Document_and_Entity_Informatio
Document and Entity Information Document Document (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Feb. 07, 2014 | Jun. 30, 2013 | |
Entity Information [Line Items] | ' | ' | ' |
Entity Registrant Name | 'PDC ENERGY, INC. | ' | ' |
Entity Central Index Key | '0000077877 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' |
Document Type | '10-K | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Amendment Flag | 'false | ' | ' |
Entity Common Stock, Shares Outstanding | ' | 35,754,597 | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Public Float | ' | ' | $1,549,265,066 |
Consolidated_Balance_Sheets_Au
Consolidated Balance Sheets (Audited) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets: | ' | ' |
Cash and cash equivalents | $193,243 | $2,457 |
Restricted cash | 2,214 | 3,942 |
Accounts receivable, net | 94,085 | 64,880 |
Accounts receivable affiliates | 6,614 | 4,842 |
Fair value of derivatives | 2,572 | 52,042 |
Deferred income taxes | 22,374 | 36,151 |
Prepaid expenses and other current assets | 4,711 | 7,635 |
Total current assets | 325,813 | 171,949 |
Properties and equipment, net | 1,653,445 | 1,616,706 |
Assets held for sale | 2,785 | 0 |
Fair value of derivatives | 5,601 | 6,883 |
Other assets | 37,559 | 31,310 |
Total Assets | 2,025,203 | 1,826,848 |
Current liabilities: | ' | ' |
Accounts payable | 109,555 | 82,716 |
Accounts payable affiliates | 41 | 5,296 |
Production tax liability | 23,421 | 25,899 |
Fair value of derivatives | 15,515 | 18,439 |
Funds held for distribution | 32,578 | 34,228 |
Accrued interest payable | 9,251 | 11,056 |
Other accrued expenses | 23,059 | 25,715 |
Total current liabilities | 213,420 | 203,349 |
Long-term debt | 656,990 | 676,579 |
Deferred income taxes | 118,767 | 148,427 |
Asset retirement obligations | 37,811 | 61,563 |
Fair value of derivatives | 3,015 | 10,137 |
Liabilities held for sale | 2,061 | 0 |
Other liabilities | 25,545 | 23,612 |
Total liabilities | 1,057,609 | 1,123,667 |
Shareholders' Equity: | ' | ' |
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized,none issued | 0 | 0 |
Common shares - par value $0.01 per share, 100,000,000 authorized, 35,675,656 and 30,294,224 issued as of December 31, 2013 and 2012, respectively | 357 | 303 |
Additional paid-in capital | 674,211 | 387,494 |
Retained earnings | 293,267 | 315,568 |
Treasury shares - at cost, 5,508 and 5,059 as of December 31, 2013 and 2012, respectively | -241 | -184 |
Total shareholders' equity | 967,594 | 703,181 |
Total Liabilities and Shareholders' Equity | $2,025,203 | $1,826,848 |
Balance_Sheet_Parentheticals_P
Balance Sheet Parentheticals (Parentheticals) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Balance Sheet Parentheticals [Abstract] | ' | ' |
Common Stock, Par or Stated Value Per Share | $0.01 | $0.01 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 35,675,656 | 30,294,224 |
Preferred Stock, Par or Stated Value Per Share | $0.01 | $0.01 |
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Treasury Stock, Shares | 5,508 | 5,059 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (Audited) (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: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Natural gas, NGL and crude oil sales | $120,286 | $82,136 | $77,537 | $79,439 | $67,773 | $52,291 | $51,342 | $66,955 | $359,398 | $238,361 | $223,297 |
Sales from natural gas marketing | 21,092 | 16,946 | 18,079 | 13,670 | 14,199 | 11,178 | 8,613 | 11,381 | 69,787 | 45,371 | 63,470 |
Commodity price risk management gain (loss), net | -2,636 | -23,638 | 24,724 | -22,355 | 14,052 | -31,943 | 38,729 | 11,501 | -23,905 | 32,339 | 46,090 |
Well operations, pipeline income and other | 2,325 | 1,672 | 965 | 1,072 | 1,115 | 1,194 | 1,056 | 1,169 | 6,034 | 4,534 | 4,432 |
Total revenues | 141,067 | 77,116 | 121,305 | 71,826 | 97,139 | 32,720 | 99,740 | 91,006 | 411,314 | 320,605 | 337,289 |
Costs, expenses and other: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Production costs | 22,299 | 19,057 | 16,176 | 15,858 | 13,594 | 15,797 | 12,373 | 12,936 | 73,390 | 54,700 | 44,832 |
Cost of natural gas marketing | 21,156 | 17,127 | 18,065 | 13,736 | 14,182 | 11,260 | 8,490 | 11,091 | 70,084 | 45,023 | 62,831 |
Exploration expense | 1,883 | 2,030 | 1,437 | 1,689 | 14,875 | 1,773 | 2,374 | 1,872 | 7,039 | 20,894 | 5,734 |
Impairment of natural gas and crude oil properties | 1,002 | 4,472 | 1,502 | 46,459 | 4,563 | 388 | 356 | 588 | 53,435 | 5,895 | 2,301 |
General and administrative expense | 16,991 | 16,080 | 15,783 | 15,115 | 16,019 | 13,710 | 14,378 | 14,708 | 63,969 | 58,815 | 61,454 |
Depreciation, depletion and amortization | 40,641 | 30,870 | 27,800 | 27,949 | 24,906 | 22,121 | 23,839 | 27,912 | 127,260 | 98,778 | 87,633 |
Accretion of asset retirement obligations | 1,080 | 1,186 | 1,172 | 1,148 | 1,127 | 1,101 | 732 | 727 | 4,586 | 3,687 | 1,398 |
Gain on sale of Leaseholds | 2,151 | -712 | -9 | -38 | -445 | -1,508 | -2,246 | -154 | 1,392 | -4,353 | -196 |
Total cost, expenses and other | 107,203 | 90,110 | 81,926 | 121,916 | 88,821 | 64,642 | 60,296 | 69,680 | 401,155 | 283,439 | 265,987 |
Income (loss) from operations | 33,864 | -12,994 | 39,379 | -50,090 | 8,318 | -31,922 | 39,444 | 21,326 | 10,159 | 37,166 | 71,302 |
Loss on extinguishment of debt | ' | ' | ' | ' | -23,283 | 0 | 0 | 0 | 0 | -23,283 | 0 |
Interest expense | -12,943 | -12,509 | -13,089 | -13,357 | -16,430 | -11,360 | -10,053 | -10,444 | -51,898 | -48,287 | -36,985 |
Interest income | 337 | 130 | 3 | 0 | 3 | 3 | 0 | 2 | 470 | 8 | 47 |
Income (loss) from continuing operations before income taxes | 21,258 | -25,373 | 26,293 | -63,447 | -31,392 | -43,279 | 29,391 | 10,884 | -41,269 | -34,396 | 34,364 |
Provision for income taxes | -8,059 | 10,155 | -9,791 | 22,492 | 11,766 | 15,268 | -10,213 | -4,120 | 14,797 | 12,701 | -11,800 |
Income (loss) from continuing operations | 13,199 | -15,218 | 16,502 | -40,955 | -19,626 | -28,011 | 19,178 | 6,764 | -26,472 | -21,695 | 22,564 |
Income (loss) from discontinued operations, net of tax | 0 | -782 | 3,416 | 1,537 | -106,549 | -4,632 | -6,907 | 9,071 | 4,171 | -109,017 | -9,127 |
Net income (loss) | $13,199 | ($16,000) | $19,918 | ($39,418) | ($126,175) | ($32,643) | $12,271 | $15,835 | ($22,301) | ($130,712) | $13,437 |
Basic | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income (loss) from continuing operations | $0.37 | ($0.46) | $0.55 | ($1.35) | ($0.65) | ($0.93) | $0.72 | $0.29 | ($0.82) | ($0.78) | $0.96 |
Income (loss) from discontinued operations | $0 | ($0.02) | $0.11 | $0.05 | ($3.52) | ($0.15) | ($0.26) | $0.38 | $0.13 | ($3.94) | ($0.39) |
Net income (loss) attributable to shareholders | $0.37 | ($0.48) | $0.66 | ($1.30) | ($4.17) | ($1.08) | $0.46 | $0.67 | ($0.69) | ($4.72) | $0.57 |
Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income (loss) from continuing operations | $0.36 | ($0.46) | $0.53 | ($1.35) | ($0.65) | ($0.93) | $0.72 | $0.28 | ($0.82) | ($0.78) | $0.95 |
Income (loss) from discontinued operations | $0 | ($0.02) | $0.11 | $0.05 | ($3.52) | ($0.15) | ($0.26) | $0.38 | $0.13 | ($3.94) | ($0.39) |
Net income (loss) attributable to shareholders | $0.36 | ($0.48) | $0.64 | ($1.30) | ($4.17) | ($1.08) | $0.46 | $0.66 | ($0.69) | ($4.72) | $0.56 |
Weighted-average common shares outstanding: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basic | 35,620 | 33,413 | 30,332 | 30,270 | 30,233 | 30,214 | 26,597 | 23,609 | 32,426 | 27,677 | 23,521 |
Diluted | 36,836 | 33,413 | 31,014 | 30,270 | 30,233 | 30,214 | 26,728 | 23,889 | 32,426 | 27,677 | 23,871 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Audited) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Cash flows from operating activities: | ($22,301) | ($130,712) | $13,437 |
Net income (loss) | -22,301 | -130,712 | 13,437 |
Adjustments to net income (loss) to reconcile to net cash provided by operating activities: | ' | ' | ' |
Net change in fair value of unsettled derivatives | 36,801 | 17,134 | -28,601 |
Depreciation, depletion and amortization | 129,518 | 146,879 | 135,154 |
Impairment of natural gas and crude oil properties | 53,438 | 168,149 | 25,159 |
Prepaid well write-offs | 74 | 3,916 | 1,359 |
Loss on extinguishment of debt | 0 | 23,283 | 0 |
Exploratory dry hole costs | 0 | 15,347 | 177 |
Accretion of asset retirement obligation | 4,747 | 4,060 | 1,897 |
Stock-based compensation | 12,880 | 8,495 | 8,781 |
Excess tax benefits from stock-based compensation | -2,489 | 0 | -1,311 |
(Gain) loss from sale of properties and equipment | -3,722 | 24,273 | 4,263 |
Amortization of debt discount and issuance costs | 6,783 | 7,864 | 6,265 |
Deferred income taxes | -15,883 | -80,379 | 9,530 |
Inventory adjustment and other | 460 | 4,123 | 135 |
Total adjustments to net income (loss) to reconcile to net cash provided by operating activities: | 230,051 | 294,598 | 154,282 |
Changes in current assets and liabilities: | ' | ' | ' |
Accounts receivable | -41,509 | 6,843 | -3,451 |
Other assets | 3,461 | -2,908 | -3,893 |
Restricted cash | -8 | 8,859 | -8,603 |
Production tax liability | 4,121 | 2,499 | 5,436 |
Accounts payable and accrued expenses | -11,485 | -5,050 | 12,422 |
Other liabilities | -3,165 | 592 | -2,796 |
Total changes in current assets and liabilities | -48,585 | 10,835 | -885 |
Net cash provided by operating activities | 159,165 | 174,721 | 166,834 |
Cash flows from investing activities: | ' | ' | ' |
Capital expenditures | -394,948 | -347,729 | -334,496 |
Acquisition of natural gas and crude oil properties, net of cash acquired | -9,658 | -312,223 | -145,894 |
Proceeds from acquisition adjustments | 7,579 | 14,469 | 0 |
Proceeds from sale of properties and equipment | 179,919 | 193,544 | 23,140 |
Other | 0 | 0 | 849 |
Net cash used in investing activities | -217,108 | -451,939 | -456,401 |
Cash flows from financing activities: | ' | ' | ' |
Proceeds from credit facility | 260,250 | 682,000 | 417,194 |
Payment of credit facility | 283,500 | 839,750 | 183,713 |
Proceeds from senior notes | 0 | 500,000 | 0 |
Repurchase of senior notes | 0 | -221,840 | 0 |
Payment of debt issuance costs | -2,352 | -11,969 | -680 |
Proceeds from sale of equity, net of issuance costs | 275,847 | 164,496 | 0 |
Excess tax benefits from stock-based compensation | 2,489 | 0 | 1,311 |
Contribution by investing partner in PDCM | 0 | 0 | 12,464 |
Purchase of treasury stock | -4,133 | -1,500 | -3,143 |
Proceeds from exercise of stock options | 128 | 0 | 0 |
Net cash provided by (used in) financing activities | 248,729 | 271,437 | 243,433 |
Net increase (decrease) in cash and cash equivalents | 190,786 | -5,781 | -46,134 |
Cash and cash equivalents, beginning of period | 2,457 | 8,238 | 54,372 |
Cash and cash equivalents, end of period | 193,243 | 2,457 | 8,238 |
Cash payments (receipts) for: | ' | ' | ' |
Interest, net of capitalized interest | 48,844 | 41,768 | 29,429 |
Income taxes | -3,014 | 1,845 | -1,498 |
Non-cash investing activities: | ' | ' | ' |
Change in accounts payable related to purchases of properties and equipment | 33,328 | 288 | 23,837 |
Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals | 2,112 | 11,967 | 17,538 |
Change in accounts receivable related to disposition of properties and equipment | 808 | 0 | 0 |
Change in other assets related to disposition of properties and equipment | $3,350 | $0 | $0 |
Consolidated_Statement_of_Equi
Consolidated Statement of Equity (Statement) (USD $) | Total | Parent [Member] | Preferred Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Treasury Stock [Member] | Noncontrolling Interest [Member] |
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2010 | ' | ' | ' | $235,000 | $209,198,000 | $432,843,000 | ($111,000) | $76,000 |
Shares issued pursuant to sale of equity | ' | ' | ' | 0 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | 2,814 | ' | ' | ' | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 242,334 | ' | ' | ' | ' |
Retirement of treasury shares | ' | ' | ' | -72,516 | ' | ' | -72,516 | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | 87,588 | ' |
Issuance of treasury shares | ' | ' | ' | ' | ' | ' | -15,072 | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | 0 | ' |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued pursuant to sale of equity | ' | ' | ' | 0 | 0 | ' | ' | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | -3,143,000 | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 1,000 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | ' | 0 | ' | ' | ' |
Share-based Compensation expense | 8,781,000 | ' | ' | ' | 8,781,000 | ' | ' | ' |
Issuance of treasury shares | ' | ' | ' | ' | -472,000 | ' | 472,000 | ' |
Retirement of treasury shares | ' | ' | ' | ' | -2,671,000 | ' | 2,671,000 | ' |
Tax benefit (detriment) of stock-based compensation | ' | ' | ' | ' | 785,000 | ' | ' | ' |
Contribution by investing partner in PDCM | 12,464,000 | ' | ' | ' | 12,464,000 | ' | ' | ' |
Effect of PDCM deconsolidation/change in ownership interest | ' | ' | ' | ' | -10,378,000 | ' | ' | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | 0 | ' |
Net income (Loss) attributable to shareholders | ' | ' | ' | ' | ' | 13,437,000 | ' | ' |
Net loss attributed to noncontrolling interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | -76,000 |
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011 | 664,112,000 | 664,112,000 | 0 | 236,000 | 217,707,000 | 446,280,000 | -111,000 | 0 |
Shares, Issued at Dec. 31, 2011 | ' | ' | ' | 23,634,958 | ' | ' | 2,938 | ' |
Shares end of year at Dec. 31, 2011 | ' | ' | ' | 23,632,020 | ' | ' | ' | ' |
Shares issued pursuant to sale of equity | ' | ' | ' | 6,500,000 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | 0 | ' | ' | ' | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 173,737 | ' | ' | ' | ' |
Retirement of treasury shares | ' | ' | ' | -14,471 | ' | ' | -14,471 | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | 44,576 | ' |
Issuance of treasury shares | ' | ' | ' | ' | ' | ' | -28,587 | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | 603 | ' |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued pursuant to sale of equity | ' | ' | ' | 65,000 | 164,431,000 | ' | ' | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | -1,500,000 | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 2,000 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | ' | 0 | ' | ' | ' |
Share-based Compensation expense | 8,495,000 | ' | ' | ' | 8,495,000 | ' | ' | ' |
Issuance of treasury shares | ' | ' | ' | ' | -955,000 | ' | 955,000 | ' |
Retirement of treasury shares | ' | ' | ' | ' | -491,000 | ' | 491,000 | ' |
Tax benefit (detriment) of stock-based compensation | ' | ' | ' | ' | -1,693,000 | ' | ' | ' |
Contribution by investing partner in PDCM | 0 | ' | ' | ' | 0 | ' | ' | ' |
Effect of PDCM deconsolidation/change in ownership interest | ' | ' | ' | ' | 0 | ' | ' | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | -19,000 | ' |
Net income (Loss) attributable to shareholders | ' | ' | ' | ' | ' | -130,712,000 | ' | ' |
Net loss attributed to noncontrolling interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | 0 |
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012 | 703,181,000 | 703,181,000 | 0 | 303,000 | 387,494,000 | 315,568,000 | -184,000 | 0 |
Shares, Issued at Dec. 31, 2012 | ' | ' | ' | 30,294,224 | ' | ' | 5,059 | ' |
Shares end of year at Dec. 31, 2012 | ' | ' | ' | 30,289,165 | ' | ' | ' | ' |
Shares issued pursuant to sale of equity | ' | ' | ' | 5,175,000 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | 10,763 | ' | ' | ' | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 212,926 | ' | ' | ' | ' |
Retirement of treasury shares | ' | ' | ' | -17,257 | ' | ' | -17,257 | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | 84,642 | ' |
Issuance of treasury shares | ' | ' | ' | ' | ' | ' | -67,334 | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | 398 | ' |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' |
Shares issued pursuant to sale of equity | ' | ' | ' | 52,000 | 275,795,000 | ' | ' | ' |
Purchase of treasury shares | ' | ' | ' | ' | ' | ' | -4,133,000 | ' |
Issuance of stock awards, net of forfeitures | ' | ' | ' | 2,000 | ' | ' | ' | ' |
Exercise of stock options | ' | ' | ' | ' | 125,000 | ' | ' | ' |
Share-based Compensation expense | 12,880,000 | ' | ' | ' | 12,402,000 | ' | ' | ' |
Issuance of treasury shares | ' | ' | ' | ' | -3,270,000 | ' | 3,271,000 | ' |
Retirement of treasury shares | ' | ' | ' | ' | -824,000 | ' | 824,000 | ' |
Tax benefit (detriment) of stock-based compensation | ' | ' | ' | ' | 2,489,000 | ' | ' | ' |
Contribution by investing partner in PDCM | 0 | ' | ' | ' | 0 | ' | ' | ' |
Effect of PDCM deconsolidation/change in ownership interest | ' | ' | ' | ' | 0 | ' | ' | ' |
Non-employee directors' deferred compensation plan | ' | ' | ' | ' | ' | ' | -19,000 | ' |
Net income (Loss) attributable to shareholders | ' | ' | ' | ' | ' | -22,301,000 | ' | ' |
Net loss attributed to noncontrolling interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | 0 |
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2013 | $967,594,000 | $967,594,000 | $0 | $357,000 | $674,211,000 | $293,267,000 | ($241,000) | $0 |
Shares, Issued at Dec. 31, 2013 | ' | ' | ' | 35,675,656 | ' | ' | 5,508 | ' |
Shares end of year at Dec. 31, 2013 | ' | ' | ' | 35,670,148 | ' | ' | ' | ' |
NATURE_OF_OPERATIONS_AND_BASIS
NATURE OF OPERATIONS AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2013 | |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract] | ' |
Nature of Operations [Text Block] | ' |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION | |
PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, acquires, and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and the Appalachia-Marcellus Shale in northern West Virginia. Our operations in the Wattenberg Field are focused on the liquid-rich horizontal Niobrara and Codell plays. We are currently focusing our Ohio development in the liquid-rich portion of the Utica Shale play and are pursuing horizontal development of the Marcellus Shale in West Virginia. As of December 31, 2013, we owned an interest in approximately 3,100 gross wells. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. | |
The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries and our proportionate share of PDC Mountaineer, LLC and our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. | |
The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments and valuation of deferred income tax assets. | |
Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. |
RECENT_ACCOUNTING_STANDARDS
RECENT ACCOUNTING STANDARDS | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Significant Accounting Policies [Text Block] | ' | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. | ||
Restricted Cash. We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2013, we had collateral in the form of certificates of deposit and cash totaling $3.3 million which consisted of $2.2 million and $1.1 million included in restricted cash and other assets, respectively. As of December 31, 2012, we had collateral in the form of certificates of deposit and cash totaling $5.3 million which consisted of $3.9 million and $1.4 million included in restricted cash and other assets, respectively. | ||
Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. As of December 31, 2013 and 2012, inventory of $0.9 million and $1.2 million, respectively, is included in prepaid expenses and other current assets on the consolidated balance sheets. | ||
Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. | ||
All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the consolidated balance sheets in accounts receivable affiliates and accounts payable affiliates. As positions designated to our affiliated partnerships mature, the cash settlements are netted for distribution. Net settlements are paid to the partnerships or deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. As of December 31, 2013, our affiliated partnerships had no outstanding derivative instruments. | ||
The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2013 and 2012, respectively. | ||
Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. | ||
Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly DD&A expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. | ||
Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment, for disclosure related to changes in our capitalized exploratory well costs. | ||
Proved Property Impairment. Upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statement of operations line item impairment of crude oil and natural gas properties, with a corresponding impact on accumulated DD&A on the consolidated balance sheet. | ||
Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statement of operations line item impairment of crude oil and natural gas properties. | ||
Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment to other property and equipment was recognized in 2013, 2012 or 2011. | ||
The following table presents the estimated useful lives of our other property and equipment: | ||
Pipelines and related facilities | 10 - 17 years | |
Transportation and other equipment | 3 - 20 years | |
Buildings | 20 - 30 years | |
Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $5.1 million, $4.7 million and $4 million in 2013, 2012 and 2011, respectively. | ||
Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $1.9 million, $1.2 million and $1.7 million in 2013, 2012 and 2011, respectively. | ||
Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. | ||
Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $22.1 million and $18.7 million in December 31, 2013 and 2012, respectively. | ||
Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2013 and 2012, we had no valuation allowance. | ||
Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2013 and 2012, included in other assets was $16.6 million and $17.4 million, respectively, related to debt issuance costs. The December 31, 2013 amount included $1.3 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $9.8 million related to our 7.75% senior notes due 2022 and $5.5 million related to our revolving credit facility and the PDCM credit facility. The December 31, 2012 amount included $1.9 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $10.9 million related to our 7.75% senior notes due 2022 and $4.6 million related to our revolving credit facility and the PDCM credit facility. | ||
Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations, for a reconciliation of the changes in our asset retirement obligation. | ||
Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. | ||
Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. | ||
Crude oil, natural gas and NGLs sales. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in the Wattenberg Field are sold on a long-term basis, primarily over the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under short-term contracts of less than one year. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas. | ||
Well operations and pipeline income. We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. | ||
Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. | ||
Accounting for Acquisitions. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. | ||
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. | ||
We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. | ||
Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statement of operations. No amounts for stock-based compensation were capitalized in 2013, 2012 and 2011. | ||
Recent Accounting Standards. | ||
Recently Adopted Accounting Standard. On January 1, 2013, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on the entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the consolidated financial statements, except for additional disclosures. | ||
Recently Issued Accounting Standard. On July 18, 2013, the FASB issued an update to accounting for income taxes. The update provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The update is effective for public entities for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. We are currently evaluating the impact of adopting this update on our financial statements, but do not believe it will have a material impact. |
FAIR_VALUE_MEASUREMENTS_AND_DI
FAIR VALUE MEASUREMENTS AND DISCLOSURES | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Text Block] | ' | |||||||||||||||||||||||
FAIR VALUE OF FINANCIAL INSTRUMENTS | ||||||||||||||||||||||||
Derivative Financial Instruments | ||||||||||||||||||||||||
Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: | ||||||||||||||||||||||||
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. | ||||||||||||||||||||||||
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. | ||||||||||||||||||||||||
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. | ||||||||||||||||||||||||
Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. | ||||||||||||||||||||||||
We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. | ||||||||||||||||||||||||
Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our crude oil and natural gas collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: | ||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||
Significant Other | Significant | Total | Significant Other | Significant | Total | |||||||||||||||||||
Observable | Unobservable | Observable | Unobservable | |||||||||||||||||||||
Inputs | Inputs | Inputs | Inputs | |||||||||||||||||||||
(Level 2) | (Level 3) | (Level 2) | (Level 3) | |||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Commodity-based derivative contracts | $ | 5,325 | $ | 2,385 | $ | 7,710 | $ | 42,798 | $ | 15,750 | $ | 58,548 | ||||||||||||
Basis protection derivative contracts | 463 | — | 463 | 377 | — | 377 | ||||||||||||||||||
Total assets | 5,788 | 2,385 | 8,173 | 43,175 | 15,750 | 58,925 | ||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Commodity-based derivative contracts | 17,537 | 988 | 18,525 | 9,839 | 2,081 | 11,920 | ||||||||||||||||||
