costs, 2017 | 5.7 | ' | ' |
Future estimated costs, thereafter | 48.4 | ' | ' |
Drilling Rig Commitments | ' | ' | ' |
Commitments [Line Items] | ' | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2013 | 21.5 | ' | ' |
Helix Well Containment Group | ' | ' | ' |
Commitments [Line Items] | ' | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2014 | 1.9 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2015 | 1.9 | ' | ' |
Minimum future lease payments due under noncancelable operating leases, 2016 | 1.9 | ' | ' |
Other commitment | ' | ' | ' |
Commitments [Line Items] | ' | ' | ' |
Security requirement minimum | 74 | ' | ' |
Security requirement maximum | $94 | ' | ' |
Related_Parties_Additional_Inf
Related Parties - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Airplane Services | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related party transactions | $1.20 | $1 | $1.10 |
Directional Drilling Services | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related party transactions | 0.2 | 0.7 | ' |
Minimum | Logistic services | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related party transactions | $0.10 | $0.10 | $0.10 |
Contingencies_Additional_Infor
Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2013 | Jan. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2009 | Sep. 30, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | |
Subsequent Event | Cameron Parish Louisiana Claim | Cameron Parish Louisiana Claim | Royalties | Royalties | Contingent Liability Recorded | Contingent Liability Recorded | Contingent Liability Recorded | Environmental Issue | Environmental Issue | ||
Plea Agreement Fine | Community Service Payment | ||||||||||
Loss Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Plea agreement fine payment, which is subject to federal district court approval | ' | ' | ' | ' | ' | ' | ' | ' | ' | $700,000 | $300,000 |
Claims paid | ' | ' | 1,300,000 | 10,000,000 | ' | ' | ' | ' | ' | ' | ' |
Costs incurred related to an insurance claim in dispute | 45,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Costs anticipated to be incurred related to an insurance claim in dispute | 1,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Allowable reductions of cash payments | ' | ' | ' | ' | 5,300,000 | ' | ' | ' | ' | ' | ' |
Notified disallowed amount in reductions taken by ONRR | ' | ' | ' | ' | ' | 4,700,000 | ' | ' | ' | ' | ' |
Expenses related to accrued and settled claims | ' | ' | ' | ' | ' | ' | 500,000 | 9,300,000 | 1,700,000 | ' | ' |
Liability loss contingency | ' | ' | ' | ' | ' | ' | 200,000 | 1,300,000 | ' | ' | ' |
Underpayment of royalties | ' | $30,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Selected_Quarterly_Financial_D2
Selected Quarterly Financial Data (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Quarterly Financial Data [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Revenues | $244,928 | [1] | $244,555 | [1] | $235,383 | [1] | $259,222 | [1] | $237,146 | $185,946 | $215,513 | $235,886 | $984,088 | $874,491 | $971,047 | ||||
Operating income | 622 | [1] | 31,965 | [1] | 53,823 | [1] | 60,321 | [1] | 46,737 | 7,560 | 99,100 | 15,913 | 146,731 | 169,310 | 329,460 | ||||
Net income | ($11,886) | [1] | $14,194 | [1] | $22,396 | [1] | $26,618 | [1] | $16,670 | ($1,471) | $53,567 | $3,218 | $51,322 | $71,984 | $172,817 | ||||
Basic and diluted earnings (loss) per common share | ($0.16) | [1],[2] | $0.19 | [1],[2] | $0.29 | [1],[2] | $0.35 | [1],[2] | $0.21 | [2] | ($0.02) | [2] | $0.70 | [2] | $0.04 | [2] | $0.68 | $0.95 | $2.29 |
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. | ||||||||||||||||||
[2] | 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. |
Selected_Quarterly_Financial_D3
Selected Quarterly Financial Data - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2013 |
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 | 3.2 |
Condensed_Consolidating_Balanc
Condensed Consolidating Balance Sheet (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
In Thousands, unless otherwise specified | ||||
Current assets: | ' | ' | ' | ' |
Cash and cash equivalents | $15,800 | $12,245 | $4,512 | $28,655 |
Receivables: | ' | ' | ' | ' |
Oil and natural gas sales | 96,752 | 97,733 | ' | ' |
Joint interest and other | 27,984 | 56,439 | ' | ' |
Income taxes | 3,120 | 47,884 | ' | ' |
Total receivables | 127,856 | 202,056 | ' | ' |
Prepaid expenses and other assets | 29,946 | 25,822 | ' | ' |
Total current assets | 173,602 | 240,123 | ' | ' |
Property and equipment – at cost: | ' | ' | ' | ' |