Basis protection derivative contracts | 5 | — | 5 | 16,656 | — | 16,656 | ||||||||||||||||||
Total liabilities | 17,542 | 988 | 18,530 | 26,495 | 2,081 | 28,576 | ||||||||||||||||||
Net asset (liability) | $ | (11,754 | ) | $ | 1,397 | $ | (10,357 | ) | $ | 16,680 | $ | 13,669 | $ | 30,349 | ||||||||||
The following table presents a reconciliation of our Level 3 assets measured at fair value: | ||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Fair value, net asset, beginning of period | $ | 13,669 | $ | 22,107 | $ | 10,762 | ||||||||||||||||||
Changes in fair value included in statement of operations line item: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | (1,521 | ) | 7,576 | 13,487 | ||||||||||||||||||||
Sales from natural gas marketing | 13 | 63 | 114 | |||||||||||||||||||||
Changes in fair value included in balance sheet line item (1): | ||||||||||||||||||||||||
Accounts receivable affiliates | — | — | 49 | |||||||||||||||||||||
Accounts payable affiliates | — | (319 | ) | (454 | ) | |||||||||||||||||||
Settlements included in statement of operations line items: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | (6,361 | ) | (15,644 | ) | (1,712 | ) | ||||||||||||||||||
Sales from natural gas marketing | (37 | ) | (114 | ) | (139 | ) | ||||||||||||||||||
Income (loss) from discontinued operations, net of tax | (4,366 | ) | — | — | ||||||||||||||||||||
Fair value, net asset end of period | $ | 1,397 | $ | 13,669 | $ | 22,107 | ||||||||||||||||||
Net change in fair value of unsettled derivatives included in statement of operations line item: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | $ | (1,032 | ) | $ | 3,665 | $ | 11,669 | |||||||||||||||||
Sales from natural gas marketing | 4 | 1 | (3 | ) | ||||||||||||||||||||
Total | $ | (1,028 | ) | $ | 3,666 | $ | 11,666 | |||||||||||||||||
__________ | ||||||||||||||||||||||||
-1 | Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. | |||||||||||||||||||||||
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. | ||||||||||||||||||||||||
Non-Derivative Financial Assets and Liabilities | ||||||||||||||||||||||||
The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. | ||||||||||||||||||||||||
The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. | ||||||||||||||||||||||||
The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2013, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $165.4 million, or 143.9% of par value, and the portion related to our 7.75% senior notes due 2022 to be $543.1 million, or 108.6% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. | ||||||||||||||||||||||||
See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. |
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Text Block] | ' | ||||||||||||
DERIVATIVE FINANCIAL INSTRUMENTS | |||||||||||||
Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. | |||||||||||||
• | For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and | ||||||||||||
• | For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. | ||||||||||||
We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2013, we had derivative instruments in place for a portion of our anticipated production through 2017 for a total of 59,971 BBtu of natural gas and 8,613 MBbls of crude oil. | |||||||||||||
As of December 31, 2013, our derivative instruments were comprised of commodity swaps, collars, basis protection swaps and physical sales and purchases. | |||||||||||||
• | Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; | ||||||||||||
• | Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; | ||||||||||||
• | Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps and TCO-basis protection swaps, which currently have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and | ||||||||||||
• | Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. | ||||||||||||
The following table presents the location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2013 and 2012: | |||||||||||||
Derivatives instruments: | Balance sheet line item | 2013 | 2012 | ||||||||||
(in thousands) | |||||||||||||
Derivative assets: | Current | ||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 2,016 | $ | 46,657 | ||||||||
Related to affiliated partnerships (1) | Fair value of derivatives | — | 4,707 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 361 | 319 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 195 | 359 | ||||||||||
2,572 | 52,042 | ||||||||||||
Non Current | |||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 5,055 | 6,653 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 278 | 212 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 268 | 18 | ||||||||||
5,601 | 6,883 | ||||||||||||
Total derivative assets | $ | 8,173 | $ | 58,925 | |||||||||
Derivative liabilities: | Current | ||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 15,263 | $ | 1,698 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 247 | 226 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | — | 14,375 | ||||||||||
Related to affiliated partnerships (2) | Fair value of derivatives | — | 2,140 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 5 | — | ||||||||||
15,515 | 18,439 | ||||||||||||
Non Current | |||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 2,782 | 9,828 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 233 | 168 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | — | 141 | ||||||||||
3,015 | 10,137 | ||||||||||||
Total derivative liabilities | $ | 18,530 | $ | 28,576 | |||||||||
__________ | |||||||||||||
-1 | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. | ||||||||||||
-2 | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. | ||||||||||||
The following table presents the impact of our derivative instruments on our consolidated statements of operations: | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statement of operations line item | 2013 | 2012 | 2011 | ||||||||||
Commodity price risk management gain (loss), net | |||||||||||||
Net settlements | $ | 12,913 | $ | 49,416 | $ | 17,243 | |||||||
Net change in fair value of unsettled derivatives | (36,818 | ) | (17,077 | ) | 28,847 | ||||||||
Total commodity price risk management gain (loss), net | $ | (23,905 | ) | $ | 32,339 | $ | 46,090 | ||||||
Sales from natural gas marketing | |||||||||||||
Net settlements | $ | 446 | $ | 2,170 | $ | 2,970 | |||||||
Net change in fair value of unsettled derivatives | 429 | (1,658 | ) | (161 | ) | ||||||||
Total sales from natural gas marketing | $ | 875 | $ | 512 | $ | 2,809 | |||||||
Cost of natural gas marketing | |||||||||||||
Net settlements | $ | (257 | ) | $ | (2,029 | ) | $ | (2,571 | ) | ||||
Net change in fair value of unsettled derivatives | (412 | ) | 1,601 | (85 | ) | ||||||||
Total cost of natural gas marketing | $ | (669 | ) | $ | (428 | ) | $ | (2,656 | ) | ||||
All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. | |||||||||||||
The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of December 31, 2013 and 2012: | |||||||||||||
As of December 31, 2013 | Derivatives instruments, recorded in consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | ||||||||||
(in thousands) | |||||||||||||
Asset derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 8,173 | $ | (5,623 | ) | $ | 2,550 | ||||||
Liability derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 18,530 | $ | (5,623 | ) | $ | 12,907 | ||||||
As of December 31, 2012 | Derivatives instruments, recorded in consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | ||||||||||
(in thousands) | |||||||||||||
Asset derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 58,925 | $ | (11,437 | ) | $ | 47,488 | ||||||
Liability derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 28,576 | $ | (11,437 | ) | $ | 17,139 | ||||||
CONCENTRATION_OF_RISK
CONCENTRATION OF RISK | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Concentration Risks, Types, No Concentration Percentage [Abstract] | ' | |||||||||
Concentration Risk Disclosure [Text Block] | ' | |||||||||
CONCENTRATION OF RISK | ||||||||||
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: | ||||||||||
As of December 31, | ||||||||||
2013 | 2012 | |||||||||
(in thousands) | ||||||||||
Crude oil, natural gas and NGLs sales | $ | 66,257 | $ | 39,837 | ||||||
Joint interest billings | 20,558 | 6,896 | ||||||||
Natural gas marketing | 6,210 | 8,209 | ||||||||
Reimbursements for title defects | — | 7,579 | ||||||||
Other | 2,321 | 3,385 | ||||||||
Allowance for doubtful accounts | (1,261 | ) | (1,026 | ) | ||||||
Accounts receivable, net | $ | 94,085 | $ | 64,880 | ||||||
Our accounts receivable primarily relates to sales of our crude oil, natural gas and NGLs production, derivative counterparties and other third parties that own working interests in the properties we operate. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Our estimate of uncollectible amounts changes periodically. For the each of the years in the three-year period ended December 31, 2013, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2013, we had two customers representing 10% or greater of our accounts receivable balance: Suncor Energy Marketing and DCP Midstream, representing 26.3% and 10.8%, respectively, of our accounts receivable balance. The $7.6 million of accounts receivable at December 31, 2012 related to reimbursements for title defects discovered subsequent to closing of the Merit Acquisition. The reimbursement was received in January 2013. | ||||||||||
Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: | ||||||||||
Year Ended December 31, | ||||||||||
Customer | 2013 | 2012 | 2011 | |||||||
Suncor Energy Marketing, Inc. | 31.3 | % | 29.8 | % | 25.7 | % | ||||
DCP Midstream, LP | 14.6 | % | 12.2 | % | 11.5 | % | ||||
Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant. | ||||||||||
The following table presents the counterparties that expose us to credit risk as of December 31, 2013, with regard to our derivative assets: | ||||||||||
Fair Value of | ||||||||||
Derivative Assets | ||||||||||
Counterparty Name | As of December 31, 2013 | |||||||||
(in thousands) | ||||||||||
Wells Fargo Bank, N.A. (1) | $ | 2,496 | ||||||||
Bank of Montreal (1) | 1,102 | |||||||||
Canadian Imperial Bank of Commerce (1) | 1,054 | |||||||||
Other lenders in our revolving credit facility | 3,380 | |||||||||
Various (2) | 141 | |||||||||
Total | $ | 8,173 | ||||||||
____________ | ||||||||||
(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt. | ||||||||||
(2)Represents a total of 19 counterparties. |
PROPERTIES_AND_EQUIPMENT
PROPERTIES AND EQUIPMENT | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Property, Plant and Equipment [Abstract] | ' | |||||||||||
Property, Plant and Equipment Disclosure [Text Block] | ' | |||||||||||
PROPERTIES AND EQUIPMENT | ||||||||||||
The following table presents the components of properties and equipment, net of accumulated DD&A: | ||||||||||||
As of December 31, | ||||||||||||
2013 | 2012 | |||||||||||
(in thousands) | ||||||||||||
Properties and equipment, net: | ||||||||||||
Crude oil and natural gas properties | ||||||||||||
Proved | $ | 1,781,681 | $ | 2,075,924 | ||||||||
Unproved | 307,203 | 319,327 | ||||||||||
Total crude oil and natural gas properties | 2,088,884 | 2,395,251 | ||||||||||
Pipelines and related facilities | 21,781 | 47,786 | ||||||||||
Equipment and other | 29,246 | 34,858 | ||||||||||
Land and buildings | 13,617 | 14,935 | ||||||||||
Construction in progress | 53,810 | 67,217 | ||||||||||
Gross properties and equipment | 2,207,338 | 2,560,047 | ||||||||||
Accumulated DD&A | (553,893 | ) | (943,341 | ) | ||||||||
Properties and equipment, net | $ | 1,653,445 | $ | 1,616,706 | ||||||||
The following table presents impairment charges recorded for crude oil and natural gas properties: | ||||||||||||
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Continuing operations: | ||||||||||||
Impairment of proved properties | $ | 48,750 | $ | — | $ | — | ||||||
Impairment of individually significant unproved properties | 1,082 | 1,629 | 1,108 | |||||||||
Amortization of individually insignificant unproved properties | 3,603 | 4,266 | 1,193 | |||||||||
Total continuing operations | 53,435 | 5,895 | 2,301 | |||||||||
Discontinued operations: | ||||||||||||
Impairment of proved properties | — | 161,185 | 22,460 | |||||||||
Impairment of individually significant unproved properties | — | 313 | — | |||||||||
Amortization of individually insignificant unproved properties | 3 | 756 | 398 | |||||||||
Total discontinued operations | 3 | 162,254 | 22,858 | |||||||||
Total impairment of crude oil and natural gas properties | $ | 53,438 | $ | 168,149 | $ | 25,159 | ||||||
In the first quarter of 2013, we recognized an impairment charge of approximately $45.0 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. Pursuant to a purchase and sale agreement entered into in October 2013, we determined that the carrying value of the above-mentioned properties exceeded the transaction sales price, a Level 3 input, less costs to sell. As a result, we recognized an additional impairment charge of approximately $3.8 million in the third quarter of 2013 to reduce the carrying value of the net assets to reflect the current net sales price. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. | ||||||||||||
In 2012, we recognized an impairment charge of $161.2 million to write-down our Piceance Basin proved oil and natural gas properties to fair value. The fair value was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. | ||||||||||||
In 2011, we recognized an impairment charge of $22.5 million to write-down our NECO assets to fair value. The fair value was based on unrelated third-party bids, a Level 3 input. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. | ||||||||||||
Suspended Well Costs | ||||||||||||
The following table presents the capitalized exploratory well costs pending determination of proved reserves, and included in properties and equipment on the consolidated balance sheets: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands, except for number of wells) | ||||||||||||
Balance beginning of year, January 1, | $ | 19,567 | $ | 4,432 | $ | 2,297 | ||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 13,424 | 30,482 | 3,692 | |||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | (32,991 | ) | — | (1,557 | ) | |||||||
Capitalized exploratory well costs charged to expense | — | (15,347 | ) | — | ||||||||
Balance end of year, December 31, | $ | — | $ | 19,567 | $ | 4,432 | ||||||
Number of wells pending determination at December 31, | — | 2 | 6 | |||||||||
As of December 31, 2013, none of our wells pending determination were classified as exploratory wells. | ||||||||||||
Additions to capitalized exploratory well costs pending determination of proved reserves increased in 2012 as compared to 2011 as we increased our exploratory drilling activities in the Utica Shale play. In 2012, capitalized well costs related to two vertical stratigraphic test wells in southeastern Ohio were expensed at a cost of $12.2 million. Additionally, three Rose Run test wells in Ohio and a well in southeast Colorado were determined to have noncommercial quantities of hydrocarbons and were expensed at a cost of $1.2 million and $0.9 million, respectively. | ||||||||||||
The following table presents an aging of capitalized exploratory well costs based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling: | ||||||||||||
As of December 31, | ||||||||||||
2012 | 2011 | |||||||||||
(in thousands) | ||||||||||||
Exploratory well costs capitalized for a period of one year or less | $ | 19,567 | $ | 3,587 | ||||||||
Exploratory well costs capitalized for a period greater than one year since commencement of drilling | — | 845 | ||||||||||
Balance end of year, December 31, | $ | 19,567 | $ | 4,432 | ||||||||
Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling | — | 2 | ||||||||||
INCOME_TAXES
INCOME TAXES | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Income Tax Disclosure [Abstract] | ' | |||||||||||
Income Tax Disclosure [Text Block] | ' | |||||||||||
INCOME TAXES | ||||||||||||
The table below presents the components of our provision for income taxes from continuing operations for the years presented: | ||||||||||||
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Current: | ||||||||||||
Federal | $ | 1,355 | $ | — | $ | 2,594 | ||||||
State | 199 | (199 | ) | 750 | ||||||||
Total current income taxes | 1,554 | (199 | ) | 3,344 | ||||||||
Deferred: | ||||||||||||
Federal | 11,145 | 12,133 | (13,309 | ) | ||||||||
State | 2,098 | 767 | (1,835 | ) | ||||||||
Total deferred income taxes | 13,243 | 12,900 | (15,144 | ) | ||||||||
Income tax benefit (expense) from continuing operations | $ | 14,797 | $ | 12,701 | $ | (11,800 | ) | |||||
In 2012 and 2011, we continued to utilize tax deferral strategies such as bonus depreciation, accelerated depreciation and intangible drilling cost expense elections to minimize our current taxes. As a result of these elections and deferral strategies, we generated federal and state net operating losses (“NOLs”) in 2012 and 2011. In 2013 we limited our deferral strategies to only the continued utilization of accelerated depreciation in an effort to utilize our federal NOLs. The majority of our federal NOLs and some of our state NOLs, except for Colorado due to statutory limits, are being utilized in 2013 to offset the 2013 taxable gain on the sale of our non-core Colorado assets. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale of our non-core Colorado assets. The remaining federal NOLs and state NOLs will be carried forward to offset taxable income in 2014 or prospective years. | ||||||||||||
The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: | ||||||||||||
Year Ended December, 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Statutory tax rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net | 3.3 | 1 | 2 | |||||||||
Percentage depletion | 1.8 | 1.9 | (2.5 | ) | ||||||||
Non-deductible compensation | (3.4 | ) | (0.5 | ) | — | |||||||
Non-deductible meals and entertainment | (0.5 | ) | (0.5 | ) | 0.3 | |||||||
State deferred rate change | — | — | 1.3 | |||||||||
Unrecognized tax benefits | (0.1 | ) | — | (2.6 | ) | |||||||
Federal return examination adjustments | — | — | 0.4 | |||||||||
Return to provision adjustments | (0.5 | ) | — | 0.3 | ||||||||
Other | 0.3 | — | 0.1 | |||||||||
Effective tax rate | 35.9 | % | 36.9 | % | 34.3 | % | ||||||
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are presented below: | ||||||||||||
As of December 31, | ||||||||||||
2013 | 2012 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax assets: | ||||||||||||
Net change in fair value of unsettled derivatives | $ | 6,205 | $ | — | ||||||||
Deferred compensation | 8,507 | 7,216 | ||||||||||
Asset retirement obligations | 11,630 | 10,325 | ||||||||||
State NOL and tax credit carryforwards, net | 5,182 | 6,117 | ||||||||||
Percentage depletion - carryforward | 4,570 | 4,702 | ||||||||||
Alternative minimum tax - credit carryforward | 3,165 | 2,351 | ||||||||||
Federal NOL carryforward | 4,601 | 21,281 | ||||||||||
Other | 6,229 | 2,276 | ||||||||||
Deferred tax assets | 50,089 | 54,268 | ||||||||||
Deferred tax liabilities: | ||||||||||||
Properties and equipment | 120,746 | 122,742 | ||||||||||
Investment in PDCM | 21,962 | 31,445 | ||||||||||
Net change in fair value of unsettled derivatives | — | 7,163 | ||||||||||
Convertible debt | 3,774 | 5,194 | ||||||||||
Total gross deferred tax liabilities | 146,482 | 166,544 | ||||||||||
Net deferred tax liability | $ | 96,393 | $ | 112,276 | ||||||||
Classification in the consolidated balance sheets: | ||||||||||||
Deferred income tax assets | $ | 22,374 | $ | 36,151 | ||||||||
Deferred income tax liability | 118,767 | 148,427 | ||||||||||
Net deferred tax liability | $ | 96,393 | $ | 112,276 | ||||||||
Deferred tax assets decreased primarily due to the utilization of a significant portion of our federal NOL carryforward in 2013. This decrease was partially offset by the addition of the deferred tax asset associated with the unrealized tax loss for the fair value of unsettled derivatives. | ||||||||||||
Deferred tax liabilities for properties and equipment remained relatively unchanged in 2013 primarily as a result of our tax gain on the sale of our non-core Colorado properties and equipment being offset by our continued use of statutory provisions for accelerated amortization of intangible drilling costs and accelerated tax depreciation. The deferred tax liability associated with our investment in PDCM decreased due to PDCM’s sale of its shallow Devonian assets. In addition, the fair value of derivatives at December 31, 2013 resulted in an unrealized tax loss versus an unrealized tax gain at December 31, 2012. | ||||||||||||
As of December 31, 2013, we have state NOL carryforwards of $136.1 million that begin to expire in 2030, state credit carryforwards of $1.1 million that begin to expire in 2023 and federal NOL carryforwards of $13.6 million that will expire in 2032. Approximately $0.2 million of excess tax benefits relating to stock-based compensation that are a component of our NOL carryforwards, when realized, will be credited to APIC. | ||||||||||||
Unrecognized tax benefits were immaterial for each of the years in the three-year period ended December 31, 2013. Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2013. The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $0.1 million as of December 31, 2013 and $0.2 million as of December 31, 2012. As of December 31, 2013, we expect a decrease in the unrecognized tax benefit in the next twelve months due to the expiration of the relevant statute of limitations. During 2013, we reduced our liability for any uncertain tax benefits, of which the remaining balance is related to our state tax filings, due to the expiration of the relevant statute of limitations. The statute of limitations for most of our state tax jurisdictions is open from 2009 forward. | ||||||||||||
In accordance with the CAP program, the IRS completed its “post filing review” of our 2011 tax return in January 2013 and they are currently completing their “post filing review” of our 2012 tax return. We have been issued a “no change” letter for both of the reviewed tax years. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the CAP program for the review of our 2013 tax year and we have been invited and have accepted continued participation in the program for our 2014 tax year. Participation in the CAP program has enabled us to currently have no uncertain tax benefits associated with our federal tax return filings. During 2011, we reduced our liability for uncertain tax benefits by $0.8 million due to the accelerated examination and settlement of our 2007-2009 tax years upon entering the CAP program. | ||||||||||||
As of December 31, 2013, we were current with our income tax filings in all applicable state jurisdictions. In 2013, the State of Colorado examined our 2008 through 2011 Colorado Corporate Income Tax Returns and proposed no adjustments. |
LONGTERM_DEBT
LONG-TERM DEBT | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Long-term Debt, Unclassified [Abstract] | ' | |||||||
Long-term Debt [Text Block] | ' | |||||||
LONG-TERM DEBT | ||||||||
Long-term debt consists of the following: | ||||||||
As of December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Senior notes: | ||||||||
3.25% Convertible senior notes due 2016: | ||||||||
Principal amount | $ | 115,000 | $ | 115,000 | ||||
Unamortized discount | (10,010 | ) | (13,671 | ) | ||||
3.25% Convertible senior notes due 2016, net of discount | 104,990 | 101,329 | ||||||
7.75% Senior notes due 2022: | ||||||||
7.75% Senior notes due 2022 | 500,000 | 500,000 | ||||||
Total senior notes | 604,990 | 601,329 | ||||||
Credit facilities: | ||||||||
Corporate | — | 49,000 | ||||||
PDCM | 37,000 | 26,250 | ||||||
Total credit facilities | 37,000 | 75,250 | ||||||
PDCM second lien term loan | 15,000 | — | ||||||
Long-term debt | $ | 656,990 | $ | 676,579 | ||||
Senior Notes | ||||||||
3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016. Interest is payable semi-annually in arrears on each May 15 and November 15. The Convertible Notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to our existing and future unsecured indebtedness that is not expressly subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the convertible notes does not contain any restrictive financial covenants. The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes, if any, have not been registered under the Securities Act of 1933 or any state securities laws, nor are we required to register such convertible notes or common shares. The Convertible Notes are governed by an indenture between the Company and the Bank of New York Mellon, as trustee. | ||||||||
We may not redeem the Convertible Notes prior to their maturity. However, prior to November 15, 2015, holders of the Convertible Notes may convert upon specified events as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. | ||||||||
We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our Convertible Notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the convertible notes. As of December 31, 2013, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 2.4 years using an effective interest rate of 7.4%. For 2013, interest expense related to the indebtedness and the amortization of the discount was $3.7 million each compared to $3.7 million and $3.4 million, respectively, in 2012 and $3.7 million and $3.2 million, respectively, in 2011. As of December 31, 2013, notwithstanding the inability to convert, the “if-converted” value of the Convertible Notes exceeded the principal amount by approximately $29.3 million. | ||||||||
7.75% Senior Notes Due 2022. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional investors. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our Convertible Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. | ||||||||