Oil and natural gas properties and equipment | 7,339,097 | 6,694,510 | ' | ' |
Furniture, fixtures and other | 21,431 | 21,786 | ' | ' |
Total property and equipment | 7,360,528 | 6,716,296 | ' | ' |
Less accumulated depreciation, depletion and amortization | 5,084,704 | 4,655,841 | ' | ' |
Net property and equipment | 2,275,824 | 2,060,455 | ' | ' |
Restricted deposits for asset retirement obligations | 37,421 | 28,466 | ' | ' |
Other assets | 20,455 | 19,943 | ' | ' |
Total assets | 2,507,302 | 2,348,987 | ' | ' |
Current liabilities: | ' | ' | ' | ' |
Accounts payable | 145,212 | 123,885 | ' | ' |
Undistributed oil and natural gas proceeds | 42,107 | 37,073 | ' | ' |
Asset retirement obligations | 77,785 | 92,630 | ' | ' |
Accrued liabilities | 28,000 | 21,021 | ' | ' |
Total current liabilities | 293,104 | 274,609 | ' | ' |
Long-term debt, less current maturities | 1,205,421 | 1,087,611 | ' | ' |
Asset retirement obligations, less current portion | 276,637 | 291,423 | ' | ' |
Deferred income taxes | 178,142 | 145,249 | ' | ' |
Other liabilities | 13,388 | 8,908 | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Shareholders’ equity: | ' | ' | ' | ' |
Common stock | 1 | 1 | ' | ' |
Additional paid-in capital | 403,564 | 396,186 | ' | ' |
Retained earnings | 161,212 | 169,167 | ' | ' |
Treasury stock, at cost | -24,167 | -24,167 | ' | ' |
Total shareholders’ equity | 540,610 | 541,187 | ' | ' |
Total liabilities and shareholders’ equity | 2,507,302 | 2,348,987 | ' | ' |
Parent Company | ' | ' | ' | ' |
Current assets: | ' | ' | ' | ' |
Cash and cash equivalents | 15,800 | 12,245 | 4,512 | 28,655 |
Receivables: | ' | ' | ' | ' |
Oil and natural gas sales | 75,486 | 80,729 | ' | ' |
Joint interest and other | 27,984 | 56,439 | ' | ' |
Income taxes | 124,393 | 163,750 | ' | ' |
Total receivables | 227,863 | 300,918 | ' | ' |
Prepaid expenses and other assets | 23,674 | 25,822 | ' | ' |
Total current assets | 267,337 | 338,985 | ' | ' |
Property and equipment – at cost: | ' | ' | ' | ' |
Oil and natural gas properties and equipment | 6,770,396 | 6,356,529 | ' | ' |
Furniture, fixtures and other | 21,431 | 21,786 | ' | ' |
Total property and equipment | 6,791,827 | 6,378,315 | ' | ' |
Less accumulated depreciation, depletion and amortization | 4,784,932 | 4,461,886 | ' | ' |
Net property and equipment | 2,006,895 | 1,916,429 | ' | ' |
Restricted deposits for asset retirement obligations | 37,421 | 28,466 | ' | ' |
Other assets | 574,280 | 442,540 | ' | ' |
Total assets | 2,885,933 | 2,726,420 | ' | ' |
Current liabilities: | ' | ' | ' | ' |
Accounts payable | 144,492 | 123,792 | ' | ' |
Undistributed oil and natural gas proceeds | 41,735 | 36,791 | ' | ' |
Asset retirement obligations | 75,977 | 92,595 | ' | ' |
Accrued liabilities | 28,000 | 20,755 | ' | ' |
Total current liabilities | 290,204 | 273,933 | ' | ' |
Long-term debt, less current maturities | 1,205,421 | 1,087,611 | ' | ' |
Asset retirement obligations, less current portion | 238,270 | 262,524 | ' | ' |
Deferred income taxes | 170,419 | 158,758 | ' | ' |
Other liabilities | 441,009 | 402,407 | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Shareholders’ equity: | ' | ' | ' | ' |
Common stock | 1 | 1 | ' | ' |
Additional paid-in capital | 403,564 | 396,186 | ' | ' |
Retained earnings | 161,212 | 169,167 | ' | ' |
Treasury stock, at cost | -24,167 | -24,167 | ' | ' |
Total shareholders’ equity | 540,610 | 541,187 | ' | ' |
Total liabilities and shareholders’ equity | 2,885,933 | 2,726,420 | ' | ' |
Guarantor Subsidiaries | ' | ' | ' | ' |
Receivables: | ' | ' | ' | ' |
Oil and natural gas sales | 21,266 | 17,004 | ' | ' |
Total receivables | 21,266 | 17,004 | ' | ' |
Prepaid expenses and other assets | 6,272 | ' | ' | ' |
Total current assets | 27,538 | 17,004 | ' | ' |
Property and equipment – at cost: | ' | ' | ' | ' |
Oil and natural gas properties and equipment | 568,701 | 337,981 | ' | ' |
Total property and equipment | 568,701 | 337,981 | ' | ' |
Less accumulated depreciation, depletion and amortization | 299,772 | 193,955 | ' | ' |
Net property and equipment | 268,929 | 144,026 | ' | ' |
Other assets | 427,619 | 407,008 | ' | ' |
Total assets | 724,086 | 568,038 | ' | ' |
Current liabilities: | ' | ' | ' | ' |
Accounts payable | 720 | 93 | ' | ' |
Undistributed oil and natural gas proceeds | 372 | 282 | ' | ' |
Asset retirement obligations | 1,808 | ' | ' | ' |
Accrued liabilities | 121,273 | 116,132 | ' | ' |
Total current liabilities | 124,173 | 116,507 | ' | ' |
Asset retirement obligations, less current portion | 38,367 | 28,934 | ' | ' |