In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for substantially identical registered notes and to use commercially reasonable efforts to cause the exchange offer to be completed on or prior to September 28, 2013. The registration statement was declared effective by the SEC in July 2013 and the exchange offer was completed in August 2013. | ||||||||
At any time prior to October 15, 2017, we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017, we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. | ||||||||
At any time prior to October 15, 2015, we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as: | ||||||||
• | at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption; and | |||||||
• | the redemption occurs within 180 days after the closing of the equity offering. | |||||||
Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. | ||||||||
The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. | ||||||||
As of December 31, 2013, we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next twelve-month period. | ||||||||
Credit Facilities | ||||||||
Revolving Credit Facility. In May 2013, we entered into a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and expires in May 2018. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. As of December 31, 2013, the borrowing base was $450 million. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our and our subsidiaries' crude oil and natural gas interests, excluding proved reserves attributable to PDCM and our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. On October 31, 2013, we completed the semi-annual redetermination of our borrowing base and the borrowing base was reaffirmed at $450 million. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor our affiliated partnerships are guarantors of our obligations under the revolving credit facility. As of December 31, 2013, we had no outstanding draws on our revolving credit facility compared to $49.0 million at a weighted-average interest rate of 2.3% as of December 31, 2012. | ||||||||
The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires in May 2018, or in the event that the borrowing base falls below the outstanding balance. | ||||||||
The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of December 31, 2013, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next twelve-month period. | ||||||||
The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. | ||||||||
As of December 31, 2013, RNG, a wholly owned subsidiary of PDC, had an approximately $11.7 million irrevocable standby letter of credit in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. The letter of credit expires in September 2014. As of December 31, 2013, the available funds under our revolving credit facility, including a reduction for the $11.7 million irrevocable standby letter of credit in effect, was $438.3 million. | ||||||||
PDCM Credit Facility. PDCM has a credit facility dated April 2010, as amended in May 2013, with a borrowing base of $105 million, of which our proportionate share is approximately $53 million. The maximum allowable facility amount is $400 million. No principal payments are required until the credit agreement expires in April 2017, or in the event that the borrowing base falls below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The borrowing base is subject to size redetermination semi-annually based upon a valuation of PDCM's reserves at June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. The credit facility is utilized by PDCM for the exploration and development of its Appalachia-Marcellus Shale assets. | ||||||||
The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests that must be met on a quarterly basis. The financial tests, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.25 to 1.0 (declining to 4.0 to 1.0 on July 1, 2014) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of December 31, 2013, our proportionate share of PDCM's outstanding credit facility balance was $37.0 million compared to $26.3 million as of December 31, 2012. The weighted-average borrowing rate on PDCM's credit facility was 3.7% per annum as of December 31, 2013, compared to 3.5% as of December 31, 2012. | ||||||||
As of December 31, 2013, PDCM was in compliance with all credit facility covenants and expects to remain in compliance throughout the next twelve-month period. | ||||||||
PDCM Second Lien Term Loan | ||||||||
In July 2013, PDCM entered into a Second Lien Credit Agreement ("Term Loan Agreement") with Wells Fargo Energy Capital as administrative agent and a syndicate of other lenders party thereto. The aggregate commitment under the Term Loan Agreement is $30 million, of which our proportionate share is $15 million. The aggregate commitment may increase periodically up to a maximum of $75 million, as PDCM's reserve value increases and the covenants under the Term Loan Agreement allow. The Term Loan Agreement matures in October 2017. Amounts borrowed accrue interest, at PDCM's discretion, at either an alternative base rate plus a margin of 6% per annum or an adjusted LIBOR for the interest period in effect plus a margin of 7% per annum. As of December 31, 2013, amounts borrowed and outstanding on the Term Loan Agreement were $30 million, of which our proportionate share is $15 million. The weighted-average borrowing rate on the Term Loan was 8.5% per annum as of December 31, 2013. | ||||||||
The Term Loan Agreement contains financial covenants that must be met on a quarterly basis, including requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.5 to 1.0, to maintain a minimum interest coverage ratio of 2.25 to 1.0 and a present value of future net revenues to total debt ratio of 1.50 to 1.00. As of December 31, 2013, PDCM was in compliance with all Term Loan Agreement covenants and expects to remain in compliance throughout the next twelve-month period. |
ASSET_RETIREMENT_OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | |||||||
Asset Retirement Obligation Disclosure [Text Block] | ' | |||||||
ASSET RETIREMENT OBLIGATIONS | ||||||||
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Balance at beginning of year, January 1 | $ | 62,563 | $ | 46,566 | ||||
Obligations incurred with development activities and assumed with acquisitions | 2,389 | 14,169 | ||||||
Accretion expense | 4,747 | 4,060 | ||||||
Revisions in estimated cash flows | 612 | — | ||||||
Obligations discharged with divestitures of properties and asset retirements (1) | (29,281 | ) | (2,232 | ) | ||||
Balance end of year, December 31 | 41,030 | 62,563 | ||||||
Less: Liabilities held for sale (1) | (2,061 | ) | — | |||||
Less: Current portion | (1,158 | ) | (1,000 | ) | ||||
Long-term portion | $ | 37,811 | $ | 61,563 | ||||
______________ | ||||||||
-1 | Represents asset retirement obligations related to assets sold and assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2013 | |
Employee Benefits and Share-based Compensation [Abstract] | ' |
Compensation and Employee Benefit Plans [Text Block] | ' |
EMPLOYEE BENEFIT PLANS | |
We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $3.7 million, $3.4 million and $2.6 million for 2013, 2012 and 2011, respectively. | |
We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2013, 2012 and 2011. As of December 31, 2013 and 2012, the liability related to this benefit was $1.8 million and $2.0 million, respectively, which was included in other liabilities on the consolidated balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2013 and 2012. | |
We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2013, 2012 and 2011 related to this plan were immaterial. As of December 31, 2013 and 2012, the related liability of $0.7 million is included in other liabilities on the consolidated balance sheets. | |
We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the consolidated balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2013 and 2012. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Text Block] | ' | ||||||||||||||||||||||||||||
COMMITMENTS AND CONTINGENCIES | |||||||||||||||||||||||||||||
Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC. | |||||||||||||||||||||||||||||
The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity: | |||||||||||||||||||||||||||||
Year Ending December 31, | |||||||||||||||||||||||||||||
Area | 2014 | 2015 | 2016 | 2017 | 2018 and | Total | Expiration | ||||||||||||||||||||||
Through | Date | ||||||||||||||||||||||||||||
Expiration | |||||||||||||||||||||||||||||
Volume (MMcf) | |||||||||||||||||||||||||||||
Appalachia-Marcellus Shale | 18,212 | 19,485 | 21,044 | 20,987 | 125,336 | 205,064 | January 31, 2026 | ||||||||||||||||||||||
Utica Shale | 2,454 | 2,738 | 2,745 | 2,737 | 15,285 | 25,959 | July 22, 2023 | ||||||||||||||||||||||
Total | 20,666 | 22,223 | 23,789 | 23,724 | 140,621 | 231,023 | |||||||||||||||||||||||
Dollar commitment (in thousands) | $ | 7,547 | $ | 7,907 | $ | 8,230 | $ | 7,790 | $ | 38,526 | $ | 70,000 | |||||||||||||||||
In March 2013, we entered into long-term agreements with a subsidiary of MarkWest Energy Partners, LP to provide midstream services, including gas gathering, processing, fractionation and marketing, to support our northern Utica Shale operations. The primary term of the agreements commenced in July 2013 when our natural gas began to flow into the gathering system. The gas processing agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall. | |||||||||||||||||||||||||||||
Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. | |||||||||||||||||||||||||||||
Alleged Class Action Regarding 2010 and 2011 Partnership Purchases | |||||||||||||||||||||||||||||
In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In June 2012, the Court denied the Company's motion to dismiss. In January 2014, the plaintiffs were conditionally certified as a class by the court. Jury trial is scheduled for May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and it is not possible for management to reasonably estimate monetary damages resulting from this claim. | |||||||||||||||||||||||||||||
Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2013 and December 31, 2012, we had accrued environmental liabilities in the amount of $5.4 million and $8.4 million, respectively, included in other accrued expenses on the consolidated balance sheet. We are not aware of any environmental claims existing as of December 31, 2013 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. | |||||||||||||||||||||||||||||
Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. | |||||||||||||||||||||||||||||
The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2013: | |||||||||||||||||||||||||||||
Year Ending December 31, | |||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||||||
Minimum Lease Payments | $ | 2,427 | $ | 1,970 | $ | 471 | $ | 257 | $ | 34 | $ | 941 | $ | 6,100 | |||||||||||||||
Operating lease expense for the years ended 2013, 2012 and 2011 was $7 million, $6.1 million and $5.9 million, respectively. | |||||||||||||||||||||||||||||
Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company. | |||||||||||||||||||||||||||||
See Note 16, Transactions With Affiliates, for a discussion related to the separation agreement entered into with our former chief executive officer in 2011. |
COMMON_STOCK
COMMON STOCK | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||||||||||
COMMON STOCK [Abstract] | ' | |||||||||||||||||||||||||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block] | ' | |||||||||||||||||||||||||||||||||||
COMMON STOCK | ||||||||||||||||||||||||||||||||||||
Sale of Equity Securities | ||||||||||||||||||||||||||||||||||||
In August 2013, we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share. Net proceeds of the offering were approximately $275.8 million, after deducting offering expenses and underwriting discounts, of which $51,750 is included in common shares-par value and approximately $275.8 million is included in APIC on the consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. | ||||||||||||||||||||||||||||||||||||
In May 2012, we completed a public offering of 6,500,000 shares of our common stock at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million, after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 million is included in APIC on the consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. | ||||||||||||||||||||||||||||||||||||
Stock-Based Compensation Plans | ||||||||||||||||||||||||||||||||||||
2010 Long-Term Equity Compensation Plan. In June 2010, our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2013, 1,708,107 shares remain available for issuance pursuant to the 2010 Plan. | ||||||||||||||||||||||||||||||||||||
2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. As of December 31, 2013, all awards granted pursuant to the 2004 Plan had vested and are exercisable through April 19, 2020. | ||||||||||||||||||||||||||||||||||||
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011(1) | ||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||
Stock-based compensation expense | $ | 12,880 | $ | 8,495 | $ | 8,781 | ||||||||||||||||||||||||||||||
Income tax benefit | (4,697 | ) | (3,245 | ) | (3,344 | ) | ||||||||||||||||||||||||||||||
Net stock-based compensation expense | $ | 8,183 | $ | 5,250 | $ | 5,437 | ||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||
(1) Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 16, Transactions with Affiliates, for additional information regarding the related separation agreement. | ||||||||||||||||||||||||||||||||||||
Stock Option Awards | ||||||||||||||||||||||||||||||||||||
We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock option awards since 2006. As of December 31, 2013, all compensation cost related to stock options has been fully recognized in our consolidated statements of operations. | ||||||||||||||||||||||||||||||||||||
The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Number of | Weighted-Average | Weighted- Average | Aggregate Intrinsic | Number of | Weighted-Average | Number of | Weighted-Average | |||||||||||||||||||||||||||||
Shares | Exercise | Remaining | Value (in thousands) | Shares | Exercise | Shares | Exercise | |||||||||||||||||||||||||||||
Underlying | Price | Contractual | Underlying | Price | Underlying | Price | ||||||||||||||||||||||||||||||
Options | Per Share | Term (in years) | Options | Per Share | Options | Per Share | ||||||||||||||||||||||||||||||
Outstanding beginning of year, January 1, | 6,973 | $ | 41.09 | 2.6 | $ | — | 6,973 | $ | 41.09 | 10,306 | $ | 41.9 | ||||||||||||||||||||||||
Exercised | (3,450 | ) | 37.15 | — | 77 | — | — | — | — | |||||||||||||||||||||||||||
Forfeited | — | — | — | — | — | — | (3,333 | ) | 43.6 | |||||||||||||||||||||||||||
Outstanding end of year, December 31, | 3,523 | 44.95 | 2.2 | 29 | 6,973 | 41.09 | 6,973 | 41.09 | ||||||||||||||||||||||||||||
Exercisable at December 31, | 3,523 | 44.95 | 2.2 | 29 | 6,973 | 41.09 | 6,973 | 41.09 | ||||||||||||||||||||||||||||
SARs | ||||||||||||||||||||||||||||||||||||
The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. | ||||||||||||||||||||||||||||||||||||
In January 2013, the Compensation Committee awarded 87,078 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Expected term of award | 6 years | 6 years | 6 years | |||||||||||||||||||||||||||||||||
Risk-free interest rate | 1 | % | 1.1 | % | 2.5 | % | ||||||||||||||||||||||||||||||
Expected volatility | 65.5 | % | 64.3 | % | 60.2 | % | ||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | $ | 21.96 | $ | 17.61 | $ | 25.22 | ||||||||||||||||||||||||||||||
The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. | ||||||||||||||||||||||||||||||||||||
The following table presents the changes in our SARs: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Number of | Weighted-Average | Average Remaining Contractual | Aggregate Intrinsic | Number of | Weighted-Average | Aggregate Intrinsic | Number of | Weighted-Average | Aggregate Intrinsic | |||||||||||||||||||||||||||
SARs | Exercise | Term (in years) | Value (in thousands) | SARs | Exercise | Value (in thousands) | SARs | Exercise | Value (in thousands) | |||||||||||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||||||||||||||
Outstanding beginning of year, January 1, | 118,832 | $ | 30.8 | 8.4 | $ | 486 | 50,471 | $ | 31.61 | $ | 341 | 57,282 | $ | 24.44 | $ | 1,020 | ||||||||||||||||||||
Awarded | 87,078 | 37.18 | — | — | 68,361 | 30.19 | — | 31,552 | 43.95 | — | ||||||||||||||||||||||||||
Exercised | (15,147 | ) | 30.06 | — | 425 | — | — | — | (25,371 | ) | 24.44 | 77 | ||||||||||||||||||||||||
Forfeited | — | — | — | — | — | — | — | (12,992 | ) | 43.95 | — | |||||||||||||||||||||||||
Outstanding at December 31, | 190,763 | 33.77 | 8.2 | 3,711 | 118,832 | 30.8 | 486 | 50,471 | 31.61 | 341 | ||||||||||||||||||||||||||
Exercisable at December 31, | 51,922 | 29.97 | 7.1 | 1,207 | 27,458 | 28.84 | 187 | 10,636 | 24.44 | 114 | ||||||||||||||||||||||||||
Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our consolidated statement of operations as of December 31, 2013, was $1.7 million. The cost is expected to be recognized over a weighted-average period of 1.8 years. | ||||||||||||||||||||||||||||||||||||
Restricted Stock Awards | ||||||||||||||||||||||||||||||||||||
Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed. | ||||||||||||||||||||||||||||||||||||
In January 2013, the Compensation Committee awarded a total of 103,050 time-based restricted shares to our executive officers that vest ratably over the three year period ending on January 16, 2016. | ||||||||||||||||||||||||||||||||||||
The following table presents the changes in non-vested time-based awards during 2013: | ||||||||||||||||||||||||||||||||||||
Shares | Weighted-Average | |||||||||||||||||||||||||||||||||||
Grant-Date | ||||||||||||||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||||||||||||||
Non-vested at December 31, 2012 | 646,490 | $ | 27.93 | |||||||||||||||||||||||||||||||||
Granted | 311,051 | 45.53 | ||||||||||||||||||||||||||||||||||
Vested | (282,787 | ) | 27.57 | |||||||||||||||||||||||||||||||||
Forfeited | (22,973 | ) | 31.52 | |||||||||||||||||||||||||||||||||
Non-vested at December 31, 2013 | 651,781 | 36.36 | ||||||||||||||||||||||||||||||||||
As of/Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||||||||||||||||||
Total intrinsic value of time-based awards vested | $ | 13,640 | $ | 5,950 | $ | 9,030 | ||||||||||||||||||||||||||||||
Total intrinsic value of time-based awards non-vested | 34,688 | 21,470 | 18,531 | |||||||||||||||||||||||||||||||||
Market price per common share as of December 31, | 53.22 | 33.21 | 35.11 | |||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | 45.53 | 26.59 | 33.71 | |||||||||||||||||||||||||||||||||
Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2013 was $15.7 million. This cost is expected to be recognized over a weighted-average period of 2.0 years. | ||||||||||||||||||||||||||||||||||||
Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. | ||||||||||||||||||||||||||||||||||||
In January 2013, the Compensation Committee awarded a total of 41,570 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2014 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||||
Expected term of award | 3 years | 3 years | ||||||||||||||||||||||||||||||||||
Risk-free interest rate | 0.4 | % | 0.3 | % | ||||||||||||||||||||||||||||||||
Expected volatility | 56.6 | % | 65.3 | % | ||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | $ | 49.04 | $ | 36.54 | ||||||||||||||||||||||||||||||||
The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. | ||||||||||||||||||||||||||||||||||||
The following table presents the change in non-vested market-based awards during 2013: | ||||||||||||||||||||||||||||||||||||
Shares | Weighted-Average | |||||||||||||||||||||||||||||||||||
Grant-Date | ||||||||||||||||||||||||||||||||||||
Fair Value per Share | ||||||||||||||||||||||||||||||||||||
Non-vested at December 31, 2012 | 40,696 | $ | 39.22 | |||||||||||||||||||||||||||||||||
Granted | 41,570 | 49.04 | ||||||||||||||||||||||||||||||||||
Vested | (10,155 | ) | 47.28 | |||||||||||||||||||||||||||||||||
Non-vested at December 31, 2013 | 72,111 | 43.75 | ||||||||||||||||||||||||||||||||||
As of/Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||||||||||||||||||
Total intrinsic value of market-based awards vested | $ | 724 | $ | — | $ | 366 | ||||||||||||||||||||||||||||||
Total intrinsic value of market-based awards non-vested | 3,838 | 1,352 | 1,513 | |||||||||||||||||||||||||||||||||
Market price per common share as of December 31, | 53.22 | 33.21 | 35.11 | |||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | 49.04 | 36.54 | 58.53 | |||||||||||||||||||||||||||||||||
Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statement of operations as of December 31, 2013 was $1.7 million. This cost is expected to be recognized over a weighted-average period of 1.8 years. | ||||||||||||||||||||||||||||||||||||
Treasury Share Purchases | ||||||||||||||||||||||||||||||||||||
In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to APIC to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2013, we acquired 84,642 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 17,257 shares were retired, 67,334 shares were reissued and 51 shares are available for reissuance pursuant to our 2010 Plan. | ||||||||||||||||||||||||||||||||||||
Shareholders’ Rights Agreement | ||||||||||||||||||||||||||||||||||||
In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record in September 2007. A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire in September 2017. | ||||||||||||||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||||||||||||||
We are authorized, pursuant to shareholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2013, no preferred shares had been issued. |
EARNINGS_PER_SHARE
EARNINGS PER SHARE | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ' | ||||||||
Earnings Per Share [Text Block] | ' | ||||||||
EARNINGS PER SHARE | |||||||||
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. | |||||||||
The following table presents a reconciliation of the weighted-average diluted shares outstanding: | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | 2011 | |||||||
(in thousands) | |||||||||
Weighted-average common shares outstanding - basic | 32,426 | 27,677 | 23,521 | ||||||
Dilutive effect of: | |||||||||
Restricted stock | — | — | 307 | ||||||
SARs | — | — | 40 | ||||||
Non-employee director deferred compensation | — | — | 3 | ||||||
Weighted-average common shares and equivalents outstanding - diluted | 32,426 | 27,677 | 23,871 | ||||||
For 2013 and 2012, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive. | |||||||||
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | 2011 | |||||||
(in thousands) | |||||||||
Weighted-average common share equivalents excluded from diluted earnings | |||||||||
per share due to their anti-dilutive effect: | |||||||||
Restricted stock | 823 | 694 | 220 | ||||||
SARs | 72 | 116 | 22 | ||||||
Stock options | 7 | 7 | 9 | ||||||
Non-employee director deferred compensation | 4 | 3 | — | ||||||
Convertible notes | 518 | — | — | ||||||
Total anti-dilutive common share equivalents | 1,424 | 820 | 251 | ||||||
In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the dilutive earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2013 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2012 and 2011 as the conversion price was greater than the average market price of our common stock during the period. |
ASSETS_HELD_FOR_SALE_DIVESTITU
ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Discontinued Operations and Disposal Groups [Abstract] | ' | ||||||||||||
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | ' | ||||||||||||
ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS | |||||||||||||
The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold, net of liabilities, that were or are expected to be assumed by the purchaser. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the consolidated statement of operations table presents the revenues and expenses that were reclassified from the specified consolidated statement of operations line items to discontinued operations. | |||||||||||||
The following table presents consolidated balance sheet data related to net assets held for sale: | |||||||||||||
Consolidated balance sheet | As of December 31, 2013 | ||||||||||||
(In thousands) | |||||||||||||
Assets | |||||||||||||
Properties and equipment, net | $ | 2,785 | |||||||||||
Liabilities | |||||||||||||
Asset retirement obligation | 2,061 | ||||||||||||
Net Assets | $ | 724 | |||||||||||
The following table presents consolidated statement of operations data related to our discontinued operations: | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statements of operations - discontinued operations | 2013 | 2012 | 2011 | ||||||||||
(in thousands) | |||||||||||||
Revenues | |||||||||||||
Crude oil, natural gas and NGLs sales | $ | 20,398 | $ | 36,422 | $ | 80,860 | |||||||
Sales from natural gas marketing | 2,825 | 1,708 | 2,949 | ||||||||||
Well operations, pipeline income and other | 890 | 1,888 | 2,542 | ||||||||||
Total revenues | 24,113 | 40,018 | 86,351 | ||||||||||
Costs, expenses and other | |||||||||||||
Production costs | 7,975 | 22,453 | 30,885 | ||||||||||
Cost of natural gas marketing | 2,673 | 1,529 | 2,634 | ||||||||||
Impairment of crude oil and natural gas properties | 3 | 162,254 | 22,858 | ||||||||||
Depreciation, depletion and amortization | 2,258 | 48,101 | 47,521 | ||||||||||
Other | 2,528 | 2,084 | 1,054 | ||||||||||
(Gain) loss on sale of properties and equipment | 2,330 | (19,920 | ) | (3,854 | ) | ||||||||
Total costs, expenses and other | 17,767 | 216,501 | 101,098 | ||||||||||
Income (loss) from discontinued operations | 6,346 | (176,483 | ) | (14,747 | ) | ||||||||
Provision for income taxes | (2,175 | ) | 67,466 | 5,620 | |||||||||
Income (loss) from discontinued operations, net of tax | $ | 4,171 | $ | (109,017 | ) | $ | (9,127 | ) | |||||
Appalachian Basin. In October 2013, we executed a purchase and sale agreement for the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties owned directly by us, as well as through our proportionate share of PDCM. The properties consisted of approximately 3,500 gross shallow producing wells, related facilities and associated leasehold acreage, limited to the Upper Devonian and shallower formations. Substantially all of the divestiture closed in December 2013 for aggregate consideration of approximately $20.6 million, of which our share of the proceeds was approximately $5.1 million, subject to certain post-closing adjustments. We received our proportionate share of cash proceeds of $0.9 million and recorded our proportionate share of a note receivable and account receivable from the buyer of $3.3 million and $0.8 million, respectively. The remaining assets and related liabilities were classified as held for sale in the consolidated balance sheet as of December 31, 2013. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. We retained all zones, formations and intervals below the Upper Devonian formation including the Marcellus Shale, Utica Shale and Huron Shale. The divestiture of these assets did not meet the requirements to be accounted for as discontinued operations. | |||||||||||||
Piceance Basin and NECO. In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by the buyer. In June 2013, this divestiture was completed with total consideration of approximately $177.6 million, with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale to Caerus, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the consolidated statement of operations for all periods presented. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations. | |||||||||||||
Permian Basin. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million. Additionally, on December 20, 2011, we executed a purchase and sale agreement with COG, a wholly owned subsidiary of Concho Resources Inc., for the sale of our core Permian Basin assets for a sale price of $173.9 million, subject to certain post-closing adjustments. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets; accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011, and the results of operations related to those assets have been separately reported as discontinued operations in the 2012 and 2011 consolidated statements of operations. On February 28, 2012, the divestiture closed. After final post-closing adjustments, total proceeds received were $189.2 million, resulting in a pre-tax gain on sale of $19.9 million. |
ACQUISITIONS
ACQUISITIONS | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Business Combinations [Abstract] | ' | ||||||||||||||||
Business Combination Disclosure [Text Block] | ' | ||||||||||||||||
ACQUISITIONS | |||||||||||||||||
The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012 and 2011: | |||||||||||||||||
Year Ended December 31, | |||||||||||||||||
2012 | 2011 | ||||||||||||||||
Merit | Seneca-Upshur | 2003/2002-D Partnerships | 2005 Partnerships | ||||||||||||||
(in thousands) | |||||||||||||||||
Total acquisition cost | $ | 304,643 | $ | 69,618 | $ | 29,960 | $ | 43,015 | |||||||||
Recognized amounts of identifiable assets acquired and liabilities assumed: | |||||||||||||||||
Assets acquired: | |||||||||||||||||
Crude oil and natural gas properties - proved | $ | 180,696 | $ | 20,175 | $ | 27,940 | $ | 39,825 | |||||||||
Crude oil and natural gas properties - unproved | 151,428 | 49,100 | — | — | |||||||||||||
Other assets | 3,631 | 10,196 | 3,455 | 3,848 | |||||||||||||
Total assets acquired | 335,755 | 79,471 | 31,395 | 43,673 | |||||||||||||
Liabilities assumed: | |||||||||||||||||
Asset retirement obligation | 14,833 | 8,157 | 497 | 300 | |||||||||||||
Other accrued expenses | 9,574 | — | — | — | |||||||||||||
Other liabilities | 6,705 | 1,696 | 938 | 358 | |||||||||||||
Total liabilities assumed | 31,112 | 9,853 | 1,435 | 658 | |||||||||||||
Total identifiable net assets acquired | $ | 304,643 | $ | 69,618 | $ | 29,960 | $ | 43,015 | |||||||||
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are sensitive and subject to change. | |||||||||||||||||
2012 Acquisitions | |||||||||||||||||
Merit Acquisition. In June 2012, we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy. The aggregate purchase price of these properties was approximately $304.6 million. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility. | |||||||||||||||||
This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. | |||||||||||||||||
Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 and December 31, 2011, assuming the Merit Acquisition had been completed as of January 1, 2011, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results. | |||||||||||||||||
Year Ended December 31, | |||||||||||||||||
2012 | 2011 | ||||||||||||||||
(in thousands, except per share amounts) | |||||||||||||||||
Total revenues | $ | 370,488 | $ | 438,204 | |||||||||||||
Total costs, expenses and other | 521,178 | 366,120 | |||||||||||||||
Net income (loss) | $ | (119,343 | ) | $ | 45,688 | ||||||||||||
Earnings per share: | |||||||||||||||||
Basic | $ | (4.31 | ) | $ | 1.94 | ||||||||||||
Diluted | $ | (4.31 | ) | $ | 1.91 | ||||||||||||
2011 Acquisitions | |||||||||||||||||
Seneca-Upshur. In October 2011, PDCM acquired 100% of the membership interests of Seneca-Upshur for $139.2 million ($69.6 million net to PDC), after post-closing adjustments, which was funded by capital contributions by PDCM's investing partners and a draw on PDCM's revolving credit facility. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. PDCM received title defect payments during 2012 totaling $28.9 million, of which $14.5 million represents our share, the effect of which is reflected in the purchase price noted above. | |||||||||||||||||
2003/2002-D Partnerships. In October 2011, we acquired from non-affiliated investor partners the interests we did not already own in five of our affiliated partnerships: PDC 2002-D Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership and PDC 2003-C Limited Partnership (the "2002/2003 Partnerships"). We purchased the 2002/2003 Partnerships for an aggregate amount of $30 million, which was funded from our revolving credit facility. These purchases included the partnerships' working interests in wells located in the Wattenberg Field and Piceance Basin. | |||||||||||||||||
2005 Partnerships. In June 2011, we acquired from non-affiliated investor partners the interests we did not already own in three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (the "2005 Partnerships"). We purchased the 2005 Partnerships for an aggregate amount of $43 million, which was funded from our revolving credit facility. These purchases included the partnerships' working interests wells located in the Wattenberg Field and the Piceance Basin. | |||||||||||||||||
Pro Forma Information. The results of operations for the Seneca-Upshur, 2002/2003 Partnerships and 2005 Partnerships acquisitions have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying consolidated statements of operations. |
TRANSACTIONS_WITH_AFFILIATES_A
TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Related Party Transactions [Abstract] | ' | ||||||||||||
Related Party Transactions Disclosure [Text Block] | ' | ||||||||||||
TRANSACTIONS WITH AFFILIATES | |||||||||||||
PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the Appalachia-Marcellus Shale. Our cost of natural gas marketing includes $18.1 million, $10.9 million and $9.5 million in 2013, 2012 and 2011, respectively, related to the marketing of natural gas on behalf of PDCM and $1.3 million, $0.5 million and $1.3 million, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships. | |||||||||||||
Amounts due from/to the affiliated partnerships have historically been primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. Previously, we have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production. In June 2013, all remaining derivative positions designated to our affiliated partnerships were liquidated prior to settlement. As a result, there were no amounts due from/to our affiliated partnerships related to derivative positions as of December 31, 2013. | |||||||||||||
We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $14.5 million, $12.1 million and $10.4 million in 2013, 2012 and 2011, respectively. Our consolidated statements of operations include only our proportionate share of these billings. The following table presents the consolidated statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented. | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statement of operations line item | 2013 | 2012 | 2011 | ||||||||||
(in thousands) | |||||||||||||
Production costs | $ | 4,097 | $ | 3,945 | $ | 3,441 | |||||||
Exploration expense | 502 | 492 | 430 | ||||||||||
General and administrative expense | 2,649 | 1,630 | 1,543 | ||||||||||
Former Executive Officer. In June 2011, Richard W. McCullough resigned from his positions as our Chief Executive Officer and the Chairman of the Board, effective immediately. In connection with his resignation, in July 2011, Mr. McCullough and the Company executed a separation agreement, whereby Mr. McCullough received those benefits to which he was entitled pursuant to his employment agreement, including without limitation, separation compensation in the amount of $4.1 million, less required withholdings, his annual non-qualified deferred supplemental retirement benefit equal to $30,000 for each of the years 2012 through 2021 (not accelerated), less required withholdings, continued coverage under the Company’s group health plans at the Company’s cost for a period equal to the lesser of 18 months or such period ending as of the date Mr. McCullough is eligible to participate in another employer’s group health plan, immediate vesting of any unvested Company stock options, SARs and restricted stock and issuance of shares representing the vested portion of his 2009 performance share awards. Related to this separation agreement, the consolidated statement of operations for 2011 reflects a charge to general and administrative expense of $6.7 million. |
BUSINESS_SEGMENTS
BUSINESS SEGMENTS | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||
Segment Reporting Disclosure [Text Block] | ' | |||||||||||
BUSINESS SEGMENTS | ||||||||||||
We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. | ||||||||||||
Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net, and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $122.2 million, $94.1 million and $83.6 million in 2013, 2012 and 2011, respectively. | ||||||||||||
Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. | ||||||||||||
Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. | ||||||||||||
The following tables present our segment information: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Year Ended December 31, | ||||||||||||
Segment revenues: | ||||||||||||
Oil and gas exploration and production | $ | 341,527 | $ | 275,234 | $ | 273,819 | ||||||
Gas marketing | 69,787 | 45,371 | 63,470 | |||||||||
Total revenues | $ | 411,314 | $ | 320,605 | $ | 337,289 | ||||||
Segment income (loss) before income taxes: | ||||||||||||
Oil and gas exploration and production | $ | 79,527 | $ | 103,111 | $ | 138,616 | ||||||
Gas marketing | (298 | ) | 349 | 639 | ||||||||
Unallocated | (120,498 | ) | (137,856 | ) | (104,891 | ) | ||||||
Income (loss) before income taxes | $ | (41,269 | ) | $ | (34,396 | ) | $ | 34,364 | ||||
Expenditures for segment long-lived assets: | ||||||||||||
Oil and gas exploration and production | $ | 403,227 | $ | 656,443 | $ | 479,027 | ||||||
Unallocated | 1,379 | 3,509 | 1,363 | |||||||||
Total | $ | 404,606 | $ | 659,952 | $ | 480,390 | ||||||
As of December 31, | ||||||||||||
Segment assets: | ||||||||||||
Oil and gas exploration and production | $ | 1,934,466 | $ | 1,723,011 | ||||||||
Gas marketing | 20,342 | 11,090 | ||||||||||
Unallocated | 67,610 | 92,747 | ||||||||||
Assets held for sale | 2,785 | — | ||||||||||
Total assets | $ | 2,025,203 | $ | 1,826,848 | ||||||||
SUPPLEMENTAL_INFORMATION_NATUR
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ' | ||||||||||||
Supplemental Information - Oil and Gas Exploration and Production Industries Disclosures [Text Block] | ' | ||||||||||||
NATURAL GAS INFORMATION - UNAUDITED | |||||||||||||
Net Proved Reserves | |||||||||||||
All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, condensate and NGL reserves. As of December 31, 2013, 2012 and 2011, all of our reserve estimates were based on reserve reports prepared by Ryder Scott. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. | |||||||||||||
Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. | |||||||||||||
The price used to estimate our reserves, by commodity, are presented below. | |||||||||||||
Price Used to Estimate Reserves | |||||||||||||
As of December 31, | Crude Oil | Natural Gas | NGLs | ||||||||||
(per Bbl) | (per Mcf) | (per Bbl) | |||||||||||
2013 | $ | 82.18 | $ | 3.22 | $ | 29.92 | |||||||
2012 | 87.51 | 2.35 | 28.02 | ||||||||||
2011 | 88.94 | 3.41 | 39.59 | ||||||||||
The following tables present the changes in our estimated quantities of proved reserves: | |||||||||||||
Crude Oil, Condensate (MBbls) | Natural Gas | NGLs | Total | ||||||||||
(MMcf) | (MBbls) | (MBoe) | |||||||||||
Proved Reserves: | |||||||||||||
Proved reserves, January 1, 2011 | 23,236 | 657,306 | 10,649 | 143,436 | |||||||||
Revisions of previous estimates | (1,904 | ) | (161,654 | ) | 3,163 | (25,683 | ) | ||||||
Extensions, discoveries and other additions | 17,092 | 176,689 | 5,633 | 52,173 | |||||||||
Purchases of reserves | 1,605 | 32,761 | 1,052 | 8,117 | |||||||||
Dispositions | (435 | ) | (2,070 | ) | (94 | ) | (874 | ) | |||||
Production | (1,958 | ) | (30,887 | ) | (815 | ) | (7,921 | ) | |||||
Proved reserves, December 31, 2011 (1) | 37,636 | 672,145 | 19,588 | 169,248 | |||||||||
Revisions of previous estimates | (6,729 | ) | (289,436 | ) | (3,671 | ) | (58,639 | ) | |||||
Extensions, discoveries and other additions | 27,482 | 172,933 | 11,637 | 67,941 | |||||||||
Purchases of reserves | 10,801 | 87,212 | 8,084 | 33,420 | |||||||||
Dispositions | (7,854 | ) | (6,406 | ) | (1,970 | ) | (10,891 | ) | |||||
Production | (2,026 | ) | (32,410 | ) | (841 | ) | (8,269 | ) | |||||
Proved reserves, December 31, 2012 (2) | 59,310 | 604,038 | 32,827 | 192,810 | |||||||||
Revisions of previous estimates | (18,420 | ) | (117,068 | ) | (8,549 | ) | (46,480 | ) | |||||
Extensions, discoveries and other additions | 55,759 | 365,563 | 25,249 | 141,935 | |||||||||
Purchases of reserves | 343 | 2,894 | 217 | 1,043 | |||||||||
Dispositions | (252 | ) | (94,927 | ) | (30 | ) | (16,104 | ) | |||||
Production | (2,910 | ) | (20,860 | ) | (1,043 | ) | (7,430 | ) | |||||
Proved reserves, December 31, 2013 | 93,830 | 739,640 | 48,671 | 265,774 | |||||||||
Proved Developed Reserves, as of: | |||||||||||||
January 1, 2011 | 8,287 | 227,341 | 4,013 | 50,190 | |||||||||
December 31, 2011 (1) | 16,910 | 299,369 | 11,753 | 78,558 | |||||||||
December 31, 2012 (2) | 20,412 | 281,925 | 14,353 | 81,753 | |||||||||
31-Dec-13 | 23,997 | 220,387 | 14,825 | 75,553 | |||||||||
Proved Undeveloped Reserves, as of: | |||||||||||||
January 1, 2011 | 14,949 | 429,965 | 6,636 | 93,246 | |||||||||
December 31, 2011 (1) | 20,726 | 372,776 | 7,835 | 90,690 | |||||||||
December 31, 2012 (2) | 38,898 | 322,113 | 18,474 | 111,058 | |||||||||
31-Dec-13 | 69,833 | 519,253 | 33,846 | 190,221 | |||||||||
__________ | |||||||||||||
-1 | Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. | ||||||||||||
-2 | Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. | ||||||||||||
Developed | Undeveloped | Total | |||||||||||
(MBoe) | |||||||||||||
Beginning proved reserves, January 1, 2012 | 78,558 | 90,690 | 169,248 | ||||||||||
Undeveloped reserves converted to developed | 7,655 | (7,655 | ) | — | |||||||||
Revisions of previous estimates | (18,318 | ) | (40,321 | ) | (58,639 | ) | |||||||
Extensions, discoveries and other additions | 11,298 | 56,643 | 67,941 | ||||||||||
Purchases of reserves | 13,542 | 19,878 | 33,420 | ||||||||||
Dispositions | (2,713 | ) | (8,178 | ) | (10,891 | ) | |||||||
Production | (8,269 | ) | — | (8,269 | ) | ||||||||
Ending proved reserves, December 31, 2012 | 81,753 | 111,057 | 192,810 | ||||||||||
Undeveloped reserves converted to developed | 3,212 | (3,212 | ) | — | |||||||||
Revisions of previous estimates | (6,751 | ) | (39,729 | ) | (46,480 | ) | |||||||
Extensions, discoveries and other additions | 19,830 | 122,105 | 141,935 | ||||||||||
Purchases of reserves | 1,043 | — | 1,043 | ||||||||||
Dispositions | (16,104 | ) | — | (16,104 | ) | ||||||||
Production | (7,430 | ) | — | (7,430 | ) | ||||||||
Ending proved reserves, December 31, 2013 | 75,553 | 190,221 | 265,774 | ||||||||||
2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe of which approximately 32 MMBoe is due to adjustments in previous PUD well spacing plans in the Wattenberg Field and the Marcellus Shale, which were offset by replacements in the extension category, approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that are no longer in our core drilling area. This was partially offset by an increase of 1 MMBoe due to higher gas pricing and lower operating costs in the vertical Wattenberg Field wells and horizontal Marcellus Shale wells, an increase of approximately 3 MMBoe due to non-acquisition interest adjustments, approximately 2 MMBoe due to asset performance and approximately 2 MMBoe due to production from wells that were either uneconomic, added or divested in the current year. Discoveries and extensions of approximately 142 MMBoe in 2013 are due to the addition of approximately 17 MMBoe of proved developed reserves from non-PUD drilling and the addition of approximately 125 MMBoe of new proved undeveloped reserves including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and the Marcellus Shale. Approximately 18 MMBoe was added in the Marcellus Shale, approximately 14 MMBoe was added in the Utica Shale and approximately 110 MMBoe was added in the Wattenberg Field, mostly related to the Niobrara and Codell formations. We acquired approximately 1 MMBoe of proved reserves due to an acquisition in the Appalachian-Marcellus Shale area and the acquisition of non-affiliated investor partner interests in shallow Upper Devonian wells. We divested a total of 16 MMBoe in 2013, primarily our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Based on the economic conditions on December 31, 2013, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. Because we will continue to drill both proven and non-proven downspaced Wattenberg Field locations in 2014, our PUD conversion rate is expected to be approximately 7.4%. The balance of the locations are scheduled to be drilled over the remaining four years with total PUD conversion rates of 22% in 2015, 27% in 2016, 24% in 2017 and 19% in 2018. This level of capital spending is consistent with the most recent years and our guidance for future activity. | |||||||||||||
2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 59 MMBoe. The revision was primarily due to a decrease of approximately 40 MMBoe due to lower gas pricing, mostly related to the Piceance Basin, approximately 1 MMBoe due to increased operating costs, approximately 8 MMBoe due to adjustments for geological reasons and approximately 13 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 0.5 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. Discoveries and extensions of approximately 68 MMBoe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 10 MMBoe were added in the Marcellus Shale and approximately 59 MMBoe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 33 MMBoe of proved reserves due to an acquisition in the Wattenberg Field. We divested a total of 11 MMBoe in 2012, primarily our core Permian Basin assets. Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 reserve report. | |||||||||||||
2011 Activity. In 2011, we recorded a downward revision of our previous estimate of proved reserves of approximately 26 MMBoe. The revision was primarily due to a decrease of approximately 0.7 MMBoe due to lower gas pricing and approximately 29 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 1 MMBoe due to increased efficiencies in operating costs, approximately 0.8 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. In addition, the “Revisions of previous estimates” line item includes a deduction in the “Undeveloped” column and an increase in the “Developed” column of approximately 21 MMBoe. These reserves were transferred from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture became less significant as compared to the costs associated with drilling a new well. Discoveries and extensions of approximately 52 MMboe in 2012 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 9 MMBoe were added in the Marcellus Shale, approximately 24 MMBoe in the Wattenberg Field, 13 MMBoe in the Piceance Basin and 7 MMBoe in the Permian Basin. We acquired approximately 8 MMboe of proved reserves, approximately 1 MMBoe through acquisitions in the Marcellus Shale, approximately 5 MMBoe in the Wattenberg Field and 2 MMBoe in the Piceance Basin due to the repurchase of the 2003/2002-D and 2005 Partnerships as well as the purchase of interests in some of our other existing properties. We divested a total of approximately 0.8 MMBoe in 2012. This included the sale of 100% of our North Dakota assets, or 0.3 MMBoe, to an unrelated third-party and our non-core Permian Basin assets, or 0.5 MMBoe, to unrelated third parties. | |||||||||||||
Results of Operations for Crude Oil and Natural Gas Producing Activities | |||||||||||||
The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Revenue: | |||||||||||||
Crude oil, natural gas and NGLs sales | $ | 379,796 | $ | 274,783 | $ | 304,157 | |||||||
Commodity price risk management gain, net | (23,905 | ) | 32,339 | 46,090 | |||||||||
355,891 | 307,122 | 350,247 | |||||||||||
Expenses: | |||||||||||||
Production costs | 81,365 | 77,537 | 75,717 | ||||||||||
Exploration expense | 7,071 | 22,605 | 6,289 | ||||||||||
Impairment of proved crude oil and natural gas properties | 53,438 | 162,287 | 25,159 | ||||||||||
Depreciation, depletion, and amortization | 124,202 | 146,879 | 128,458 | ||||||||||
Accretion of asset retirement obligations | 4,747 | 4,060 | 1,897 | ||||||||||
(Gain) loss on sale of properties and equipment | 3,722 | (24,273 | ) | (4,050 | ) | ||||||||
274,545 | 389,095 | 233,470 | |||||||||||
Results of operations for crude oil and natural gas producing | 81,346 | (81,973 | ) | 116,777 | |||||||||
activities before provision for income taxes | |||||||||||||
Provision for income taxes | (29,400 | ) | 31,163 | (36,785 | ) | ||||||||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs | $ | 51,946 | $ | (50,810 | ) | $ | 79,992 | ||||||
Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. | |||||||||||||
Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities | |||||||||||||
Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Acquisition of properties: (1) | |||||||||||||
Proved properties | $ | 28,698 | $ | 105,303 | $ | 79,554 | |||||||
Unproved properties | 3,390 | 276,225 | 95,081 | ||||||||||
Development costs (2) | 332,250 | 233,144 | 301,008 | ||||||||||
Exploration costs: (3) | |||||||||||||
Exploratory drilling | 58,988 | 18,803 | 3,626 | ||||||||||
Geological and geophysical | 752 | 1,925 | 1,846 | ||||||||||
Total costs incurred | $ | 424,078 | $ | 635,400 | $ | 481,115 | |||||||
__________ | |||||||||||||
-1 | Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. | ||||||||||||
-2 | Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2013, 2012 and 2011, $40.1 million, $62.0 million and $80.6 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. | ||||||||||||
-3 | Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. | ||||||||||||
Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities | |||||||||||||
Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: | |||||||||||||
As of December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
(in thousands) | |||||||||||||
Proved crude oil and natural gas properties | $ | 1,781,681 | $ | 2,075,924 | |||||||||
Unproved crude oil and natural gas properties | 307,203 | 319,327 | |||||||||||
Uncompleted wells, equipment and facilities | 51,773 | 62,392 | |||||||||||
Capitalized costs | 2,140,657 | 2,457,643 | |||||||||||
Less accumulated DD&A | (529,607 | ) | (905,458 | ) | |||||||||
Capitalized costs, net | $ | 1,611,050 | $ | 1,552,185 | |||||||||
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves | |||||||||||||
The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. | |||||||||||||
The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. | |||||||||||||
As of December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Future estimated cash flows | $ | 11,550,917 | $ | 7,529,292 | $ | 6,415,255 | |||||||
Future estimated production costs | (2,329,836 | ) | (1,690,453 | ) | (1,704,645 | ) | |||||||
Future estimated development costs | (2,778,148 | ) | (1,852,177 | ) | (1,474,137 | ) | |||||||
Future estimated income tax expense | (2,119,615 | ) | (1,230,294 | ) | (946,849 | ) | |||||||
Future net cash flows | 4,323,318 | 2,756,368 | 2,289,624 | ||||||||||
10% annual discount for estimated timing of cash flows | (2,541,155 | ) | (1,587,871 | ) | (1,348,415 | ) | |||||||
Standardized measure of discounted future estimated net cash flows | $ | 1,782,163 | $ | 1,168,497 | $ | 941,209 | |||||||
The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Sales of crude oil, natural gas and NGLs production, net of production costs | $ | (286,021 | ) | $ | (194,346 | ) | $ | (226,227 | ) | ||||
Net changes in prices and production costs (1) | 89,527 | 95,501 | 383,293 | ||||||||||