Deferred income taxes | 7,723 | ' | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Shareholders’ equity: | ' | ' | ' | ' |
Additional paid-in capital | 317,776 | 231,759 | ' | ' |
Retained earnings | 236,047 | 190,838 | ' | ' |
Total shareholders’ equity | 553,823 | 422,597 | ' | ' |
Total liabilities and shareholders’ equity | 724,086 | 568,038 | ' | ' |
Eliminations | ' | ' | ' | ' |
Current assets: | ' | ' | ' | ' |
Cash and cash equivalents | ' | ' | ' | ' |
Receivables: | ' | ' | ' | ' |
Income taxes | -121,273 | -115,866 | ' | ' |
Total receivables | -121,273 | -115,866 | ' | ' |
Total current assets | -121,273 | -115,866 | ' | ' |
Property and equipment – at cost: | ' | ' | ' | ' |
Other assets | -981,444 | -829,605 | ' | ' |
Total assets | -1,102,717 | -945,471 | ' | ' |
Current liabilities: | ' | ' | ' | ' |
Asset retirement obligations | ' | 35 | ' | ' |
Accrued liabilities | -121,273 | -115,866 | ' | ' |
Total current liabilities | -121,273 | -115,831 | ' | ' |
Asset retirement obligations, less current portion | ' | -35 | ' | ' |
Deferred income taxes | ' | -13,509 | ' | ' |
Other liabilities | -427,621 | -393,499 | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Shareholders’ equity: | ' | ' | ' | ' |
Additional paid-in capital | -317,776 | -231,759 | ' | ' |
Retained earnings | -236,047 | -190,838 | ' | ' |
Total shareholders’ equity | -553,823 | -422,597 | ' | ' |
Total liabilities and shareholders’ equity | ($1,102,717) | ($945,471) | ' | ' |
Condensed_Consolidating_Statem
Condensed Consolidating Statement of Income (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Condensed Financial Statements Captions [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Revenues | $244,928 | [1] | $244,555 | [1] | $235,383 | [1] | $259,222 | [1] | $237,146 | $185,946 | $215,513 | $235,886 | $984,088 | $874,491 | $971,047 |
Operating costs and expenses: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 270,839 | 232,260 | 219,206 | ||||
Production taxes | ' | ' | ' | ' | ' | ' | ' | ' | 7,135 | 5,840 | 4,275 | ||||
Gathering and transportation | ' | ' | ' | ' | ' | ' | ' | ' | 17,510 | 14,878 | 16,920 | ||||
Depreciation, depletion and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 430,611 | 336,177 | 299,015 | ||||
Asset retirement obligation accretion | ' | ' | ' | ' | ' | ' | ' | ' | 20,918 | 20,055 | 29,771 | ||||
General and administrative expenses | ' | ' | ' | ' | ' | ' | ' | ' | 81,874 | 82,017 | 74,296 | ||||
Derivative (gain) loss | ' | ' | ' | ' | ' | ' | ' | ' | 8,470 | 13,954 | -1,896 | ||||
Total costs and expenses | ' | ' | ' | ' | ' | ' | ' | ' | 837,357 | 705,181 | 641,587 | ||||
Operating income | 622 | [1] | 31,965 | [1] | 53,823 | [1] | 60,321 | [1] | 46,737 | 7,560 | 99,100 | 15,913 | 146,731 | 169,310 | 329,460 |
Interest expense: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 85,639 | 63,268 | 52,393 | ||||
Capitalized | ' | ' | ' | ' | ' | ' | ' | ' | -10,058 | -13,274 | -9,877 | ||||
Loss on extinguishment of debt | ' | ' | ' | ' | ' | ' | ' | ' | 128 | ' | 22,694 | ||||
Other income | ' | ' | ' | ' | ' | ' | ' | ' | 9,074 | 215 | 84 | ||||
Income before income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 80,096 | 119,531 | 264,334 | ||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 28,774 | 47,547 | 91,517 | ||||
Net income | -11,886 | [1] | 14,194 | [1] | 22,396 | [1] | 26,618 | [1] | 16,670 | -1,471 | 53,567 | 3,218 | 51,322 | 71,984 | 172,817 |
Parent Company | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Condensed Financial Statements Captions [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 780,442 | 659,203 | 697,899 | ||||
Operating costs and expenses: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 252,511 | 209,581 | 182,165 | ||||
Production taxes | ' | ' | ' | ' | ' | ' | ' | ' | 7,135 | 5,840 | 4,275 | ||||
Gathering and transportation | ' | ' | ' | ' | ' | ' | ' | ' | 13,747 | 11,703 | 12,676 | ||||
Depreciation, depletion and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 324,794 | 253,807 | 214,740 | ||||
Asset retirement obligation accretion | ' | ' | ' | ' | ' | ' | ' | ' | 18,152 | 17,463 | 26,947 | ||||
General and administrative expenses | ' | ' | ' | ' | ' | ' | ' | ' | 78,649 | 79,424 | 71,714 | ||||
Derivative (gain) loss | ' | ' | ' | ' | ' | ' | ' | ' | 8,470 | 13,954 | -1,896 | ||||
Total costs and expenses | ' | ' | ' | ' | ' | ' | ' | ' | 703,458 | 591,772 | 510,621 | ||||
Operating income | ' | ' | ' | ' | ' | ' | ' | ' | 76,984 | 67,431 | 187,278 | ||||