Extensions, discoveries, and improved recovery, less related costs (2) | 1,529,006 | 632,781 | 467,347 | ||||||||||
Sales of reserves (3) | (142,724 | ) | (86,902 | ) | (4,224 | ) | |||||||
Purchases of reserves (4) | 10,610 | 296,208 | 64,761 | ||||||||||
Development costs incurred during the period | 46,366 | 69,198 | 94,941 | ||||||||||
Revisions of previous quantity estimates (5) | (397,738 | ) | (452,775 | ) | (112,468 | ) | |||||||
Changes in estimated income taxes (6) | (381,369 | ) | (131,256 | ) | (204,377 | ) | |||||||
Net changes in future development costs | (40,707 | ) | (3,979 | ) | (29,827 | ) | |||||||
Accretion of discount | 142,040 | 124,105 | 65,284 | ||||||||||
Timing and other | 44,676 | (121,247 | ) | (45,712 | ) | ||||||||
Total | $ | 613,666 | $ | 227,288 | $ | 452,791 | |||||||
__________ | |||||||||||||
-1 | Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves. | ||||||||||||
-2 | The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. | ||||||||||||
-3 | The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012. | ||||||||||||
-4 | The decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field. | ||||||||||||
-5 | The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. | ||||||||||||
-6 | The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0%, 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. | ||||||||||||
The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. |
SUPPLEMENTAL_INFORMATION_QUART
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Quarterly Financial Data [Abstract] | ' | |||||||||||||||||||
Quarterly Financial Information [Text Block] | ' | |||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION - UNAUDITED | ||||||||||||||||||||
Quarterly financial data for the years ended December 31, 2013 and 2012 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. | ||||||||||||||||||||
2013 | ||||||||||||||||||||
Quarter Ended | ||||||||||||||||||||
31-Mar | 30-Jun | 30-Sep | 31-Dec | Year Ended | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Crude oil, natural gas and NGLs sales | $ | 79,439 | $ | 77,537 | $ | 82,136 | $ | 120,286 | $ | 359,398 | ||||||||||
Sales from natural gas marketing | 13,670 | 18,079 | 16,946 | 21,092 | 69,787 | |||||||||||||||
Commodity price risk management gain (loss), net | (22,355 | ) | 24,724 | (23,638 | ) | (2,636 | ) | (23,905 | ) | |||||||||||
Well operations, pipeline income and other | 1,072 | 965 | 1,672 | 2,325 | 6,034 | |||||||||||||||
Total revenues | 71,826 | 121,305 | 77,116 | 141,067 | 411,314 | |||||||||||||||
Costs, expenses and other: | ||||||||||||||||||||
Production costs | 15,858 | 16,176 | 19,057 | 22,299 | 73,390 | |||||||||||||||
Cost of natural gas marketing | 13,736 | 18,065 | 17,127 | 21,156 | 70,084 | |||||||||||||||
Exploration expense | 1,689 | 1,437 | 2,030 | 1,883 | 7,039 | |||||||||||||||
Impairment of crude oil and natural gas properties | 46,459 | 1,502 | 4,472 | 1,002 | 53,435 | |||||||||||||||
General and administrative expense | 15,115 | 15,783 | 16,080 | 16,991 | 63,969 | |||||||||||||||
Depreciation, depletion and amortization | 27,949 | 27,800 | 30,870 | 40,641 | 127,260 | |||||||||||||||
Accretion of asset retirement obligations | 1,148 | 1,172 | 1,186 | 1,080 | 4,586 | |||||||||||||||
(Gain) loss on sale of properties and equipment | (38 | ) | (9 | ) | (712 | ) | 2,151 | 1,392 | ||||||||||||
Total costs, expenses and other | 121,916 | 81,926 | 90,110 | 107,203 | 401,155 | |||||||||||||||
Income (loss) from operations | (50,090 | ) | 39,379 | (12,994 | ) | 33,864 | 10,159 | |||||||||||||
Interest expense | (13,357 | ) | (13,089 | ) | (12,509 | ) | (12,943 | ) | (51,898 | ) | ||||||||||
Interest income | — | 3 | 130 | 337 | 470 | |||||||||||||||
Income (loss) from continuing operations before income taxes | (63,447 | ) | 26,293 | (25,373 | ) | 21,258 | (41,269 | ) | ||||||||||||
Provision for income taxes | 22,492 | (9,791 | ) | 10,155 | (8,059 | ) | 14,797 | |||||||||||||
Income (loss) from continuing operations | (40,955 | ) | 16,502 | (15,218 | ) | 13,199 | (26,472 | ) | ||||||||||||
Income (loss) from discontinued operations, net of tax | 1,537 | 3,416 | (782 | ) | — | 4,171 | ||||||||||||||
Net income (loss) | $ | (39,418 | ) | $ | 19,918 | $ | (16,000 | ) | $ | 13,199 | $ | (22,301 | ) | |||||||
Earnings per share: | ||||||||||||||||||||
Basic | ||||||||||||||||||||
Income (loss) from continuing operations | $ | (1.35 | ) | $ | 0.55 | $ | (0.46 | ) | $ | 0.37 | $ | (0.82 | ) | |||||||
Income (loss) from discontinued operations | 0.05 | 0.11 | (0.02 | ) | — | 0.13 | ||||||||||||||
Net income (loss) | $ | (1.30 | ) | $ | 0.66 | $ | (0.48 | ) | $ | 0.37 | $ | (0.69 | ) | |||||||
Diluted | ||||||||||||||||||||
Income (loss) from continuing operations | $ | (1.35 | ) | $ | 0.53 | $ | (0.46 | ) | $ | 0.36 | $ | (0.82 | ) | |||||||
Income (loss) from discontinued operations | 0.05 | 0.11 | (0.02 | ) | — | 0.13 | ||||||||||||||
Net income (loss) | $ | (1.30 | ) | $ | 0.64 | $ | (0.48 | ) | $ | 0.36 | $ | (0.69 | ) | |||||||
Weighted-average common shares outstanding: | ||||||||||||||||||||
Basic | 30,270 | 30,332 | 33,413 | 35,620 | 32,426 | |||||||||||||||
Diluted | 30,270 | 31,014 | 33,413 | 36,836 | 32,426 | |||||||||||||||
2012 | ||||||||||||||||||||
Quarter Ended | ||||||||||||||||||||
31-Mar | 30-Jun | 30-Sep | 31-Dec | Year Ended | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Crude oil, natural gas and NGLs sales | $ | 66,955 | $ | 51,342 | $ | 52,291 | $ | 67,773 | $ | 238,361 | ||||||||||
Sales from natural gas marketing | 11,381 | 8,613 | 11,178 | 14,199 | 45,371 | |||||||||||||||
Commodity price risk management gain (loss), net | 11,501 | 38,729 | (31,943 | ) | 14,052 | 32,339 | ||||||||||||||
Well operations, pipeline income and other | 1,169 | 1,056 | 1,194 | 1,115 | 4,534 | |||||||||||||||
Total revenues | 91,006 | 99,740 | 32,720 | 97,139 | 320,605 | |||||||||||||||
Costs, expenses and other: | ||||||||||||||||||||
Production costs | 12,936 | 12,373 | 15,797 | 13,594 | 54,700 | |||||||||||||||
Cost of natural gas marketing | 11,091 | 8,490 | 11,260 | 14,182 | 45,023 | |||||||||||||||
Exploration expense | 1,872 | 2,374 | 1,773 | 14,875 | 20,894 | |||||||||||||||
Impairment of crude oil and natural gas properties | 588 | 356 | 388 | 4,563 | 5,895 | |||||||||||||||
General and administrative expense | 14,708 | 14,378 | 13,710 | 16,019 | 58,815 | |||||||||||||||
Depreciation, depletion and amortization | 27,912 | 23,839 | 22,121 | 24,906 | 98,778 | |||||||||||||||
Accretion of asset retirement obligations | 727 | 732 | 1,101 | 1,127 | 3,687 | |||||||||||||||
Gain on sale of properties and equipment | (154 | ) | (2,246 | ) | (1,508 | ) | (445 | ) | (4,353 | ) | ||||||||||
Total costs, expenses and other | 69,680 | 60,296 | 64,642 | 88,821 | 283,439 | |||||||||||||||
Income (loss) from operations | 21,326 | 39,444 | (31,922 | ) | 8,318 | 37,166 | ||||||||||||||
Loss on extinguishment of debt | — | — | — | (23,283 | ) | (23,283 | ) | |||||||||||||
Interest expense | (10,444 | ) | (10,053 | ) | (11,360 | ) | (16,430 | ) | (48,287 | ) | ||||||||||
Interest income | 2 | — | 3 | 3 | 8 | |||||||||||||||
Income (loss) from continuing operations before income taxes | 10,884 | 29,391 | (43,279 | ) | (31,392 | ) | (34,396 | ) | ||||||||||||
Provision for income taxes | (4,120 | ) | (10,213 | ) | 15,268 | 11,766 | 12,701 | |||||||||||||
Income (loss) from continuing operations | 6,764 | 19,178 | (28,011 | ) | (19,626 | ) | (21,695 | ) | ||||||||||||
Income (loss) from discontinued operations, net of tax | 9,071 | (6,907 | ) | (4,632 | ) | (106,549 | ) | (109,017 | ) | |||||||||||
Net income (loss) | $ | 15,835 | $ | 12,271 | $ | (32,643 | ) | $ | (126,175 | ) | $ | (130,712 | ) | |||||||
Earnings per share: | ||||||||||||||||||||
Basic | ||||||||||||||||||||
Income (loss) from continuing operations | $ | 0.29 | $ | 0.72 | $ | (0.93 | ) | $ | (0.65 | ) | $ | (0.78 | ) | |||||||
Income (loss) from discontinued operations | 0.38 | (0.26 | ) | (0.15 | ) | (3.52 | ) | (3.94 | ) | |||||||||||
Net income (loss) attributable to shareholders | $ | 0.67 | $ | 0.46 | $ | (1.08 | ) | $ | (4.17 | ) | $ | (4.72 | ) | |||||||
Diluted | ||||||||||||||||||||
Income (loss) from continuing operations | $ | 0.28 | $ | 0.72 | $ | (0.93 | ) | $ | (0.65 | ) | $ | (0.78 | ) | |||||||
Income (loss) from discontinued operations | 0.38 | (0.26 | ) | (0.15 | ) | (3.52 | ) | (3.94 | ) | |||||||||||
Net income (loss) attributable to shareholders | $ | 0.66 | $ | 0.46 | $ | (1.08 | ) | $ | (4.17 | ) | $ | (4.72 | ) | |||||||
Weighted-average common shares outstanding | ||||||||||||||||||||
Basic | 23,609 | 26,597 | 30,214 | 30,233 | 27,677 | |||||||||||||||
Diluted | 23,889 | 26,728 | 30,214 | 30,233 | 27,677 | |||||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
Accounting Policies [Abstract] | ' |
Consolidation, Policy [Policy Text Block] | ' |
The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries and our proportionate share of PDC Mountaineer, LLC and our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. | |
Use of Estimates, Policy [Policy Text Block] | ' |
The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments and valuation of deferred income tax assets | |
Cash and Cash Equivalents, Policy [Policy Text Block] | ' |
We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. | |
Inventory, Policy [Policy Text Block] | ' |
Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. | |
Derivative Financial Instruments, Policy [Policy Text Block] | ' |
All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the consolidated balance sheets in accounts receivable affiliates and accounts payable affiliates. As positions designated to our affiliated partnerships mature, the cash settlements are netted for distribution. Net settlements are paid to the partnerships or deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. As of December 31, 2013, our affiliated partnerships had no outstanding derivative instruments. | |
The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. | |
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block] | ' |
We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly DD&A expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. | |
Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. | |
Proved and Unproved Property, Impairment [Policy Text Block] | ' |
The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statement of operations line item impairment of crude oil and natural gas properties. | |
e assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. | |
Property, Plant and Equipment, Policy [Policy Text Block] | ' |
Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. | |
Interest Capitalization, Policy [Policy Text Block] | ' |
Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. | |
Assets Held For Sale, Policy [Policy Text Block] | ' |
Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. | |
Production Tax Liability, Policy [Policy Text Block] | ' |
Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. | |
Income Tax, Policy [Policy Text Block] | ' |
We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. | |
Debt Issuance Costs, Policy [Policy Text Block] | ' |
Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. | |
Asset Retirement Obligations, Policy [Policy Text Block] | ' |
We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. | |
Treasury Shares, Policy [Policy Text Block] | ' |
We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. | |
Revenue Recognition, Policy [Policy Text Block] | ' |
Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in the Wattenberg Field are sold on a long-term basis, primarily over the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under short-term contracts of less than one year. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas. | |
Well operations and pipeline income. We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. | |
Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. | |
Accounting for Acquisitions using Purchase Accounting [Policy Text Block] | ' |
We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. | |
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. | |
We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. | |
Stock-Based Compensation, Policy [Policy Text Block] | ' |
Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statement of operations. | |
Earnings Per Share, Policy [Policy Text Block] | ' |
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. | |
Accounting Standards Recently Adopted [Policy Text Block] | ' |
Recently Adopted Accounting Standard. On January 1, 2013, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on the entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the consolidated financial statements, except for additional disclosures. | |
Accounting Standards Recently Issued [Policy Text Block] | ' |
Recently Issued Accounting Standard. On July 18, 2013, the FASB issued an update to accounting for income taxes. The update provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The update is effective for public entities for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. We are currently evaluating the impact of adopting this update on our financial statements, but do not believe it will have a material impact. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables) | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Property, Plant and Equipment, Estimated Useful Lives [Table Text Block] | ' | |
Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment to other property and equipment was recognized in 2013, 2012 or 2011. | ||
The following table presents the estimated useful lives of our other property and equipment: | ||
Pipelines and related facilities | 10 - 17 years | |
Transportation and other equipment | 3 - 20 years | |
Buildings | 20 - 30 years |
FAIR_VALUE_MEASUREMENTS_AND_DI1
FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | ' | |||||||||||||||||||||||
The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: | ||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||
Significant Other | Significant | Total | Significant Other | Significant | Total | |||||||||||||||||||
Observable | Unobservable | Observable | Unobservable | |||||||||||||||||||||
Inputs | Inputs | Inputs | Inputs | |||||||||||||||||||||
(Level 2) | (Level 3) | (Level 2) | (Level 3) | |||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Commodity-based derivative contracts | $ | 5,325 | $ | 2,385 | $ | 7,710 | $ | 42,798 | $ | 15,750 | $ | 58,548 | ||||||||||||
Basis protection derivative contracts | 463 | — | 463 | 377 | — | 377 | ||||||||||||||||||
Total assets | 5,788 | 2,385 | 8,173 | 43,175 | 15,750 | 58,925 | ||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Commodity-based derivative contracts | 17,537 | 988 | 18,525 | 9,839 | 2,081 | 11,920 | ||||||||||||||||||
Basis protection derivative contracts | 5 | — | 5 | 16,656 | — | 16,656 | ||||||||||||||||||
Total liabilities | 17,542 | 988 | 18,530 | 26,495 | 2,081 | 28,576 | ||||||||||||||||||
Net asset (liability) | $ | (11,754 | ) | $ | 1,397 | $ | (10,357 | ) | $ | 16,680 | $ | 13,669 | $ | 30,349 | ||||||||||
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block] | ' | |||||||||||||||||||||||
The following table presents a reconciliation of our Level 3 assets measured at fair value: | ||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Fair value, net asset, beginning of period | $ | 13,669 | $ | 22,107 | $ | 10,762 | ||||||||||||||||||
Changes in fair value included in statement of operations line item: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | (1,521 | ) | 7,576 | 13,487 | ||||||||||||||||||||
Sales from natural gas marketing | 13 | 63 | 114 | |||||||||||||||||||||
Changes in fair value included in balance sheet line item (1): | ||||||||||||||||||||||||
Accounts receivable affiliates | — | — | 49 | |||||||||||||||||||||
Accounts payable affiliates | — | (319 | ) | (454 | ) | |||||||||||||||||||
Settlements included in statement of operations line items: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | (6,361 | ) | (15,644 | ) | (1,712 | ) | ||||||||||||||||||
Sales from natural gas marketing | (37 | ) | (114 | ) | (139 | ) | ||||||||||||||||||
Income (loss) from discontinued operations, net of tax | (4,366 | ) | — | — | ||||||||||||||||||||
Fair value, net asset end of period | $ | 1,397 | $ | 13,669 | $ | 22,107 | ||||||||||||||||||
Net change in fair value of unsettled derivatives included in statement of operations line item: | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | $ | (1,032 | ) | $ | 3,665 | $ | 11,669 | |||||||||||||||||
Sales from natural gas marketing | 4 | 1 | (3 | ) | ||||||||||||||||||||
Total | $ | (1,028 | ) | $ | 3,666 | $ | 11,666 | |||||||||||||||||
__________ | ||||||||||||||||||||||||
-1 | Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. |
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | ' | ||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||
The following table presents the location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2013 and 2012: | |||||||||||||
Derivatives instruments: | Balance sheet line item | 2013 | 2012 | ||||||||||
(in thousands) | |||||||||||||
Derivative assets: | Current | ||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 2,016 | $ | 46,657 | ||||||||
Related to affiliated partnerships (1) | Fair value of derivatives | — | 4,707 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 361 | 319 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 195 | 359 | ||||||||||
2,572 | 52,042 | ||||||||||||
Non Current | |||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 5,055 | 6,653 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 278 | 212 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 268 | 18 | ||||||||||
5,601 | 6,883 | ||||||||||||
Total derivative assets | $ | 8,173 | $ | 58,925 | |||||||||
Derivative liabilities: | Current | ||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 15,263 | $ | 1,698 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 247 | 226 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | — | 14,375 | ||||||||||
Related to affiliated partnerships (2) | Fair value of derivatives | — | 2,140 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 5 | — | ||||||||||
15,515 | 18,439 | ||||||||||||
Non Current | |||||||||||||
Commodity contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 2,782 | 9,828 | ||||||||||
Related to natural gas marketing | Fair value of derivatives | 233 | 168 | ||||||||||
Basis protection contracts | |||||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | — | 141 | ||||||||||
3,015 | 10,137 | ||||||||||||
Total derivative liabilities | $ | 18,530 | $ | 28,576 | |||||||||
__________ | |||||||||||||
-1 | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. | ||||||||||||
-2 | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. | ||||||||||||
The following table presents the impact of our derivative instruments on our consolidated statements of operations: | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statement of operations line item | 2013 | 2012 | 2011 | ||||||||||
Commodity price risk management gain (loss), net | |||||||||||||
Net settlements | $ | 12,913 | $ | 49,416 | $ | 17,243 | |||||||
Net change in fair value of unsettled derivatives | (36,818 | ) | (17,077 | ) | 28,847 | ||||||||
Total commodity price risk management gain (loss), net | $ | (23,905 | ) | $ | 32,339 | $ | 46,090 | ||||||
Sales from natural gas marketing | |||||||||||||
Net settlements | $ | 446 | $ | 2,170 | $ | 2,970 | |||||||
Net change in fair value of unsettled derivatives | 429 | (1,658 | ) | (161 | ) | ||||||||
Total sales from natural gas marketing | $ | 875 | $ | 512 | $ | 2,809 | |||||||
Cost of natural gas marketing | |||||||||||||
Net settlements | $ | (257 | ) | $ | (2,029 | ) | $ | (2,571 | ) | ||||
Net change in fair value of unsettled derivatives | (412 | ) | 1,601 | (85 | ) | ||||||||
Total cost of natural gas marketing | $ | (669 | ) | $ | (428 | ) | $ | (2,656 | ) | ||||
All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. | |||||||||||||
The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of December 31, 2013 and 2012: | |||||||||||||
As of December 31, 2013 | Derivatives instruments, recorded in consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | ||||||||||
(in thousands) | |||||||||||||
Asset derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 8,173 | $ | (5,623 | ) | $ | 2,550 | ||||||
Liability derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 18,530 | $ | (5,623 | ) | $ | 12,907 | ||||||
As of December 31, 2012 | Derivatives instruments, recorded in consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | ||||||||||
(in thousands) | |||||||||||||
Asset derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 58,925 | $ | (11,437 | ) | $ | 47,488 | ||||||
Liability derivatives: | |||||||||||||
Derivative instruments, at fair value | $ | 28,576 | $ | (11,437 | ) | $ | 17,139 | ||||||
CONCENTRATION_OF_RISK_Accounts
CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Concentration Risks, Types, No Concentration Percentage [Abstract] | ' | |||||||||
Account Receivable, net of Allowance for Doubtful Accounts [Table Text Block] | ' | |||||||||
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: | ||||||||||
As of December 31, | ||||||||||
2013 | 2012 | |||||||||
(in thousands) | ||||||||||
Crude oil, natural gas and NGLs sales | $ | 66,257 | $ | 39,837 | ||||||
Joint interest billings | 20,558 | 6,896 | ||||||||
Natural gas marketing | 6,210 | 8,209 | ||||||||
Reimbursements for title defects | — | 7,579 | ||||||||
Other | 2,321 | 3,385 | ||||||||
Allowance for doubtful accounts | (1,261 | ) | (1,026 | ) | ||||||
Accounts receivable, net | $ | 94,085 | $ | 64,880 | ||||||
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block] | ' | |||||||||
Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: | ||||||||||
Year Ended December 31, | ||||||||||
Customer | 2013 | 2012 | 2011 | |||||||
Suncor Energy Marketing, Inc. | 31.3 | % | 29.8 | % | 25.7 | % | ||||
DCP Midstream, LP | 14.6 | % | 12.2 | % | 11.5 | % | ||||
Fair Value, Concentration of Risk [Table Text Block] | ' | |||||||||
The following table presents the counterparties that expose us to credit risk as of December 31, 2013, with regard to our derivative assets: | ||||||||||
Fair Value of | ||||||||||
Derivative Assets | ||||||||||
Counterparty Name | As of December 31, 2013 | |||||||||
(in thousands) | ||||||||||
Wells Fargo Bank, N.A. (1) | $ | 2,496 | ||||||||
Bank of Montreal (1) | 1,102 | |||||||||
Canadian Imperial Bank of Commerce (1) | 1,054 | |||||||||
Other lenders in our revolving credit facility | 3,380 | |||||||||
Various (2) | 141 | |||||||||
Total | $ | 8,173 | ||||||||
____________ | ||||||||||
(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt. | ||||||||||
(2)Represents a total of 19 counterparties. |
PROPERTIES_AND_EQUIPMENT_Prope
PROPERTIES AND EQUIPMENT Properties and Equipment (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Property, Plant and Equipment [Abstract] | ' | |||||||||||
Property, Plant and Equipment [Table Text Block] | ' | |||||||||||
The following table presents the components of properties and equipment, net of accumulated DD&A: | ||||||||||||
As of December 31, | ||||||||||||
2013 | 2012 | |||||||||||
(in thousands) | ||||||||||||
Properties and equipment, net: | ||||||||||||
Crude oil and natural gas properties | ||||||||||||
Proved | $ | 1,781,681 | $ | 2,075,924 | ||||||||
Unproved | 307,203 | 319,327 | ||||||||||
Total crude oil and natural gas properties | 2,088,884 | 2,395,251 | ||||||||||
Pipelines and related facilities | 21,781 | 47,786 | ||||||||||
Equipment and other | 29,246 | 34,858 | ||||||||||
Land and buildings | 13,617 | 14,935 | ||||||||||
Construction in progress | 53,810 | 67,217 | ||||||||||
Gross properties and equipment | 2,207,338 | 2,560,047 | ||||||||||
Accumulated DD&A | (553,893 | ) | (943,341 | ) | ||||||||
Properties and equipment, net | $ | 1,653,445 | $ | 1,616,706 | ||||||||
Impairment of natural gas and crude oil properties [Table Text Block] | ' | |||||||||||
The following table presents impairment charges recorded for crude oil and natural gas properties: | ||||||||||||
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Continuing operations: | ||||||||||||
Impairment of proved properties | $ | 48,750 | $ | — | $ | — | ||||||
Impairment of individually significant unproved properties | 1,082 | 1,629 | 1,108 | |||||||||
Amortization of individually insignificant unproved properties | 3,603 | 4,266 | 1,193 | |||||||||
Total continuing operations | 53,435 | 5,895 | 2,301 | |||||||||
Discontinued operations: | ||||||||||||
Impairment of proved properties | — | 161,185 | 22,460 | |||||||||
Impairment of individually significant unproved properties | — | 313 | — | |||||||||
Amortization of individually insignificant unproved properties | 3 | 756 | 398 | |||||||||
Total discontinued operations | 3 | 162,254 | 22,858 | |||||||||
Total impairment of crude oil and natural gas properties | $ | 53,438 | $ | 168,149 | $ | 25,159 | ||||||
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block] | ' | |||||||||||
The following table presents the capitalized exploratory well costs pending determination of proved reserves, and included in properties and equipment on the consolidated balance sheets: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands, except for number of wells) | ||||||||||||
Balance beginning of year, January 1, | $ | 19,567 | $ | 4,432 | $ | 2,297 | ||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 13,424 | 30,482 | 3,692 | |||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | (32,991 | ) | — | (1,557 | ) | |||||||
Capitalized exploratory well costs charged to expense | — | (15,347 | ) | — | ||||||||
Balance end of year, December 31, | $ | — | $ | 19,567 | $ | 4,432 | ||||||
Number of wells pending determination at December 31, | — | 2 | 6 | |||||||||
Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block] | ' | |||||||||||
The following table presents an aging of capitalized exploratory well costs based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling: | ||||||||||||
As of December 31, | ||||||||||||
2012 | 2011 | |||||||||||
(in thousands) | ||||||||||||
Exploratory well costs capitalized for a period of one year or less | $ | 19,567 | $ | 3,587 | ||||||||
Exploratory well costs capitalized for a period greater than one year since commencement of drilling | — | 845 | ||||||||||
Balance end of year, December 31, | $ | 19,567 | $ | 4,432 | ||||||||
Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling | — | 2 | ||||||||||
INCOME_TAXES_Income_Taxes_Tabl
INCOME TAXES Income Taxes (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Income Tax Disclosure [Abstract] | ' | |||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | ' | |||||||||||
The table below presents the components of our provision for income taxes from continuing operations for the years presented: | ||||||||||||
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Current: | ||||||||||||
Federal | $ | 1,355 | $ | — | $ | 2,594 | ||||||
State | 199 | (199 | ) | 750 | ||||||||
Total current income taxes | 1,554 | (199 | ) | 3,344 | ||||||||
Deferred: | ||||||||||||
Federal | 11,145 | 12,133 | (13,309 | ) | ||||||||
State | 2,098 | 767 | (1,835 | ) | ||||||||
Total deferred income taxes | 13,243 | 12,900 | (15,144 | ) | ||||||||
Income tax benefit (expense) from continuing operations | $ | 14,797 | $ | 12,701 | $ | (11,800 | ) | |||||
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | ' | |||||||||||
The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: | ||||||||||||
Year Ended December, 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Statutory tax rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net | 3.3 | 1 | 2 | |||||||||
Percentage depletion | 1.8 | 1.9 | (2.5 | ) | ||||||||
Non-deductible compensation | (3.4 | ) | (0.5 | ) | — | |||||||
Non-deductible meals and entertainment | (0.5 | ) | (0.5 | ) | 0.3 | |||||||
State deferred rate change | — | — | 1.3 | |||||||||
Unrecognized tax benefits | (0.1 | ) | — | (2.6 | ) | |||||||
Federal return examination adjustments | — | — | 0.4 | |||||||||
Return to provision adjustments | (0.5 | ) | — | 0.3 | ||||||||
Other | 0.3 | — | 0.1 | |||||||||
Effective tax rate | 35.9 | % | 36.9 | % | 34.3 | % | ||||||
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | ' | |||||||||||
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are presented below: | ||||||||||||
As of December 31, | ||||||||||||
2013 | 2012 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax assets: | ||||||||||||
Net change in fair value of unsettled derivatives | $ | 6,205 | $ | — | ||||||||
Deferred compensation | 8,507 | 7,216 | ||||||||||
Asset retirement obligations | 11,630 | 10,325 | ||||||||||
State NOL and tax credit carryforwards, net | 5,182 | 6,117 | ||||||||||
Percentage depletion - carryforward | 4,570 | 4,702 | ||||||||||
Alternative minimum tax - credit carryforward | 3,165 | 2,351 | ||||||||||
Federal NOL carryforward | 4,601 | 21,281 | ||||||||||
Other | 6,229 | 2,276 | ||||||||||
Deferred tax assets | 50,089 | 54,268 | ||||||||||
Deferred tax liabilities: | ||||||||||||
Properties and equipment | 120,746 | 122,742 | ||||||||||
Investment in PDCM | 21,962 | 31,445 | ||||||||||
Net change in fair value of unsettled derivatives | — | 7,163 | ||||||||||
Convertible debt | 3,774 | 5,194 | ||||||||||
Total gross deferred tax liabilities | 146,482 | 166,544 | ||||||||||
Net deferred tax liability | $ | 96,393 | $ | 112,276 | ||||||||
Classification in the consolidated balance sheets: | ||||||||||||
Deferred income tax assets | $ | 22,374 | $ | 36,151 | ||||||||
Deferred income tax liability | 118,767 | 148,427 | ||||||||||
Net deferred tax liability | $ | 96,393 | $ | 112,276 | ||||||||
LONGTERM_DEBT_LONGTERM_DEBT_Ta
LONG-TERM DEBT LONG-TERM DEBT (Tables) | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Long-term Debt, Unclassified [Abstract] | ' | |||||||
Schedule of Long-term Debt Instruments [Table Text Block] | ' | |||||||
Long-term debt consists of the following: | ||||||||
As of December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Senior notes: | ||||||||
3.25% Convertible senior notes due 2016: | ||||||||
Principal amount | $ | 115,000 | $ | 115,000 | ||||
Unamortized discount | (10,010 | ) | (13,671 | ) | ||||
3.25% Convertible senior notes due 2016, net of discount | 104,990 | 101,329 | ||||||
7.75% Senior notes due 2022: | ||||||||
7.75% Senior notes due 2022 | 500,000 | 500,000 | ||||||
Total senior notes | 604,990 | 601,329 | ||||||
Credit facilities: | ||||||||
Corporate | — | 49,000 | ||||||
PDCM | 37,000 | 26,250 | ||||||
Total credit facilities | 37,000 | 75,250 | ||||||
PDCM second lien term loan | 15,000 | — | ||||||
Long-term debt | $ | 656,990 | $ | 676,579 | ||||
ASSET_RETIREMENT_OBLIGATIONS_A
ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | |||||||
Schedule of Change in Asset Retirement Obligation [Table Text Block] | ' | |||||||
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Balance at beginning of year, January 1 | $ | 62,563 | $ | 46,566 | ||||
Obligations incurred with development activities and assumed with acquisitions | 2,389 | 14,169 | ||||||
Accretion expense | 4,747 | 4,060 | ||||||
Revisions in estimated cash flows | 612 | — | ||||||
Obligations discharged with divestitures of properties and asset retirements (1) | (29,281 | ) | (2,232 | ) | ||||
Balance end of year, December 31 | 41,030 | 62,563 | ||||||
Less: Liabilities held for sale (1) | (2,061 | ) | — | |||||
Less: Current portion | (1,158 | ) | (1,000 | ) | ||||
Long-term portion | $ | 37,811 | $ | 61,563 | ||||
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||||||||||||||
Supply Commitment [Table Text Block] | ' | ||||||||||||||||||||||||||||
The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity: | |||||||||||||||||||||||||||||
Year Ending December 31, | |||||||||||||||||||||||||||||
Area | 2014 | 2015 | 2016 | 2017 | 2018 and | Total | Expiration | ||||||||||||||||||||||
Through | Date | ||||||||||||||||||||||||||||
Expiration | |||||||||||||||||||||||||||||
Volume (MMcf) | |||||||||||||||||||||||||||||
Appalachia-Marcellus Shale | 18,212 | 19,485 | 21,044 | 20,987 | 125,336 | 205,064 | January 31, 2026 | ||||||||||||||||||||||
Utica Shale | 2,454 | 2,738 | 2,745 | 2,737 | 15,285 | 25,959 | July 22, 2023 | ||||||||||||||||||||||
Total | 20,666 | 22,223 | 23,789 | 23,724 | 140,621 | 231,023 | |||||||||||||||||||||||
Dollar commitment (in thousands) | $ | 7,547 | $ | 7,907 | $ | 8,230 | $ | 7,790 | $ | 38,526 | $ | 70,000 | |||||||||||||||||
Schedule of Minimum Future Lease Payments under the Non-cancelable Operating Leases [Table Text Block] | ' | ||||||||||||||||||||||||||||
The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2013: | |||||||||||||||||||||||||||||
Year Ending December 31, | |||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||||||
Minimum Lease Payments | $ | 2,427 | $ | 1,970 | $ | 471 | $ | 257 | $ | 34 | $ | 941 | $ | 6,100 | |||||||||||||||
COMMON_STOCK_Common_Stock_Tabl
COMMON STOCK Common Stock (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||||||||||
Equity [Abstract] | ' | |||||||||||||||||||||||||||||||||||
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011(1) | ||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||
Stock-based compensation expense | $ | 12,880 | $ | 8,495 | $ | 8,781 | ||||||||||||||||||||||||||||||
Income tax benefit | (4,697 | ) | (3,245 | ) | (3,344 | ) | ||||||||||||||||||||||||||||||
Net stock-based compensation expense | $ | 8,183 | $ | 5,250 | $ | 5,437 | ||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||
(1) Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 16, Transactions with Affiliates, for additional information regarding the related separation agreement. | ||||||||||||||||||||||||||||||||||||
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Number of | Weighted-Average | Weighted- Average | Aggregate Intrinsic | Number of | Weighted-Average | Number of | Weighted-Average | |||||||||||||||||||||||||||||
Shares | Exercise | Remaining | Value (in thousands) | Shares | Exercise | Shares | Exercise | |||||||||||||||||||||||||||||
Underlying | Price | Contractual | Underlying | Price | Underlying | Price | ||||||||||||||||||||||||||||||
Options | Per Share | Term (in years) | Options | Per Share | Options | Per Share | ||||||||||||||||||||||||||||||
Outstanding beginning of year, January 1, | 6,973 | $ | 41.09 | 2.6 | $ | — | 6,973 | $ | 41.09 | 10,306 | $ | 41.9 | ||||||||||||||||||||||||
Exercised | (3,450 | ) | 37.15 | — | 77 | — | — | — | — | |||||||||||||||||||||||||||
Forfeited | — | — | — | — | — | — | (3,333 | ) | 43.6 | |||||||||||||||||||||||||||
Outstanding end of year, December 31, | 3,523 | 44.95 | 2.2 | 29 | 6,973 | 41.09 | 6,973 | 41.09 | ||||||||||||||||||||||||||||
Exercisable at December 31, | 3,523 | 44.95 | 2.2 | 29 | 6,973 | 41.09 | 6,973 | 41.09 | ||||||||||||||||||||||||||||
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
In January 2013, the Compensation Committee awarded 87,078 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Expected term of award | 6 years | 6 years | 6 years | |||||||||||||||||||||||||||||||||
Risk-free interest rate | 1 | % | 1.1 | % | 2.5 | % | ||||||||||||||||||||||||||||||
Expected volatility | 65.5 | % | 64.3 | % | 60.2 | % | ||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | $ | 21.96 | $ | 17.61 | $ | 25.22 | ||||||||||||||||||||||||||||||
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
The following table presents the changes in our SARs: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
Number of | Weighted-Average | Average Remaining Contractual | Aggregate Intrinsic | Number of | Weighted-Average | Aggregate Intrinsic | Number of | Weighted-Average | Aggregate Intrinsic | |||||||||||||||||||||||||||
SARs | Exercise | Term (in years) | Value (in thousands) | SARs | Exercise | Value (in thousands) | SARs | Exercise | Value (in thousands) | |||||||||||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||||||||||||||
Outstanding beginning of year, January 1, | 118,832 | $ | 30.8 | 8.4 | $ | 486 | 50,471 | $ | 31.61 | $ | 341 | 57,282 | $ | 24.44 | $ | 1,020 | ||||||||||||||||||||
Awarded | 87,078 | 37.18 | — | — | 68,361 | 30.19 | — | 31,552 | 43.95 | — | ||||||||||||||||||||||||||
Exercised | (15,147 | ) | 30.06 | — | 425 | — | — | — | (25,371 | ) | 24.44 | 77 | ||||||||||||||||||||||||
Forfeited | — | — | — | — | — | — | — | (12,992 | ) | 43.95 | — | |||||||||||||||||||||||||
Outstanding at December 31, | 190,763 | 33.77 | 8.2 | 3,711 | 118,832 | 30.8 | 486 | 50,471 | 31.61 | 341 | ||||||||||||||||||||||||||
Exercisable at December 31, | 51,922 | 29.97 | 7.1 | 1,207 | 27,458 | 28.84 | 187 | 10,636 | 24.44 | 114 | ||||||||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
The following table presents the changes in non-vested time-based awards during 2013: | ||||||||||||||||||||||||||||||||||||
Shares | Weighted-Average | |||||||||||||||||||||||||||||||||||
Grant-Date | ||||||||||||||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||||||||||||||
Non-vested at December 31, 2012 | 646,490 | $ | 27.93 | |||||||||||||||||||||||||||||||||
Granted | 311,051 | 45.53 | ||||||||||||||||||||||||||||||||||
Vested | (282,787 | ) | 27.57 | |||||||||||||||||||||||||||||||||
Forfeited | (22,973 | ) | 31.52 | |||||||||||||||||||||||||||||||||
Non-vested at December 31, 2013 | 651,781 | 36.36 | ||||||||||||||||||||||||||||||||||
As of/Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||||||||||||||||||
Total intrinsic value of time-based awards vested | $ | 13,640 | $ | 5,950 | $ | 9,030 | ||||||||||||||||||||||||||||||
Total intrinsic value of time-based awards non-vested | 34,688 | 21,470 | 18,531 | |||||||||||||||||||||||||||||||||
Market price per common share as of December 31, | 53.22 | 33.21 | 35.11 | |||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | 45.53 | 26.59 | 33.71 | |||||||||||||||||||||||||||||||||
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
In January 2013, the Compensation Committee awarded a total of 41,570 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2014 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: | ||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||||
Expected term of award | 3 years | 3 years | ||||||||||||||||||||||||||||||||||
Risk-free interest rate | 0.4 | % | 0.3 | % | ||||||||||||||||||||||||||||||||
Expected volatility | 56.6 | % | 65.3 | % | ||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | $ | 49.04 | $ | 36.54 | ||||||||||||||||||||||||||||||||
Schedule of Nonvested Performance-based Units Activity [Table Text Block] | ' | |||||||||||||||||||||||||||||||||||
The following table presents the change in non-vested market-based awards during 2013: | ||||||||||||||||||||||||||||||||||||
Shares | Weighted-Average | |||||||||||||||||||||||||||||||||||
Grant-Date | ||||||||||||||||||||||||||||||||||||
Fair Value per Share | ||||||||||||||||||||||||||||||||||||
Non-vested at December 31, 2012 | 40,696 | $ | 39.22 | |||||||||||||||||||||||||||||||||
Granted | 41,570 | 49.04 | ||||||||||||||||||||||||||||||||||
Vested | (10,155 | ) | 47.28 | |||||||||||||||||||||||||||||||||
Non-vested at December 31, 2013 | 72,111 | 43.75 | ||||||||||||||||||||||||||||||||||
As of/Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||||||||||||||||||
Total intrinsic value of market-based awards vested | $ | 724 | $ | — | $ | 366 | ||||||||||||||||||||||||||||||
Total intrinsic value of market-based awards non-vested | 3,838 | 1,352 | 1,513 | |||||||||||||||||||||||||||||||||
Market price per common share as of December 31, | 53.22 | 33.21 | 35.11 | |||||||||||||||||||||||||||||||||
Weighted-average grant date fair value per share | 49.04 | 36.54 | 58.53 | |||||||||||||||||||||||||||||||||
EARNINGS_PER_SHARE_Tables
EARNINGS PER SHARE (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Earnings Per Share [Abstract] | ' | ||||||||
Schedule of Earnings Per Share Reconciliation [Table Text Block] | ' | ||||||||
The following table presents a reconciliation of the weighted-average diluted shares outstanding: | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | 2011 | |||||||
(in thousands) | |||||||||
Weighted-average common shares outstanding - basic | 32,426 | 27,677 | 23,521 | ||||||
Dilutive effect of: | |||||||||
Restricted stock | — | — | 307 | ||||||
SARs | — | — | 40 | ||||||
Non-employee director deferred compensation | — | — | 3 | ||||||
Weighted-average common shares and equivalents outstanding - diluted | 32,426 | 27,677 | 23,871 | ||||||
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block] | ' | ||||||||
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: | |||||||||
Year Ended December 31, | |||||||||
2013 | 2012 | 2011 | |||||||
(in thousands) | |||||||||
Weighted-average common share equivalents excluded from diluted earnings | |||||||||
per share due to their anti-dilutive effect: | |||||||||
Restricted stock | 823 | 694 | 220 | ||||||
SARs | 72 | 116 | 22 | ||||||
Stock options | 7 | 7 | 9 | ||||||
Non-employee director deferred compensation | 4 | 3 | — | ||||||
Convertible notes | 518 | — | — | ||||||
Total anti-dilutive common share equivalents | 1,424 | 820 | 251 | ||||||
ASSETS_HELD_FOR_SALE_DIVESTITU1
ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Assets Held for Sale, Divestitures and Discontinued Operations (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Discontinued Operations and Disposal Groups [Abstract] | ' | ||||||||||||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block] | ' | ||||||||||||
The following table presents consolidated balance sheet data related to net assets held for sale: | |||||||||||||
Consolidated balance sheet | As of December 31, 2013 | ||||||||||||
(In thousands) | |||||||||||||
Assets | |||||||||||||
Properties and equipment, net | $ | 2,785 | |||||||||||
Liabilities | |||||||||||||
Asset retirement obligation | 2,061 | ||||||||||||
Net Assets | $ | 724 | |||||||||||
The following table presents consolidated statement of operations data related to our discontinued operations: | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statements of operations - discontinued operations | 2013 | 2012 | 2011 | ||||||||||
(in thousands) | |||||||||||||
Revenues | |||||||||||||
Crude oil, natural gas and NGLs sales | $ | 20,398 | $ | 36,422 | $ | 80,860 | |||||||
Sales from natural gas marketing | 2,825 | 1,708 | 2,949 | ||||||||||
Well operations, pipeline income and other | 890 | 1,888 | 2,542 | ||||||||||
Total revenues | 24,113 | 40,018 | 86,351 | ||||||||||
Costs, expenses and other | |||||||||||||
Production costs | 7,975 | 22,453 | 30,885 | ||||||||||
Cost of natural gas marketing | 2,673 | 1,529 | 2,634 | ||||||||||
Impairment of crude oil and natural gas properties | 3 | 162,254 | 22,858 | ||||||||||
Depreciation, depletion and amortization | 2,258 | 48,101 | 47,521 | ||||||||||
Other | 2,528 | 2,084 | 1,054 | ||||||||||
(Gain) loss on sale of properties and equipment | 2,330 | (19,920 | ) | (3,854 | ) | ||||||||
Total costs, expenses and other | 17,767 | 216,501 | 101,098 | ||||||||||
Income (loss) from discontinued operations | 6,346 | (176,483 | ) | (14,747 | ) | ||||||||
Provision for income taxes | (2,175 | ) | 67,466 | 5,620 | |||||||||
Income (loss) from discontinued operations, net of tax | $ | 4,171 | $ | (109,017 | ) | $ | (9,127 | ) | |||||
ACQUISITIONS_Acquisitions_Tabl
ACQUISITIONS Acquisitions (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Business Combinations [Abstract] | ' | ||||||||||||||||
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | ' | ||||||||||||||||
The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012 and 2011: | |||||||||||||||||
Year Ended December 31, | |||||||||||||||||
2012 | 2011 | ||||||||||||||||
Merit | Seneca-Upshur | 2003/2002-D Partnerships | 2005 Partnerships | ||||||||||||||
(in thousands) | |||||||||||||||||
Total acquisition cost | $ | 304,643 | $ | 69,618 | $ | 29,960 | $ | 43,015 | |||||||||
Recognized amounts of identifiable assets acquired and liabilities assumed: | |||||||||||||||||
Assets acquired: | |||||||||||||||||
Crude oil and natural gas properties - proved | $ | 180,696 | $ | 20,175 | $ | 27,940 | $ | 39,825 | |||||||||
Crude oil and natural gas properties - unproved | 151,428 | 49,100 | — | — | |||||||||||||
Other assets | 3,631 | 10,196 | 3,455 | 3,848 | |||||||||||||
Total assets acquired | 335,755 | 79,471 | 31,395 | 43,673 | |||||||||||||
Liabilities assumed: | |||||||||||||||||
Asset retirement obligation | 14,833 | 8,157 | 497 | 300 | |||||||||||||
Other accrued expenses | 9,574 | — | — | — | |||||||||||||
Other liabilities | 6,705 | 1,696 | 938 | 358 | |||||||||||||
Total liabilities assumed | 31,112 | 9,853 | 1,435 | 658 | |||||||||||||
Total identifiable net assets acquired | $ | 304,643 | $ | 69,618 | $ | 29,960 | $ | 43,015 | |||||||||
Business Acquisition, Pro Forma Information [Table Text Block] | ' | ||||||||||||||||
Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 and December 31, 2011, assuming the Merit Acquisition had been completed as of January 1, 2011, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results. | |||||||||||||||||
Year Ended December 31, | |||||||||||||||||
2012 | 2011 | ||||||||||||||||
(in thousands, except per share amounts) | |||||||||||||||||
Total revenues | $ | 370,488 | $ | 438,204 | |||||||||||||
Total costs, expenses and other | 521,178 | 366,120 | |||||||||||||||
Net income (loss) | $ | (119,343 | ) | $ | 45,688 | ||||||||||||
Earnings per share: | |||||||||||||||||
Basic | $ | (4.31 | ) | $ | 1.94 | ||||||||||||
Diluted | $ | (4.31 | ) | $ | 1.91 | ||||||||||||
TRANSACTIONS_WITH_AFFILIATES_A1
TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Transactions with Affiliates and Other Related Parties (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Related Party Transactions [Abstract] | ' | ||||||||||||
Schedule of Related Party Transactions [Table Text Block] | ' | ||||||||||||
The following table presents the consolidated statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented. | |||||||||||||
Year Ended December 31, | |||||||||||||
Consolidated statement of operations line item | 2013 | 2012 | 2011 | ||||||||||
(in thousands) | |||||||||||||
Production costs | $ | 4,097 | $ | 3,945 | $ | 3,441 | |||||||
Exploration expense | 502 | 492 | 430 | ||||||||||
General and administrative expense | 2,649 | 1,630 | 1,543 | ||||||||||
BUSINESS_SEGMENTS_Business_Seg
BUSINESS SEGMENTS Business Segments (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||
Schedule of Segment Reporting Information [Table Text Block] | ' | |||||||||||
The following tables present our segment information: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(in thousands) | ||||||||||||
Year Ended December 31, | ||||||||||||
Segment revenues: | ||||||||||||
Oil and gas exploration and production | $ | 341,527 | $ | 275,234 | $ | 273,819 | ||||||
Gas marketing | 69,787 | 45,371 | 63,470 | |||||||||
Total revenues | $ | 411,314 | $ | 320,605 | $ | 337,289 | ||||||
Segment income (loss) before income taxes: | ||||||||||||
Oil and gas exploration and production | $ | 79,527 | $ | 103,111 | $ | 138,616 | ||||||
Gas marketing | (298 | ) | 349 | 639 | ||||||||
Unallocated | (120,498 | ) | (137,856 | ) | (104,891 | ) | ||||||
Income (loss) before income taxes | $ | (41,269 | ) | $ | (34,396 | ) | $ | 34,364 | ||||
Expenditures for segment long-lived assets: | ||||||||||||
Oil and gas exploration and production | $ | 403,227 | $ | 656,443 | $ | 479,027 | ||||||
Unallocated | 1,379 | 3,509 | 1,363 | |||||||||
Total | $ | 404,606 | $ | 659,952 | $ | 480,390 | ||||||
As of December 31, | ||||||||||||
Segment assets: | ||||||||||||
Oil and gas exploration and production | $ | 1,934,466 | $ | 1,723,011 | ||||||||
Gas marketing | 20,342 | 11,090 | ||||||||||
Unallocated | 67,610 | 92,747 | ||||||||||
Assets held for sale | 2,785 | — | ||||||||||
Total assets | $ | 2,025,203 | $ | 1,826,848 | ||||||||
SUPPLEMENTAL_INFORMATION_NATUR1
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract] | ' | ||||||||||||
Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block] | ' | ||||||||||||
The price used to estimate our reserves, by commodity, are presented below. | |||||||||||||
Price Used to Estimate Reserves | |||||||||||||
As of December 31, | Crude Oil | Natural Gas | NGLs | ||||||||||
(per Bbl) | (per Mcf) | (per Bbl) | |||||||||||
2013 | $ | 82.18 | $ | 3.22 | $ | 29.92 | |||||||
2012 | 87.51 | 2.35 | 28.02 | ||||||||||
2011 | 88.94 | 3.41 | 39.59 | ||||||||||
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | ' | ||||||||||||
The following tables present the changes in our estimated quantities of proved reserves: | |||||||||||||
Crude Oil, Condensate (MBbls) | Natural Gas | NGLs | Total | ||||||||||
(MMcf) | (MBbls) | (MBoe) | |||||||||||
Proved Reserves: | |||||||||||||
Proved reserves, January 1, 2011 | 23,236 | 657,306 | 10,649 | 143,436 | |||||||||
Revisions of previous estimates | (1,904 | ) | (161,654 | ) | 3,163 | (25,683 | ) | ||||||
Extensions, discoveries and other additions | 17,092 | 176,689 | 5,633 | 52,173 | |||||||||
Purchases of reserves | 1,605 | 32,761 | 1,052 | 8,117 | |||||||||
Dispositions | (435 | ) | (2,070 | ) | (94 | ) | (874 | ) | |||||
Production | (1,958 | ) | (30,887 | ) | (815 | ) | (7,921 | ) | |||||
Proved reserves, December 31, 2011 (1) | 37,636 | 672,145 | 19,588 | 169,248 | |||||||||
Revisions of previous estimates | (6,729 | ) | (289,436 | ) | (3,671 | ) | (58,639 | ) | |||||
Extensions, discoveries and other additions | 27,482 | 172,933 | 11,637 | 67,941 | |||||||||
Purchases of reserves | 10,801 | 87,212 | 8,084 | 33,420 | |||||||||
Dispositions | (7,854 | ) | (6,406 | ) | (1,970 | ) | (10,891 | ) | |||||
Production | (2,026 | ) | (32,410 | ) | (841 | ) | (8,269 | ) | |||||
Proved reserves, December 31, 2012 (2) | 59,310 | 604,038 | 32,827 | 192,810 | |||||||||
Revisions of previous estimates | (18,420 | ) | (117,068 | ) | (8,549 | ) | (46,480 | ) | |||||
Extensions, discoveries and other additions | 55,759 | 365,563 | 25,249 | 141,935 | |||||||||
Purchases of reserves | 343 | 2,894 | 217 | 1,043 | |||||||||
Dispositions | (252 | ) | (94,927 | ) | (30 | ) | (16,104 | ) | |||||
Production | (2,910 | ) | (20,860 | ) | (1,043 | ) | (7,430 | ) | |||||
Proved reserves, December 31, 2013 | 93,830 | 739,640 | 48,671 | 265,774 | |||||||||
Proved Developed Reserves, as of: | |||||||||||||
January 1, 2011 | 8,287 | 227,341 | 4,013 | 50,190 | |||||||||
December 31, 2011 (1) | 16,910 | 299,369 | 11,753 | 78,558 | |||||||||
December 31, 2012 (2) | 20,412 | 281,925 | 14,353 | 81,753 | |||||||||
31-Dec-13 | 23,997 | 220,387 | 14,825 | 75,553 | |||||||||
Proved Undeveloped Reserves, as of: | |||||||||||||
January 1, 2011 | 14,949 | 429,965 | 6,636 | 93,246 | |||||||||
December 31, 2011 (1) | 20,726 | 372,776 | 7,835 | 90,690 | |||||||||
December 31, 2012 (2) | 38,898 | 322,113 | 18,474 | 111,058 | |||||||||
31-Dec-13 | 69,833 | 519,253 | 33,846 | 190,221 | |||||||||
__________ | |||||||||||||
-1 | Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. | ||||||||||||
-2 | Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. | ||||||||||||
Developed | Undeveloped | Total | |||||||||||
(MBoe) | |||||||||||||
Beginning proved reserves, January 1, 2012 | 78,558 | 90,690 | 169,248 | ||||||||||
Undeveloped reserves converted to developed | 7,655 | (7,655 | ) | — | |||||||||
Revisions of previous estimates | (18,318 | ) | (40,321 | ) | (58,639 | ) | |||||||
Extensions, discoveries and other additions | 11,298 | 56,643 | 67,941 | ||||||||||
Purchases of reserves | 13,542 | 19,878 | 33,420 | ||||||||||
Dispositions | (2,713 | ) | (8,178 | ) | (10,891 | ) | |||||||
Production | (8,269 | ) | — | (8,269 | ) | ||||||||