Earnings of affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 45,209 | 66,195 | 92,533 | ||||
Interest expense: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 85,531 | 63,268 | 52,393 | ||||
Capitalized | ' | ' | ' | ' | ' | ' | ' | ' | -9,950 | -13,274 | -9,877 | ||||
Loss on extinguishment of debt | ' | ' | ' | ' | ' | ' | ' | ' | 128 | ' | 22,694 | ||||
Other income | ' | ' | ' | ' | ' | ' | ' | ' | 9,074 | 215 | 84 | ||||
Income before income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 55,558 | 83,847 | 214,685 | ||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 4,236 | 11,863 | 41,868 | ||||
Net income | ' | ' | ' | ' | ' | ' | ' | ' | 51,322 | 71,984 | 172,817 | ||||
Guarantor Subsidiaries | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Condensed Financial Statements Captions [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 203,646 | 215,288 | 273,148 | ||||
Operating costs and expenses: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Lease operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | 18,328 | 22,679 | 37,041 | ||||
Gathering and transportation | ' | ' | ' | ' | ' | ' | ' | ' | 3,763 | 3,175 | 4,244 | ||||
Depreciation, depletion and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 105,817 | 82,370 | 84,275 | ||||
Asset retirement obligation accretion | ' | ' | ' | ' | ' | ' | ' | ' | 2,766 | 2,592 | 2,824 | ||||
General and administrative expenses | ' | ' | ' | ' | ' | ' | ' | ' | 3,225 | 2,593 | 2,582 | ||||
Total costs and expenses | ' | ' | ' | ' | ' | ' | ' | ' | 133,899 | 113,409 | 130,966 | ||||
Operating income | ' | ' | ' | ' | ' | ' | ' | ' | 69,747 | 101,879 | 142,182 | ||||
Interest expense: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Incurred | ' | ' | ' | ' | ' | ' | ' | ' | 108 | ' | ' | ||||
Capitalized | ' | ' | ' | ' | ' | ' | ' | ' | -108 | ' | ' | ||||
Income before income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 69,747 | 101,879 | 142,182 | ||||
Income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | 24,538 | 35,684 | 49,649 | ||||
Net income | ' | ' | ' | ' | ' | ' | ' | ' | 45,209 | 66,195 | 92,533 | ||||
Eliminations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Operating costs and expenses: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Earnings of affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -45,209 | -66,195 | -92,533 | ||||
Interest expense: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income before income tax expense | ' | ' | ' | ' | ' | ' | ' | ' | -45,209 | -66,195 | -92,533 | ||||
Net income | ' | ' | ' | ' | ' | ' | ' | ' | ($45,209) | ($66,195) | ($92,533) | ||||
[1] | In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtuâ€) 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. |
Condensed_Consolidating_Statem1
Condensed Consolidating Statement of Cash Flows (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating activities: | ' | ' | ' |
Net income | $51,322 | $71,984 | $172,817 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Depreciation, depletion, amortization and accretion | 451,529 | 356,232 | 328,786 |
Amortization of debt issuance costs and premium | 1,645 | 2,575 | 2,010 |
Loss on extinguishment of debt | 128 | ' | 22,694 |
Share-based compensation | 11,525 | 12,398 | 9,710 |
Derivative (gain) loss | 8,470 | 13,954 | -1,896 |
Cash payments on derivative settlements (realized) | -8,589 | -7,664 | -9,873 |
Deferred income taxes | 30,920 | 88,109 | 61,835 |
Changes in operating assets and liabilities: | ' | ' | ' |
Oil and natural gas receivables | 980 | 818 | -18,639 |
Joint interest and other receivables | 28,566 | -31,399 | 375 |
Insurance proceeds | 5,691 | 2,576 | 20,771 |
Income taxes | 44,328 | -58,011 | -7,124 |
Prepaid expenses and other assets | -10,044 | 7,440 | -7,809 |
Asset retirement obligations settlements | -81,543 | -112,827 | -59,958 |
Accounts payable and accrued liabilities | 28,132 | 38,026 | 7,881 |
Other | -1,702 | 926 | -102 |
Net cash provided by operating activities | 561,358 | 385,137 | 521,478 |
Investing activities: | ' | ' | ' |
Acquisition of property interest in oil and natural gas properties | -82,424 | -205,550 | -437,247 |
Investment in oil and natural gas properties and equipment | -551,954 | -479,313 | -281,779 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | 15 |
Purchases of furniture, fixtures and other, net | -1,435 | -3,031 | -3,660 |
Net cash used in investing activities | -614,805 | -657,441 | -722,671 |
Financing activities: | ' | ' | ' |
Borrowings of long-term debt - revolving bank credit facility | 563,000 | 732,000 | 623,000 |
Repayments of long-term debt - revolving bank credit facility | -443,000 | -679,000 | -506,000 |
Repurchase premium and debt issuance costs | -3,892 | -8,510 | -32,288 |
Dividends to shareholders | -58,846 | -82,832 | -58,756 |
Other | -260 | 379 | 1,094 |
Net cash provided by financing activities | 57,002 | 280,037 | 177,050 |
Issuance of 8.50% Senior Notes | ' | 318,000 | 600,000 |
Repurchase of 8.25% Senior Notes | ' | ' | -450,000 |
Increase (decrease) in cash and cash equivalents | 3,555 | 7,733 | -24,143 |
Cash and cash equivalents, beginning of period | 12,245 | 4,512 | 28,655 |
Cash and cash equivalents, end of period | 15,800 | 12,245 | 4,512 |
Parent Company | ' | ' | ' |
Operating activities: | ' | ' | ' |
Net income | 51,322 | 71,984 | 172,817 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Depreciation, depletion, amortization and accretion | 342,946 | 271,270 | 241,687 |
Amortization of debt issuance costs and premium | 1,645 | 2,575 | 2,010 |
Loss on extinguishment of debt | 128 | ' | 22,694 |
Share-based compensation | 11,525 | 12,398 | 9,710 |
Derivative (gain) loss | 8,470 | 13,954 | -1,896 |
Cash payments on derivative settlements (realized) | -8,589 | -7,664 | -9,873 |
Deferred income taxes | 11,522 | 83,981 | 76,717 |
Earnings of affiliates | -45,209 | -66,195 | -92,533 |
Changes in operating assets and liabilities: | ' | ' | ' |
Oil and natural gas receivables | 5,242 | -2,597 | -27,709 |
Joint interest and other receivables | 28,566 | -31,399 | 375 |
Insurance proceeds | 5,691 | 2,576 | 20,771 |
Income taxes | 39,188 | -89,568 | -71,655 |
Prepaid expenses and other assets | -5,606 | 7,442 | -8,003 |
Asset retirement obligations settlements | -79,950 | -112,199 | -59,958 |
Accounts payable and accrued liabilities | 27,415 | 40,530 | 8,589 |
Other | 32,418 | 119,244 | 227,918 |
Net cash provided by operating activities | 426,724 | 316,332 | 511,661 |
Investing activities: | ' | ' | ' |
Acquisition of property interest in oil and natural gas properties | -82,424 | -205,550 | -437,247 |
Investment in oil and natural gas properties and equipment | -331,303 | -410,508 | -277,147 |
Investment in subsidiary | -86,017 | ' | 5,185 |
Proceeds from sales of assets and other, net | 21,008 | 30,453 | 15 |
Purchases of furniture, fixtures and other, net | -1,435 | -3,031 | -3,660 |
Net cash used in investing activities | -480,171 | -588,636 | -712,854 |
Financing activities: | ' | ' | ' |
Borrowings of long-term debt - revolving bank credit facility | 563,000 | 732,000 | 623,000 |
Repayments of long-term debt - revolving bank credit facility | -443,000 | -679,000 | -506,000 |
Repurchase premium and debt issuance costs | -3,892 | -8,510 | -32,288 |
Dividends to shareholders | -58,846 | -82,832 | -58,756 |
Other | -260 | 379 | 1,094 |
Net cash provided by financing activities | 57,002 | 280,037 | 177,050 |
Issuance of 8.50% Senior Notes | ' | 318,000 | 600,000 |
Repurchase of 8.25% Senior Notes | ' | ' | -450,000 |
Increase (decrease) in cash and cash equivalents | 3,555 | 7,733 | -24,143 |
Cash and cash equivalents, beginning of period | 12,245 | 4,512 | 28,655 |
Cash and cash equivalents, end of period | 15,800 | 12,245 | 4,512 |
Guarantor Subsidiaries | ' | ' | ' |
Operating activities: | ' | ' | ' |
Net income | 45,209 | 66,195 | 92,533 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Depreciation, depletion, amortization and accretion | 108,583 | 84,962 | 87,099 |
Deferred income taxes | 19,398 | 4,128 | -14,882 |
Changes in operating assets and liabilities: | ' | ' | ' |
Oil and natural gas receivables | -4,262 | 3,415 | 9,070 |
Income taxes | 5,140 | 31,557 | 64,531 |
Prepaid expenses and other assets | -38,558 | -118,320 | -228,020 |
Asset retirement obligations settlements | -1,593 | -628 | ' |
Accounts payable and accrued liabilities | 717 | -2,504 | -514 |
Net cash provided by operating activities | 134,634 | 68,805 | 9,817 |
Investing activities: | ' | ' | ' |
Investment in oil and natural gas properties and equipment | -220,651 | -68,805 | -4,632 |
Net cash used in investing activities | -220,651 | -68,805 | -4,632 |
Financing activities: | ' | ' | ' |
Investment from parent | 86,017 | ' | -5,185 |
Net cash provided by financing activities | 86,017 | ' | -5,185 |
Eliminations | ' | ' | ' |
Operating activities: | ' | ' | ' |
Net income | -45,209 | -66,195 | -92,533 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Earnings of affiliates | 45,209 | 66,195 | 92,533 |
Changes in operating assets and liabilities: | ' | ' | ' |