Ending proved reserves, December 31, 2012 | 81,753 | 111,057 | 192,810 | ||||||||||
Undeveloped reserves converted to developed | 3,212 | (3,212 | ) | — | |||||||||
Revisions of previous estimates | (6,751 | ) | (39,729 | ) | (46,480 | ) | |||||||
Extensions, discoveries and other additions | 19,830 | 122,105 | 141,935 | ||||||||||
Purchases of reserves | 1,043 | — | 1,043 | ||||||||||
Dispositions | (16,104 | ) | — | (16,104 | ) | ||||||||
Production | (7,430 | ) | — | (7,430 | ) | ||||||||
Ending proved reserves, December 31, 2013 | 75,553 | 190,221 | 265,774 | ||||||||||
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | ' | ||||||||||||
The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Revenue: | |||||||||||||
Crude oil, natural gas and NGLs sales | $ | 379,796 | $ | 274,783 | $ | 304,157 | |||||||
Commodity price risk management gain, net | (23,905 | ) | 32,339 | 46,090 | |||||||||
355,891 | 307,122 | 350,247 | |||||||||||
Expenses: | |||||||||||||
Production costs | 81,365 | 77,537 | 75,717 | ||||||||||
Exploration expense | 7,071 | 22,605 | 6,289 | ||||||||||
Impairment of proved crude oil and natural gas properties | 53,438 | 162,287 | 25,159 | ||||||||||
Depreciation, depletion, and amortization | 124,202 | 146,879 | 128,458 | ||||||||||
Accretion of asset retirement obligations | 4,747 | 4,060 | 1,897 | ||||||||||
(Gain) loss on sale of properties and equipment | 3,722 | (24,273 | ) | (4,050 | ) | ||||||||
274,545 | 389,095 | 233,470 | |||||||||||
Results of operations for crude oil and natural gas producing | 81,346 | (81,973 | ) | 116,777 | |||||||||
activities before provision for income taxes | |||||||||||||
Provision for income taxes | (29,400 | ) | 31,163 | (36,785 | ) | ||||||||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs | $ | 51,946 | $ | (50,810 | ) | $ | 79,992 | ||||||
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | ' | ||||||||||||
Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Acquisition of properties: (1) | |||||||||||||
Proved properties | $ | 28,698 | $ | 105,303 | $ | 79,554 | |||||||
Unproved properties | 3,390 | 276,225 | 95,081 | ||||||||||
Development costs (2) | 332,250 | 233,144 | 301,008 | ||||||||||
Exploration costs: (3) | |||||||||||||
Exploratory drilling | 58,988 | 18,803 | 3,626 | ||||||||||
Geological and geophysical | 752 | 1,925 | 1,846 | ||||||||||
Total costs incurred | $ | 424,078 | $ | 635,400 | $ | 481,115 | |||||||
__________ | |||||||||||||
-1 | Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. | ||||||||||||
-2 | Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2013, 2012 and 2011, $40.1 million, $62.0 million and $80.6 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. | ||||||||||||
-3 | Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. | ||||||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | ' | ||||||||||||
Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: | |||||||||||||
As of December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
(in thousands) | |||||||||||||
Proved crude oil and natural gas properties | $ | 1,781,681 | $ | 2,075,924 | |||||||||
Unproved crude oil and natural gas properties | 307,203 | 319,327 | |||||||||||
Uncompleted wells, equipment and facilities | 51,773 | 62,392 | |||||||||||
Capitalized costs | 2,140,657 | 2,457,643 | |||||||||||
Less accumulated DD&A | (529,607 | ) | (905,458 | ) | |||||||||
Capitalized costs, net | $ | 1,611,050 | $ | 1,552,185 | |||||||||
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | ' | ||||||||||||
The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. | |||||||||||||
As of December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Future estimated cash flows | $ | 11,550,917 | $ | 7,529,292 | $ | 6,415,255 | |||||||
Future estimated production costs | (2,329,836 | ) | (1,690,453 | ) | (1,704,645 | ) | |||||||
Future estimated development costs | (2,778,148 | ) | (1,852,177 | ) | (1,474,137 | ) | |||||||
Future estimated income tax expense | (2,119,615 | ) | (1,230,294 | ) | (946,849 | ) | |||||||
Future net cash flows | 4,323,318 | 2,756,368 | 2,289,624 | ||||||||||
10% annual discount for estimated timing of cash flows | (2,541,155 | ) | (1,587,871 | ) | (1,348,415 | ) | |||||||
Standardized measure of discounted future estimated net cash flows | $ | 1,782,163 | $ | 1,168,497 | $ | 941,209 | |||||||
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | ' | ||||||||||||
The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: | |||||||||||||
Year Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
(in thousands) | |||||||||||||
Sales of crude oil, natural gas and NGLs production, net of production costs | $ | (286,021 | ) | $ | (194,346 | ) | $ | (226,227 | ) | ||||
Net changes in prices and production costs (1) | 89,527 | 95,501 | 383,293 | ||||||||||
Extensions, discoveries, and improved recovery, less related costs (2) | 1,529,006 | 632,781 | 467,347 | ||||||||||
Sales of reserves (3) | (142,724 | ) | (86,902 | ) | (4,224 | ) | |||||||
Purchases of reserves (4) | 10,610 | 296,208 | 64,761 | ||||||||||
Development costs incurred during the period | 46,366 | 69,198 | 94,941 | ||||||||||
Revisions of previous quantity estimates (5) | (397,738 | ) | (452,775 | ) | (112,468 | ) | |||||||
Changes in estimated income taxes (6) | (381,369 | ) | (131,256 | ) | (204,377 | ) | |||||||
Net changes in future development costs | (40,707 | ) | (3,979 | ) | (29,827 | ) | |||||||
Accretion of discount | 142,040 | 124,105 | 65,284 | ||||||||||
Timing and other | 44,676 | (121,247 | ) | (45,712 | ) | ||||||||
Total | $ | 613,666 | $ | 227,288 | $ | 452,791 | |||||||
__________ | |||||||||||||
-1 | Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves. | ||||||||||||
-2 | The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. | ||||||||||||
-3 | The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012. | ||||||||||||
-4 | The decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field. | ||||||||||||
-5 | The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. | ||||||||||||
-6 | The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0%, 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. |
NATURE_OF_OPERATIONS_AND_BASIS1
NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Oil and gas producing wells, gross | 3,100 |
Number of Operating Segments | 2 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Certificates of Deposit and Cash | $3,300,000 | $5,300,000 | ' |
Inventory, Net | 900,000 | 1,200,000 | ' |
Impairment of other property and equipment | 0 | 0 | ' |
Non-Oil and gas Depreciation, Depletion and Amortization | 5,100,000 | 4,700,000 | 4,000,000 |
Capitalized Interest | 1,900,000 | 1,200,000 | 1,700,000 |
Production Tax Liability | 22,100,000 | 18,700,000 | ' |
Debt Issuance Cost | 16,600,000 | 17,400,000 | ' |
Restricted Cash [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Certificates of Deposit and Cash | 2,200,000 | 3,900,000 | ' |
Other Assets [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Certificates of Deposit and Cash | 1,100,000 | 1,400,000 | ' |
12% Senior Notes [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Debt Issuance Cost | ' | 10,900,000 | ' |
7.75% Senior Notes [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Debt Issuance Cost | 9,800,000 | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | ' | ' |
Revolving Credit Facility [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Debt Issuance Cost | 5,500,000 | 4,600,000 | ' |
3.25% Convertible Note [Member] | ' | ' | ' |
Significant Accounting Plicies [Line Items] | ' | ' | ' |
Debt Issuance Cost | $1,300,000 | $1,900,000 | ' |
FAIR_VALUE_MEASUREMENTS_AND_DI2
FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value | Significant Other Observable Inputs (Level 2) | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity Based Derivative Assets | $5,325,000 | $42,798,000 |
Basis Protection Derivative Assets | 463,000 | 377,000 |
Assets, Fair Value Disclosure | 5,788,000 | 43,175,000 |
Commodity Based Derivative Liabilities | 17,537,000 | 9,839,000 |
Basis Protection Derivative Liabilities | 5,000 | 16,656,000 |
Liabilities, Fair Value Disclosure | 17,542,000 | 26,495,000 |
Net Asset Fair Value | -11,754,000 | 16,680,000 |
Fair Value | Significant Unobservable Inputs (Level 3) | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity Based Derivative Assets | 2,385,000 | 15,750,000 |
Basis Protection Derivative Assets | 0 | 0 |
Assets, Fair Value Disclosure | 2,385,000 | 15,750,000 |
Commodity Based Derivative Liabilities | 988,000 | 2,081,000 |
Basis Protection Derivative Liabilities | 0 | 0 |
Liabilities, Fair Value Disclosure | 988,000 | 2,081,000 |
Net Asset Fair Value | 1,397,000 | 13,669,000 |
Fair Value | Total | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity Based Derivative Assets | 7,710,000 | 58,548,000 |
Basis Protection Derivative Assets | 463,000 | 377,000 |
Assets, Fair Value Disclosure | 8,173,000 | 58,925,000 |
Commodity Based Derivative Liabilities | 18,525,000 | 11,920,000 |
Basis Protection Derivative Liabilities | 5,000 | 16,656,000 |
Liabilities, Fair Value Disclosure | 18,530,000 | 28,576,000 |
Net Asset Fair Value | -10,357,000 | 30,349,000 |
3.25% Convertible Senior Notes due 2016 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | 3.25% | ' |
3.25% convertible senior notes fair value | 165,400,000 | ' |
3.25% convertible senior notes fair value as a percentage of par | 143.90% | ' |
7.75% Senior Notes [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | ' |
7.75% senior notes fair value | $543,100,000 | ' |
7.75% senior notes fair value as percentage of par | 108.60% | ' |
FAIR_VALUE_MEASUREMENTS_AND_DI3
FAIR VALUE MEASUREMENTS AND DISCLOSURES Reconciliation of Level 3 Fair Value Measurements (Details) (Derivative Financial Instrument Net Assets [Member], USD $) | 12 Months Ended | ||||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value | $1,397 | $13,669 | $22,107 | $10,762 | |||
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item; | -1,028 | 3,666 | 11,666 | ' | |||
Commodity Price Risk Management, net | ' | ' | ' | ' | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings | -1,521 | 7,576 | 13,487 | ' | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements | -6,361 | -15,644 | -1,712 | ' | |||
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item; | -1,032 | 3,665 | 11,669 | ' | |||
Sales From Natural Gas Marketing | ' | ' | ' | ' | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings | 13 | 63 | 114 | ' | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements | -37 | -114 | -139 | ' | |||
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item; | 4 | 1 | -3 | ' | |||
Accounts Receivable Affiliates [Member] | ' | ' | ' | ' | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Changes in Fair Value Included in Balance Sheet Line Item | 0 | [1] | 0 | [1] | 49 | [1] | ' |
Accounts Payable Affiliates [Member] | ' | ' | ' | ' | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Changes in Fair Value Included in Balance Sheet Line Item | 0 | [1] | -319 | [1] | -454 | [1] | ' |
Net Assets Related to Discontinued Operations [Member] | ' | ' | ' | ' | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements | ($4,366) | $0 | $0 | ' | |||
[1] | Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | ||||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | $18,530 | $28,576 | ||
Derivative Asset, Fair Value, Gross Asset | 8,173 | 58,925 | ||
Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 2,572 | 52,042 | ||
Non Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 5,601 | 6,883 | ||
Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 15,515 | 18,439 | ||
Non Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,015 | 10,137 | ||
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 2,016 | 46,657 | ||
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 5,055 | 6,653 | ||
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 15,263 | 1,698 | ||
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 2,782 | 9,828 | ||
Commodity Contracts Related to Affiliated Partnership [Member] | Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 0 | [1] | 4,707 | [1] |
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 361 | 319 | ||
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 278 | 212 | ||
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 247 | 226 | ||
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 233 | 168 | ||
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 195 | 359 | ||
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 268 | 18 | ||
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 0 | 14,375 | ||
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 0 | 141 | ||
Basis Protection Contracts Related to Natural Gas Marketing [Member] | Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | 5 | 0 | ||
Basis Protection Contracts Related to Affiliated Partnerships [Member] | Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Fair Value of Derivatives | $0 | [2] | $2,140 | [2] |
[1] | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. | |||
[2] | Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS Impact of Derivative Instruments on Statement of Operations (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Commodity Price Risk Management, net | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Net settlements | $12,913 | $49,416 | $17,243 |
Net change in fair value of unsettled derivatives | -36,818 | -17,077 | 28,847 |
Total Derivative Gain (Loss) | -23,905 | 32,339 | 46,090 |
Sales From Natural Gas Marketing | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Net settlements | 446 | 2,170 | 2,970 |
Net change in fair value of unsettled derivatives | 429 | -1,658 | -161 |
Total Derivative Gain (Loss) | 875 | 512 | 2,809 |
Cost of Natural Gas Marketing | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Net settlements | -257 | -2,029 | -2,571 |
Net change in fair value of unsettled derivatives | -412 | 1,601 | -85 |
Total Derivative Gain (Loss) | ($669) | ($428) | ($2,656) |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Derivative Asset [Abstract] | ' | ' |
Derivative Asset, Fair Value, Gross Asset | $8,173 | $58,925 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -5,623 | -11,437 |
Derivative Asset | 2,550 | 47,488 |
Derivative Liability [Abstract] | ' | ' |
Derivative Liability, Fair Value, Gross Liability | 18,530 | 28,576 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -5,623 | -11,437 |
Derivative Liability | $12,907 | $17,139 |
DERIVATIVE_FINANCIAL_INSTRUMEN5
DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details) | Dec. 31, 2013 |
MBbls | |
MMBTU | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' |
Portion of Anticipated Natural Gas Production Hedged (MMBtu) | 59,971,000 |
Portion of Future Oil and Gas Production Being Hedged (MBbls) | 8,613 |
CONCENTRATION_OF_RISK_Accounts1
CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Concentration Risk [Line Items] | ' | ' |
Allowance for Doubtful Accounts Receivable, Current | ($1,261) | ($1,026) |
Accounts Receivable, Net, Current | 94,085 | 64,880 |
Natural gas, NGLs and crude oil sales | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Accounts Receivable, Gross | 66,257 | 39,837 |
Joint interest billing | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Accounts Receivable, Gross | 20,558 | 6,896 |
Natural gas marketing | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Accounts Receivable, Gross | 6,210 | 8,209 |
Reimbursements for title defects | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Accounts Receivable, Gross | 0 | 7,579 |
Other Accounts Receivable | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Accounts Receivable, Gross | $2,321 | $3,385 |
CONCENTRATION_OF_RISK_Customer
CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Rate | Rate | Rate | |
Suncor Energy Marketing, Inc. [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Percentage of Revenue | 31.30% | 29.80% | 25.70% |
Percentage of Accounts Receivable Balance at Year-End | 26.30% | ' | ' |
DCP Midstream, LP [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Percentage of Revenue | 14.60% | 12.20% | 11.50% |
Percentage of Accounts Receivable Balance at Year-End | 10.80% | ' | ' |
CONCENTRATION_OF_RISK_Derivati
CONCENTRATION OF RISK Derivative Counterparties (Details) (USD $) | Dec. 31, 2013 | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | $8,173,000 | |
Number of derivative counterparties | 19 | |
Wells Fargo Bank [Member] | ' | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | 2,496,000 | [1] |
Bank of Montreal [Member] | ' | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | 1,102,000 | [1] |
Canadian Imperial Bank of Commerce [Member] | ' | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | 1,054,000 | [1] |
Other Lenders in Our Credit Facility [Member] | ' | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | 3,380,000 | |
Various [Member] | ' | |
Concentration Risk [Line Items] | ' | |
Fair Value of Derivative Assets | $141,000 | [2] |
[1] | Major lender in our revolving credit facility. See Note 8, Long-Term Debt. | |
[2] | Represents a total of 19 counterparties. |
PROPERTIES_AND_EQUIPMENT_Prope1
PROPERTIES AND EQUIPMENT Properties and Equipment (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment [Line Items] | ' | ' |
Proved Natural Gas and Crude Oil Properties | $1,781,681 | $2,075,924 |
Unproved Natural Gas and Crude Oil Properties | 307,203 | 319,327 |
Total Natural Gas and Crude Oil Properties | 2,088,884 | 2,395,251 |
Pipelines and Related Facilities | 21,781 | 47,786 |
Transportation and Other Equipment | 29,246 | 34,858 |
Land and Buildings | 13,617 | 14,935 |
Construction in Progress | 53,810 | 67,217 |
Gross Propertis and Equipment | 2,207,338 | 2,560,047 |
Accumulated Depreciation, Depletion and Amortization | -553,893 | -943,341 |
Property, Plant and Equipment, Net | $1,653,445 | $1,616,706 |
PROPERTIES_AND_EQUIPMENT_Impai
PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) (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 |
Continuing Operations: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment of proved properties | ' | ' | ' | ' | ' | ' | ' | ' | $48,750 | $0 | $0 |
Impairment of significantly unproved properties | ' | ' | ' | ' | ' | ' | ' | ' | 1,082 | 1,629 | 1,108 |
Amortization of Individually Insignificant Unproved Properties | ' | ' | ' | ' | ' | ' | ' | ' | 3,603 | 4,266 | 1,193 |
Total continuing operations | 1,002 | 4,472 | 1,502 | 46,459 | 4,563 | 388 | 356 | 588 | 53,435 | 5,895 | 2,301 |
Discontinued operations: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment of proved properties | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 161,185 | 22,460 |
Impairment of individually significant unproved properties from discontinued operations | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 313 | 0 |
Amortization of Individually Insignificant Unproved Properties, discontinued operations | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 756 | 398 |
Total discontinued operations | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 162,254 | 22,858 |
Total impairment of natural gas and crude oil properties | ' | ' | ' | ' | ' | ' | ' | ' | 53,438 | 168,149 | 25,159 |
Shallow Upper Devonian properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Continuing Operations: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment of proved properties | ' | $3,800 | ' | $45,000 | ' | ' | ' | ' | ' | ' | ' |
PROPERTIES_AND_EQUIPMENT_Suspe
PROPERTIES AND EQUIPMENT Suspended Exploratory Well Costs (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Change in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ' | ' | ' |
Balance beginning of year, January 1, | $19,567 | $4,432 | $2,297 |
Additions to capitalized exploratory well costs pending determination of proved reserves | 13,424 | 30,482 | 3,692 |
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | -32,991 | 0 | -1,557 |
capitalized well cost | 0 | -15,347 | 0 |
Balance end of year, December 31, | 0 | 19,567 | 4,432 |
Number of wells pending determination | 0 | 2 | 6 |
Aging of Capitalized Exploratory Well Costs | ' | ' | ' |
Exploratory well costs capitalized for a period of one year or less | ' | 19,567 | 3,587 |
Exploratory well costs capitalized for a period greater than one year since commencement of drilling | ' | 0 | 845 |
Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling | ' | 0 | 2 |
Southeast Ohio wells | ' | ' | ' |
Change in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ' | ' | ' |
Additions to capitalized exploratory well costs pending determination of proved reserves | ' | 12,200 | ' |
Rose Run wells | ' | ' | ' |
Change in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ' | ' | ' |
Additions to capitalized exploratory well costs pending determination of proved reserves | ' | 1,200 | ' |
SECO wells | ' | ' | ' |
Change in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ' | ' | ' |
Additions to capitalized exploratory well costs pending determination of proved reserves | ' | $900 | ' |
INCOME_TAXES_Provision_for_Inc
INCOME TAXES Provision for Income Taxes (Details) (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 |
Income Tax Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current Federal Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | $1,355 | $0 | $2,594 |
Current State and Local Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 199 | -199 | 750 |
Current Income Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 1,554 | -199 | 3,344 |
Deferred Federal Income Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 11,145 | 12,133 | -13,309 |
Deferred State and Local Income Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 2,098 | 767 | -1,835 |
Deferred Income Tax Benefit (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 13,243 | 12,900 | -15,144 |
Provision for income taxes | ($8,059) | $10,155 | ($9,791) | $22,492 | $11,766 | $15,268 | ($10,213) | ($4,120) | $14,797 | $12,701 | ($11,800) |
INCOME_TAXES_Reconciliation_of
INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Rate | Rate | Rate | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ' | ' | ' |
Statutory tax rate | 35.00% | 35.00% | 35.00% |
State income tax, net | 3.30% | 1.00% | 2.00% |
Percentage depletion | 1.80% | 1.90% | -2.50% |
Non-deductible compensation | -3.40% | -0.50% | 0.00% |
Non-deductible meals and entertainment | -0.50% | -0.50% | 0.30% |
State deferred rate change | 0.00% | 0.00% | 1.30% |
Unrecognized tax benefits | -0.10% | 0.00% | -2.60% |
Federal return examination adjustments | 0.00% | 0.00% | 0.40% |
Return to provision adjustments | -0.50% | 0.00% | 0.30% |
Other | 0.30% | 0.00% | 0.10% |
Effective tax rate | 35.90% | 36.90% | 34.30% |
INCOME_TAXES_Tax_Effects_of_Te
INCOME TAXES Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Components of Deferred Tax Assets [Abstract] | ' | ' |
Deferred Tax Assets, Provision for Underpayment of Natural Gas Sales | $6,205 | $0 |
Deferred compensation | 8,507 | 7,216 |
Asset retirement obligations | 11,630 | 10,325 |
State NOL and tax credit carryforwards, net | 5,182 | 6,117 |
Percentage depletion - Carryforward | 4,570 | 4,702 |
Alternative minimum tax - credit carryforward | 3,165 | 2,351 |
Federal NOL carryforward | 4,601 | 21,281 |
Other | 6,229 | 2,276 |
Deferred tax assets | 50,089 | 54,268 |
Components of Deferred Tax Liabilities [Abstract] | ' | ' |
properties and equipment | 120,746 | 122,742 |
Investment in PDCM | 21,962 | 31,445 |
Net change in fair value of unsettled derivatives | 0 | 7,163 |
Convertible debt | 3,774 | 5,194 |
Total gross deferred tax liabilities | 146,482 | 166,544 |
Net deferred tax liability | 96,393 | 112,276 |
Deferred income tax assets | 22,374 | 36,151 |
Deferred income tax liability | $118,767 | $148,427 |
INCOME_TAXES_Unrecognized_Tax_
INCOME TAXES Unrecognized Tax Benefits (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 |
Unrecognized Tax Benefits: | ' | ' | ' |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | ' | $0.10 | $0.20 |
Reductions in uncertain tax benefits due to settlements | $0.80 | ' | ' |
INCOME_TAXES_Additional_Inform
INCOME TAXES Additional Information (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 |
Federal NOL Carryforwards | State NOL Carryforwards | State Credit Carryforwards | |||
Operating Loss Carryforwards: | ' | ' | ' | ' | ' |
State NOL carryforwards | ' | ' | ' | $136,100,000 | ' |
State credit carryforwards | ' | ' | ' | ' | 1,100,000 |
Federal NOL carryforward | 4,601,000 | 21,281,000 | 13,600,000 | ' | ' |
Year Carryforwards Expire | ' | ' | 31-Dec-32 | 31-Dec-30 | 31-Dec-23 |
NOL Carryforward, Excess Tax Benefit from Share-based Compensation | 200,000 | ' | ' | ' | ' |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | $100,000 | $200,000 | ' | ' | ' |
LONGTERM_DEBT_SCHEDULE_OF_LONG
LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ' | ' |
Total senior notes | $604,990 | $601,329 |
Total credit facilities | 37,000 | 75,250 |
Loans Payable, Noncurrent | 15,000 | 0 |
Total long-term debt | 656,990 | 676,579 |
Convertible Debt | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Principal amount | 115,000 | 115,000 |
Unamortized discount | -10,010 | -13,671 |
3.25% Convertible senior notes due 2016, net of discount | 104,990 | 101,329 |
7.75% Senior Notes due 2022 [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Senior Notes | 500,000 | ' |
Revolving Credit Facility [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Corporate Line of Credit Outstanding | 0 | 49,000 |
PDCM Credit Facility [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
PDCM Line of Credit Outstanding | 37,000 | 26,250 |
PDCM Second Lien Term Loan [Member] | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Loans Payable, Noncurrent | 30,000 | ' |
Convertible Debt | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Principal amount | $165,400 | ' |
LONGTERM_DEBT_ADDITIONAL_INFOR