Prepaid expenses and other assets | 34,120 | 118,318 | 228,214 |
Accounts payable and accrued liabilities | ' | ' | -194 |
Other | -34,120 | -118,318 | -228,020 |
Investing activities: | ' | ' | ' |
Investment in subsidiary | 86,017 | ' | -5,185 |
Net cash used in investing activities | 86,017 | ' | -5,185 |
Financing activities: | ' | ' | ' |
Investment from parent | -86,017 | ' | 5,185 |
Net cash provided by financing activities | -86,017 | ' | 5,185 |
Cash and cash equivalents, beginning of period | ' | ' | ' |
Cash and cash equivalents, end of period | ' | ' | ' |
Supplement_Guarantor_Informati
Supplement Guarantor Information - Additional Information (Detail) | Dec. 31, 2013 |
Debt Disclosure [Line Items] | ' |
Senior notes interest rate | 8.50% |
Capitalized_Costs_Related_to_O
Capitalized Costs Related to Oil and Natural Gas (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Millions, unless otherwise specified | |||
Net capitalized cost: | ' | ' | ' |
Proved oil and natural gas properties and equipment | $7,207.10 | $6,551.50 | $5,775.40 |
Unproved oil and natural gas properties and equipment | 132 | 143 | 183.6 |
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | -5,069.20 | -4,640.80 | -4,307.10 |
Net capitalized costs related to producing activities | $2,269.90 | $2,053.70 | $1,651.90 |
Capitalized_Costs_Not_Subject_
Capitalized Costs Not Subject to Amortization (Detail) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
Costs excluded by year incurred: | ' | ' | ' | ' |
Acquisition costs | $9.20 | $8.70 | $50.10 | $19.30 |
Capitalized interest not subject to amortization | 8.4 | 7.4 | 5.1 | 8.4 |
Total costs not subject to amortization | 17.6 | 16.1 | 55.2 | 27.7 |
Acquisition costs, Total | 87.3 | ' | ' | ' |
Capitalized interest not subject to amortization, Total | 29.3 | ' | ' | ' |
Total costs not subject to amortization, Total | $116.60 | ' | ' | ' |
Cost_Incurred_in_Oil_and_Gas_P
Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Costs incurred: | ' | ' | ' | |||
Proved property acquisitions | $96.90 | [1] | $239.80 | [1] | $369.90 | [1] |
Exploration | 215.3 | [1],[2],[3] | 151.3 | [1],[2],[3] | 92.7 | [1],[2],[3] |
Development | 352.9 | [1] | 363.7 | [1] | 203.7 | [1] |
Unproved property acquisitions | 26.3 | [1],[4] | 26.5 | [1],[4] | 95.1 | [1],[4] |
Total costs incurred in oil and gas property acquisition, exploration and development activities | $691.40 | [1] | $781.30 | [1] | $761.40 | [1] |
[1] | Includes net additions to our ARO of $50.6 million, $86.9 million and $32.8 million during 2013, 2012 and 2011, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5. | |||||
[2] | Includes seismic costs of $8.9 million, $6.2 million and $8.0 million incurred during 2013, 2012 and 2011, respectively. | |||||
[3] | Includes geological and geophysical costs charged to expense of $5.9 million, $6.2 million and $6.8 million during 2013, 2012 and 2011, respectively. | |||||
[4] | The amounts for unproved property acquisitions include capitalized interest associated with properties classified as unproved as of the end of the period. |
Cost_Incurred_in_Oil_and_Gas_P1
Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Parenthetical) (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Reserve Quantities [Line Items] | ' | ' | ' |
Additions (reductions) of asset retirement obligations | $50.60 | $86.90 | $32.80 |
Seismic costs | 8.9 | 6.2 | 8 |
Geological and geophysical costs | $5.90 | $6.20 | $6.80 |
Schedule_of_Depreciation_Deple
Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Detail) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Reserve Quantities [Line Items] | ' | ' | ' |
Depreciation, depletion, amortization and accretion per Mcfe | 4.18 | 3.47 | 3.24 |
Estimated_Quantities_of_Net_Pr
Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Detail) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
MMBbls | MMBbls | MMBbls | ||||
Oil | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, beginning balance | 54.8 | 51.4 | 34 | |||
Revisions of previous estimates | -4.3 | [1] | -1.1 | [2] | 0.8 | [3] |
Extensions and discoveries | 13.9 | [4] | 8.2 | [5] | 2 | [6] |
Purchase of minerals in place | 1.5 | [7] | 2.5 | [8] | 20.7 | [9] |
Production | -7 | -6 | -6.1 | |||
Proved reserves, ending balance | 58.5 | 54.8 | 51.4 | |||
Sales of reserves | -0.4 | [10] | -0.2 | [11] | ' | |
Oil | Proved Developed Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 36.2 | 35.3 | 23.4 | |||
Oil | Proved Undeveloped Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 22.3 | 19.5 | 28 | |||
NGLs | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, beginning balance | 15.2 | 17.1 | 4.2 | |||
Revisions of previous estimates | 0.2 | [1] | -2.6 | [2] | 5.5 | [3] |
Extensions and discoveries | 2.6 | [4] | 2.6 | [5] | 0.4 | [6] |
Purchase of minerals in place | ' | 0.2 | [8] | 8.9 | [9] | |
Production | -2.1 | -2.1 | -1.9 | |||
Proved reserves, ending balance | 15.9 | 15.2 | 17.1 | |||
Sales of reserves | ' | [10] | ' | [11] | ' | |
NGLs | Proved Developed Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 11.1 | 11 | 11 | |||
NGLs | Proved Undeveloped Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 4.8 | 4.2 | 6.1 | |||
Natural Gas | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, beginning balance | 285,100 | 289,700 | 256,300 | |||
Revisions of previous estimates | 2,100 | [1] | -4,800 | [2] | 13,500 | [3] |
Extensions and discoveries | 22,000 | [4] | 29,600 | [5] | 17,700 | [6] |
Purchase of minerals in place | 4,400 | [7] | 25,500 | [8] | 55,900 | [9] |
Production | -53,300 | -53,800 | -53,700 | |||
Proved reserves, ending balance | 259,900 | 285,100 | 289,700 | |||
Sales of reserves | -400 | [10] | -1,100 | [11] | ' | |
Natural Gas | Proved Developed Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 232,700 | 243,500 | 251,400 | |||
Natural Gas | Proved Undeveloped Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 27,200 | 41,600 | 38,300 | |||
Barrel Equivalent | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, beginning balance | 117.5 | [12] | 116.9 | [12] | 80.9 | [12] |
Revisions of previous estimates | -3.8 | [1],[12] | -4.6 | [12],[2] | 8.6 | [12],[3] |
Extensions and discoveries | 20.2 | [12],[4] | 15.7 | [12],[5] | 5.3 | [12],[6] |
Purchase of minerals in place | 2.3 | [12],[7] | 7 | [12],[8] | 39 | [12],[9] |
Production | -18 | [12] | -17.1 | [12] | -16.9 | [12] |
Proved reserves, ending balance | 117.7 | [12] | 117.5 | [12] | 116.9 | [12] |
Sales of reserves | -0.5 | [10],[12] | -0.4 | [11],[12] | ' | |
Barrel Equivalent | Proved Developed Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 86.1 | [12] | 86.9 | [12] | 76.4 | [12] |
Barrel Equivalent | Proved Undeveloped Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 31.6 | [12] | 30.6 | [12] | 40.5 | [12] |
Natural Gas Equivalent | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, beginning balance | 705,100,000 | [12] | 701,100,000 | [12] | 485,400,000 | [12] |
Revisions of previous estimates | -22,800,000 | [1],[12] | -27,500,000 | [12],[2] | 51,100,000 | [12],[3] |
Extensions and discoveries | 121,000,000 | [12],[4] | 94,500,000 | [12],[5] | 32,000,000 | [12],[6] |
Purchase of minerals in place | 13,700,000 | [12],[7] | 42,000,000 | [12],[8] | 234,100,000 | [12],[9] |
Production | -107,900,000 | [12] | -102,800,000 | [12] | -101,500,000 | [12] |
Proved reserves, ending balance | 705,900,000 | [12] | 705,100,000 | [12] | 701,100,000 | [12] |
Sales of reserves | -3,200,000 | [10],[12] | -2,200,000 | [11],[12] | ' | |
Natural Gas Equivalent | Proved Developed Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 516,100,000 | [12] | 521,200,000 | [12] | 458,200,000 | [12] |
Natural Gas Equivalent | Proved Undeveloped Reserves | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | |||
Proved reserves, ending balance | 189,800,000 | [12] | 183,900,000 | [12] | 242,900,000 | [12] |
[1] | Includes upward revision due to price of 11.3 Bcfe; negative revisions of 29.6 Bcfe at our Spraberry field for performance and technical changes, 13.9 Bcfe at our High Island 21/22 field for performance, 7.9 Bcfe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 4.3 Bcfe at our Main Pass 98 field, 4.0 Bcfe at our South Timbalier 314, 3.5 Bcfe at our Main Pass 108 field and 3.2 at our South Timbalier 176 field. | |||||
[2] | Includes downward revisions due to price of 8.0 Bcfe and negative performance revisions of 17.9 Bcfe at our Spraberry field. | |||||
[3] | Includes revision of 6.3 Bcfe due to an increase in average prices; 16.5 Bcfe for a change in NGLs marketing arrangements; 11.3 Bcfe increase due to additional compression at our Tahoe field that increases production and ultimate recoveries; and 10.6 Bcfe at our Fairway field for revisions to reserve estimates from the acquisition date to year end. | |||||
[4] | Includes extensions and discoveries of 75.4 Bcfe at our Spraberry field, 25.3 Bcfe at our Ship Shoal 349/359 field and 11.5 Bcfe at our Mississippi Canyon 698 field. | |||||
[5] | Includes extensions and discoveries of 69.5 Bcfe at our Spraberry field and extensions and discoveries of 16.2 Bcfe at our High Island 21/22 field | |||||
[6] | Includes discoveries of 13.9 Bcfe at our Main Pass 98 field and 8.0 Bcfe at our Ship Shoal 349/359 field and extensions of 3.7 Bcfe at our Main Pass 108 field. | |||||
[7] | Primarily due to the acquisition of the Callon Properties. | |||||
[8] | Due to the acquisition of the Newfield Properties | |||||
[9] | Primarily due to the acquisition of the Opal Properties and the Fairway 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] | 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. |
Estimated_Quantities_of_Net_Pr1
Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Parenthetical) (Detail) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | |
Changes due to price | Changes due to price | Changes due to marketing arrangement | Changes at Tahoe field for compressor project | Changes at the Fairway field | Changes at the Main Pass 98 field | Changes at the Ship Shoal 349/359 field | Changes at the Ship Shoal 349/359 field | Changes at the Main Pass 108 field | Changes at the Spraberry field | Changes at the Spraberry field | Changes at the High Island 22 field | Changes due to price | Changes at the High Island 22 field | Changes at the Main Pass 98 field | Changes at the South Timbalier 314 field | Changes at the Main Pass 108 field | Changes at the South Timbalier 176 field | Changes at the Mississippi Canyon 698 field | |
Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | |
Reserve Quantities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revisions of previous estimates | -8,000,000 | 6,300,000 | 16,500,000 | 11,300,000 | 10,600,000 | ' | -7,900,000 | ' | ' | -29,600,000 | -17,900,000 | ' | 11,300,000 | -13,900,000 | 4,300,000 | 4,000,000 | 3,500,000 | 3,200,000 | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | 13,900,000 | 25,300,000 | 8,000,000 | 3,700,000 | 75,400,000 | 69,500,000 | 16,200,000 | ' | ' | ' | ' | ' | ' | 11,500,000 |
Schedule_of_Prices_Weighted_by
Schedule of Prices Weighted by Field Production Related to Proved Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | |
Oil | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Weighted price | 99.65 | 98.13 | 97.36 | 76.28 |
NGLs | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Weighted price | 35.21 | 47.3 | 51.3 | 44.92 |
Natural Gas | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Weighted price | 3.8 | 2.77 | 4.11 | 4.57 |
Standardized_Measure_of_Discou
Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Standardized Measure of Discounted Future Net Cash Flows | ' | ' | ' |
Future cash inflows | $7,376.70 | $6,888.40 | $7,077.20 |
Production | -2,142.80 | -1,858.30 | -1,862.50 |
Development | -1,001.40 | -655.4 | -543 |
Dismantlement and abandonment | -441.6 | -508 | -513.6 |
Income taxes | -986.9 | -1,002.10 | -1,126.60 |
Future net cash inflows before 10% discount | 2,804 | 2,864.60 | 3,031.50 |
10% annual discount factor | -1,129.40 | -1,018.20 | -1,025.10 |
Standardized measure of discounted future net cash flows | $1,674.60 | $1,846.40 | $2,006.40 |
Schedule_of_Changes_in_Standar
Schedule of Changes in Standardized Measure (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Reserve Quantities [Line Items] | ' | ' | ' |
Changes in Standardized Measure Standardized measure, beginning of year | $1,846.40 | $2,006.40 | $1,179.10 |
Sales and transfers of oil and gas produced, net of production costs | -686.1 | -620.4 | -729.6 |
Net changes in price, net of future production costs | -65.2 | -224.3 | 634.2 |
Extensions and discoveries, net of future production and development costs | 393.8 | 181.9 | 219.9 |
Changes in estimated future development costs | -91.1 | -103.3 | -4.6 |
Previously estimated development costs incurred | 262.1 | 332.9 | 173.9 |
Revisions of quantity estimates | -91.6 | -128.1 | 205 |
Accretion of discount | 202.2 | 231.1 | 135.8 |
Net change in income taxes | 56.6 | 99.7 | -398.2 |
Purchases of reserves in-place | 79.6 | 270.2 | 483.3 |
Sales of reserves in-place | -53.1 | -16.1 | ' |
Changes in production rates due to timing and other | -179 | -183.6 | 107.6 |
Net increase (decrease) in standardized measure | -171.8 | -160 | 827.3 |
Changes in Standardized measure, end of year | $1,674.60 | $1,846.40 | $2,006.40 |
Supplemental_Oil_and_Gas_Discl2
Supplemental Oil and Gas Disclosures - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2013 | |
Reserve Quantities [Line Items] | ' |
Percentage non-operated non-producing reserves | 9.00% |
Present value discounted percentage | 10.00% |
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 |