LONG-TERM DEBT ADDITIONAL INFORMATION (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | 15-May-16 | Nov. 15, 2015 | Nov. 15, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Oct. 15, 2022 | Oct. 03, 2012 | Dec. 31, 2013 | 21-May-18 | 21-May-13 | Oct. 05, 2010 | Dec. 31, 2013 | Dec. 31, 2013 | Apr. 30, 2017 | Apr. 30, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 31, 2017 | Jul. 02, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | |
3.25% Convertible Senior Notes due 2016 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 7.75% Senior Notes due 2022 [Member] | 7.75% Senior Notes due 2022 [Member] | 7.75% Senior Notes due 2022 [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | RNG Credit Facility [Member] | PDCM Credit Facility [Member] | PDCM Credit Facility [Member] | PDCM Credit Facility [Member] | PDCM Credit Facility [Member] | PDCM Second Lien Term Loan [Member] | PDCM Second Lien Term Loan [Member] | PDCM Second Lien Term Loan [Member] | First Payment [Member] | First Payment [Member] | Second Payment [Member] | Second Payment [Member] | PDCM Credit Facility [Member] | PDCM Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | LIBOR [Member] | Alternate Base Rate [Member] | ||||||||
Rate | Rate | Rate | Rate | Rate | 3.25% Convertible Senior Notes due 2016 [Member] | 7.75% Senior Notes due 2022 [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | 7.75% Senior Notes due 2022 [Member] | Rate | PDCM Second Lien Term Loan [Member] | PDCM Second Lien Term Loan [Member] | |||||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Issuance Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Nov-10 | ' | ' | ' | ' | 3-Oct-12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2-Jul-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Maturity Date | ' | ' | ' | ' | ' | ' | ' | 15-May-16 | ' | ' | ' | ' | ' | 15-Oct-22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31-Oct-17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.25% | ' | ' | ' | ' | 7.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Frequency of Periodic Payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'May 15 | 'April 15 | 'November 15 | 'October 15 | ' | ' | ' | ' | ' | ' |
Debt Instrument, Call Date, Earliest | ' | ' | ' | ' | ' | ' | ' | ' | 15-Nov-15 | ' | ' | ' | ' | ' | 15-Oct-15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Convertible Senior Note, Shares Issued Upon Conversion | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23.5849 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Convertible Note Principal Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
3.25% Convertible Note, Conversion Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | $42.40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
3.25% Convertible Debt, Liability Component ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 94,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
3.25% Convertible Debt, Equity Component ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
3.25% Convertible Debt, Remaining Discount Amortization Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2 years 4 months 28 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate During Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.40% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Convertible Debt, Interest Expense ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,700,000 | 3,700,000 | 3,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Convertible Debt, Amortization of Debt Discount ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,700,000 | 3,400,000 | 3,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Convertible, If-converted Value in Excess of Principal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Issuance Costs ($) | ' | ' | ' | ' | 2,352,000 | 11,969,000 | 680,000 | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Call Date, Latest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Oct-17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss on extinguishment of debt | -23,283,000 | 0 | 0 | 0 | 0 | -23,283,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Initiation Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5-Nov-10 | ' | ' | ' | 30-Apr-10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Current Borrowing Capacity ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 450,000,000 | ' | ' | ' | 105,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt agreement Amendment date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21-May-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | 400,000,000 | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Corporate Line of Credit Outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 49,000,000 | ' | ' |
Proportionate Share of PDCM Credit Facility ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Expiration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21-May-18 | ' | ' | ' | ' | 30-Apr-17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
PDCM Line of Credit Outstanding ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,000,000 | 26,250,000 | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,700,000 | 11,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
PDCE's proportionate share of Second Lien Term Note | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $438,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt, Weighted Average Interest Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.70% | 3.50% | ' | ' | 8.50% | ' | ' | ' | ' | ' | ' | ' | 2.30% | ' | ' |
Credit Facility - Restrictive Covenants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit Facility - Covenant Description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. | ' | ' | ' | 'The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests that must be met on a quarterly basis. The financial tests, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.25 to 1.0 (declining to 4.0 to 1.0 on July 1, 2014) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. | ' | ' | ' | 'The Term Loan Agreement contains financial covenants that must be met on a quarterly basis, including requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.5 to 1.0, to maintain a minimum interest coverage ratio of 2.25 to 1.0 and a present value of future net revenues to total debt ratio of 1.50 to 1.00. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loans Receivable, Basis Spread on Variable Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.00% | 7.00% |
ASSET_RETIREMENT_OBLIGATIONS_A1
ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) (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] | ' | ' | ' | ||
Balance beginning of year, January 1 | $62,563 | $46,566 | ' | ||
Obligations incurred with development activities and assumed with acquisitions | 2,389 | 14,169 | ' | ||
Accretion of asset retirement obligation | 4,747 | 4,060 | 1,897 | ||
Obligations discharged with disposal of properties and asset retirements | -29,281 | -2,232 | ' | ||
Revisions in estimated cash flows | 612 | 0 | ' | ||
Balance end of year, December 31 | 41,030 | 62,563 | 46,566 | ||
Less: Liabilities held for sale | -2,061 | [1] | 0 | [1] | ' |
Less: Current portion | -1,158 | -1,000 | ' | ||
Long-term portion | $37,811 | $61,563 | ' | ||
[1] | Represents asset retirement obligations related to assets sold and assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. |
EMPLOYEE_BENEFIT_PLANS_Employe
EMPLOYEE BENEFIT PLANS Employee Benefit Plan (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ' |
Postretirement Benefit Expense | $3.70 | $3.40 | $2.60 |
Deferred Compensation Liability, Current and Noncurrent | 1.8 | 2 | ' |
Deferred Compensation Liability, Current | 0.3 | 0.3 | ' |
Supplemental Health Care Benefits Liability, Noncurrent | $0.70 | $0.70 | ' |
COMMITMENTS_AND_CONTINGENCIES_1
COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2013 |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 231,023 |
Dollar Commitment ($ in thousands) | 70,000 |
First Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 20,666 |
Dollar Commitment ($ in thousands) | 7,547 |
Second Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 22,223 |
Dollar Commitment ($ in thousands) | 7,907 |
Third Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 23,789 |
Dollar Commitment ($ in thousands) | 8,230 |
Fourth Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 23,724 |
Dollar Commitment ($ in thousands) | 7,790 |
commitments 5 years and beyond [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 140,621 |
Dollar Commitment ($ in thousands) | 38,526 |
Appalachiain Basin [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 205,064 |
Appalachiain Basin [Member] | First Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 18,212 |
Appalachiain Basin [Member] | Second Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 19,485 |
Appalachiain Basin [Member] | Third Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 21,044 |
Appalachiain Basin [Member] | Fourth Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 20,987 |
Appalachiain Basin [Member] | commitments 5 years and beyond [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 125,336 |
Appalachiain Basin [Member] | Supply Contract Expiration Date [Member] | ' |
Supply Commitment [Line Items] | ' |
Supply Commitments Contract Expiration Date | 31-Jan-26 |
Utica Shale [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 25,959 |
Utica Shale [Member] | First Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,454 |
Utica Shale [Member] | Second Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,738 |
Utica Shale [Member] | Third Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,745 |
Utica Shale [Member] | Fourth Year Commitment [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,737 |
Utica Shale [Member] | commitments 5 years and beyond [Member] | ' |
Supply Commitment [Line Items] | ' |
Oil and Gas Delivery Commitments Volumes (MMcf) | 15,285 |
Utica Shale [Member] | Supply Contract Expiration Date [Member] | ' |
Supply Commitment [Line Items] | ' |
Supply Commitments Contract Expiration Date | 22-Jul-23 |
COMMITMENTS_AND_CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items] | ' |
2014 | $2,427 |
2015 | 1,970 |
2016 | 471 |
2017 | 257 |
2018 | 34 |
Thereafter | 941 |
Total | $6,100 |
COMMITMENTS_AND_CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES Additional information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Commitments and Contingencies Disclosure [Abstract] | ' | ' | ' |
Accrued Environmental Liabilities | $5.40 | $8.40 | ' |
Operating Lease Expense | $7 | $6.10 | $5.90 |
COMMON_STOCK_Stockholders_Equi
COMMON STOCK Stockholders' Equity Note (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 19, 2013 | 21-May-12 |
August 2013 Common Stock Issuance [Member] | May 2012 Common Stock Issuance [Member] | |||
Class of Stock [Line Items] | ' | ' | ' | ' |
Stock Issuance Date | ' | ' | 19-Aug-13 | 21-May-12 |
Stock Issued During Period, Shares, New Issues | ' | ' | 5,175,000 | 6,500,000 |
Common Stock, Par or Stated Value Per Share | $0.01 | $0.01 | $0.01 | ' |
Sale of Stock, Price Per Share | ' | ' | $53.37 | $26.50 |
Proceeds from Issuance of Common Stock | ' | ' | $275,800,000 | $164,500,000 |
Common Stock, Value, Issued | 357,000 | 303,000 | 51,750 | 65,000 |
Additional paid-in capital | $674,211,000 | $387,494,000 | $275,800,000 | $164,400,000 |
COMMON_STOCK_Stock_based_compe
COMMON STOCK Stock based compensation plans (Details) | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 29, 2010 |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ' | ' | ' |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 | 3,000,000 |
Common stock shares remain avaliable for issuance | 1,708,107 | ' | ' |
COMMON_STOCK_Stocked_Based_Com
COMMON STOCK Stocked Based Compensation Summary (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ' | ' | ' | |
Stock-based compensation expense | $12,880,000 | $8,495,000 | $8,781,000 | [1] |
Income tax benefit | -4,697,000 | -3,245,000 | -3,344,000 | |
Net stock-based compensation expense | 8,183,000 | 5,250,000 | 5,437,000 | |
shared based compensation for executive | ' | ' | $2,500,000 | |
[1] | Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 16, Transactions with Affiliates, for additional information regarding the related separation agreement. |
COMMON_STOCK_Schedule_of_Chang
COMMON STOCK Schedule of Changes in Stock Option Awards (Details) (Employee Stock Option [Member], USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Employee Stock Option [Member] | ' | ' | ' |
Number of Shares | ' | ' | ' |
Outstanding beginning of year, January 1, | 6,973 | 6,973 | 10,306 |
Exercised | -3,450 | 0 | 0 |
Forfeited | 0 | 0 | -3,333 |
Outstanding end of year, December 31, | 3,523 | 6,973 | 6,973 |
Exercisable at December 31, | 3,523 | 6,973 | 6,973 |
Weighted-Average Exercise Price | ' | ' | ' |
Outstanding beginning of year, January 1, | $41.09 | $41.09 | $41.90 |
Exercised | $37.15 | $0 | $0 |
Forfeited | $0 | $0 | $43.60 |
Outstanding end of year, December 31, | $44.95 | $41.09 | $41.09 |
Exercisable at December 31, | $44.95 | $41.09 | $41.09 |
Weighted-Average Remaining Contractual Term (in years) | ' | ' | ' |
Outstanding at December 31, | '2 years 2 months 15 days | '2 years 7 months 5 days | ' |
Exercisable at December 31, | '2 years 2 months 15 days | ' | ' |
Aggregate Intrinsic Value (in thousands) | ' | ' | ' |
Outstanding at December 31 | $29 | $0 | ' |
Exercised during period | 77 | ' | ' |
Exercisable at December 31 | $29 | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | 'Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. | ' | ' |
COMMON_STOCK_SARs_Fair_Value_A
COMMON STOCK SARs Fair Value Assumptions (Details) (Stock Appreciation Rights (SARs) [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Rate | Rate | Rate | |
Stock Appreciation Rights (SARs) [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | 'The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. | ' | ' |
Expected term of award | '6 years | '6 years | '6 years |
Risk-free interest rate | 1.00% | 1.10% | 2.50% |
Expected Volatility | 65.50% | 64.30% | 60.20% |
Weighted-average grant date fair value per share | $21.96 | $17.61 | $25.22 |
COMMON_STOCK_Schedule_of_Chang1
COMMON STOCK Schedule of Changes in SARs (Details) (Stock Appreciation Rights (SARs) [Member], USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 01, 2010 | |
Stock Appreciation Rights (SARs) [Member] | ' | ' | ' | ' |
Number of SARs | ' | ' | ' | ' |
Outstanding beginning of year, January 1, | 118,832 | 50,471 | ' | 57,282 |
Awarded | 87,078 | 68,361 | 31,552 | ' |
Exercised | -15,147 | 0 | -25,371 | ' |
Forfeited | 0 | 0 | -12,992 | ' |
Outstanding end of year, December 31, | 190,763 | 118,832 | 50,471 | 57,282 |
Exercisable at December 31, | 51,922 | 27,458 | 10,636 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | ' | ' | ' | ' |
Outstanding beginning of year, January 1, | $30.80 | $31.61 | ' | $24.44 |
Awarded | $37.18 | $30.19 | $43.95 | ' |
Exercised | $30.06 | $0 | $24.44 | ' |
Forfeited | $0 | $0 | $43.95 | ' |
Outstanding end of year, December 31, | $33.77 | $30.80 | $31.61 | $24.44 |
Exercisable at December 31, | $29.97 | $28.84 | $24.44 | ' |
Weighted-Average Remaining Contractual Term (in years) | ' | ' | ' | ' |
Outstanding at December 31, | '8 years 2 months 0 days | '8 years 4 months 30 days | ' | ' |
Exercisable at December 31, | '7 years 1 month 0 days | ' | ' | ' |
Share based compesation aggregate intrinsic valu [Roll Forward] | ' | ' | ' | ' |
Outstanding beginning of year, January 1, | $3,711,000 | $486,000 | $341,000 | $1,020,000 |
Awarded | 0 | 0 | 0 | ' |
Exercised | 425,000 | 0 | 77,000 | ' |
Forfeited | 0 | 0 | 0 | ' |
Outstanding end of year, December 31, | 3,711,000 | 486,000 | 341,000 | 1,020,000 |
Exercisable at December 31, | 1,207,000 | 187,000 | 114,000 | ' |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $1,700,000 | ' | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | '1 year 9 months 0 days | ' | ' | ' |
COMMON_STOCK_Schedule_of_Chang2
COMMON STOCK Schedule of Changes in Restricted Stock - TIme Based Awards (Details) (Restricted Stock [Member], USD $) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock [Member] | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | ' | 'The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed. | ' | ' |
Time based shares granted to executives | ' | 103,050 | ' | ' |
Number of Shares | ' | ' | ' | ' |
Outstanding beginning of year, January 1, | 646,490 | 646,490 | ' | ' |
Granted | ' | 311,051 | ' | ' |
Vested | ' | -282,787 | ' | ' |
Forfeited | ' | -22,973 | ' | ' |
Outstanding end of year, December 31, | ' | 651,781 | 646,490 | ' |
Weighted-Average Grant-Date Fair Value | ' | ' | ' | ' |
Outstanding at beginning of year, January 1, | $27.93 | $27.93 | ' | ' |
Weighted-average grant date fair value per share | ' | $45.53 | $26.59 | $33.71 |
Vested | ' | $27.57 | ' | ' |
Forfeited | ' | $31.52 | ' | ' |
Outstanding at end of year, December 31, | ' | $36.36 | $27.93 | ' |
Total intrinsic value of time based awards vested | ' | $13,640,000 | $5,950,000 | $9,030,000 |
Total intrinsic value of time-based awards non-vested | ' | 34,688,000 | 21,470,000 | 18,531,000 |
Market price per common share as of December 31, | ' | $53.22 | $33.21 | $35.11 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | ' | $15,700,000 | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | '2 years 0 months 0 days | ' | ' | ' |
COMMON_STOCK_Restricted_Stock_
COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) (Restricted Stock - Market Based Awards [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Rate | Rate | ||
Restricted Stock - Market Based Awards [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Expected term of award | '3 years | '3 years | ' |
Risk-free interest rate | 0.40% | 0.30% | ' |
Expected Volatility | 56.60% | 65.30% | ' |
Weighted-average grant date fair value per share | $49.04 | $36.54 | $58.53 |
COMMON_STOCK_Schedule_of_Chang3
COMMON STOCK Schedule of Changes in Restricted Stock - Market Based Awards (Details) (Restricted Stock - Market Based Awards [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock - Market Based Awards [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Total intrinsic value of time based awards vested | $724,000 | $0 | $366,000 |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | 'The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. | ' | ' |
Time based shares granted to executives | 41,570 | ' | ' |
Number of Shares | ' | ' | ' |
Outstanding beginning of year, January 1, | 40,696 | ' | ' |
Granted | 41,570 | ' | ' |
Vested | -10,155 | ' | ' |
Outstanding end of year, December 31, | 72,111 | 40,696 | ' |
Weighted-Average Grant-Date Fair Value | ' | ' | ' |
Outstanding at beginning of year, January 1, | $39.22 | ' | ' |
Weighted-average grant date fair value per share | $49.04 | $36.54 | $58.53 |
Vested | $47.28 | ' | ' |
Outstanding at end of year, December 31, | $43.75 | $39.22 | ' |
Total intrinsic value of market-based awards non-vested | 3,838,000 | 1,352,000 | 1,513,000 |
Market price per common share as of December 31, | $53.22 | $33.21 | $35.11 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $1,700,000 | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | '1 year 9 months 0 days | ' | ' |
COMMON_STOCK_Treasury_Shares_D
COMMON STOCK Treasury Shares (Details) (Treasury Stock [Member]) | 12 Months Ended |
Dec. 31, 2013 | |
Treasury Stock [Member] | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' |
Treasury Stock, Shares, Acquired | 84,642 |
Treasury Stock, Shares, Retired | 17,257 |
Treasury stock acquired and reissued | 67,334 |
Treasury stock acquired, and available for reissuance | 51 |
COMMON_STOCK_Preferred_Stock_D
COMMON STOCK Preferred Stock (Details) | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 23, 2008 | Dec. 31, 2013 |
Preferred Stock [Member] | Preferred Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' |
Equity Issuance, Date | ' | ' | 23-Jun-08 | ' |
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 | 50,000,000 | ' |
Preferred Stock, Shares Issued | 0 | 0 | ' | 0 |
EARNINGS_PER_SHARE_Earnings_Pe
EARNINGS PER SHARE Earnings Per Share (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | |||||||||||||||||||||||
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 | 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 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Nov. 15, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Stock Appreciation Rights [Member] | Stock Appreciation Rights [Member] | Stock Appreciation Rights [Member] | Stock Options [Member] | Stock Options [Member] | Stock Options [Member] | 3.25% Convertible Note [Member] | 3.25% Convertible Note [Member] | 3.25% Convertible Note [Member] | 3.25% Convertible Senior Notes due 2016 [Member] | Non employee director deferred compensation [Member] | Non employee director deferred compensation [Member] | Non employee director deferred compensation [Member] | ||||||||||||
Reconciliation of Weighted-Average Diluted Shares Outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average common shares outstanding - basic | 35,620,000 | 33,413,000 | 30,332,000 | 30,270,000 | 30,233,000 | 30,214,000 | 26,597,000 | 23,609,000 | 32,426,000 | 27,677,000 | 23,521,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incremental Common Shares Attributable to Share-based Payment Arrangements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 307,000 | 0 | 0 | 40,000 | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 3,000 |
Weighted Average Number of Shares Outstanding - Diluted | 36,836,000 | 33,413,000 | 31,014,000 | 30,270,000 | 30,233,000 | 30,214,000 | 26,728,000 | 23,889,000 | 32,426,000 | 27,677,000 | 23,871,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Anti-dilutive Effect | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | ' | ' | ' | ' | ' | ' | ' | ' | 1,424,000 | 820,000 | 251,000 | 823,000 | 694,000 | 220,000 | 72,000 | 116,000 | 22,000 | 7,000 | 7,000 | 9,000 | 518,000 | 0 | 0 | ' | 4,000 | 3,000 | 0 |
Convertible Senior Note Due 2016 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Convertible Senior Note Principal Amount ($ per Note) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,000 | ' | ' | ' |
3.25% Convertible Note, Number of Shares Convertible | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,700,000 | ' | ' | ' |
3.25% Convertible Note, Conversion Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $42.40 | ' | ' | ' |
ASSETS_HELD_FOR_SALE_DIVESTITU2
ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Discontinued Operations and Disposal Groups (Details) (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 | ||||
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Asset retirement obligation | $2,061 | [1] | ' | ' | ' | $0 | [1] | ' | ' | ' | $2,061 | [1] | $0 | [1] | ' |
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Impairment of Natural Gas and Crude Oil Properties | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 162,254 | 22,858 | ||||
Income (loss) from discontinued operations, net of tax | 0 | -782 | 3,416 | 1,537 | -106,549 | -4,632 | -6,907 | 9,071 | 4,171 | -109,017 | -9,127 | ||||
Net Assets Held for Sale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Properties and equipment | 2,785 | ' | ' | ' | ' | ' | ' | ' | 2,785 | ' | ' | ||||
Asset retirement obligation | -2,061 | ' | ' | ' | ' | ' | ' | ' | -2,061 | ' | ' | ||||
Net assets | 724 | ' | ' | ' | ' | ' | ' | ' | 724 | ' | ' | ||||
Net Assets Related to Discontinued Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Natural gas, NGL and crude oil sales | ' | ' | ' | ' | ' | ' | ' | ' | 20,398 | 36,422 | 80,860 | ||||
Sales from natural gas marketing | ' | ' | ' | ' | ' | ' | ' | ' | 2,825 | 1,708 | 2,949 | ||||
Well operations, pipeline income and other | ' | ' | ' | ' | ' | ' | ' | ' | 890 | 1,888 | 2,542 | ||||
Disposal Group, Discontinued Operations, Total revenue | ' | ' | ' | ' | ' | ' | ' | ' | 24,113 | 40,018 | 86,351 | ||||
Production Costs | ' | ' | ' | ' | ' | ' | ' | ' | 7,975 | 22,453 | 30,885 | ||||
Cost of natural gas marketing | ' | ' | ' | ' | ' | ' | ' | ' | 2,673 | 1,529 | 2,634 | ||||
Impairment of Natural Gas and Crude Oil Properties | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 162,254 | 22,858 | ||||
Depreciation, depletion and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 2,258 | 48,101 | 47,521 | ||||
Accretion of ARO and other, Discontinued Operations | ' | ' | ' | ' | ' | ' | ' | ' | 2,528 | 2,084 | 1,054 | ||||
(Gain) loss on sale of properties and equipment | ' | ' | ' | ' | ' | ' | ' | ' | 2,330 | -19,920 | -3,854 | ||||
Total costs, expenses and other | ' | ' | ' | ' | ' | ' | ' | ' | 17,767 | 216,501 | 101,098 | ||||
Income (loss) from discontinued operations | ' | ' | ' | ' | ' | ' | ' | ' | 6,346 | -176,483 | -14,747 | ||||
Income taxes (expense) benefit | ' | ' | ' | ' | ' | ' | ' | ' | -2,175 | 67,466 | 5,620 | ||||
Income (loss) from discontinued operations, net of tax | ' | ' | ' | ' | ' | ' | ' | ' | $4,171 | ($109,017) | ($9,127) | ||||
[1] | Represents asset retirement obligations related to assets sold and assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. |
ASSETS_HELD_FOR_SALE_DIVESTITU3
ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Additional Information (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2013 | Oct. 08, 2013 |
Shallow Upper Devonian Sale [Member] | Piceance and NECO Asset Group [Member] | Permian Basin [Member] | Permian Basin [Member] | Permian Basin [Member] | Segment, Discontinued Operations [Member] | Segment, Discontinued Operations [Member] | Segment, Discontinued Operations [Member] | Shallow Upper Devonian Letter of Credit [Member] | Shallow Upper Devonian Sale [Member] | ||
PDCE proportionate share | |||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shallow Upper Devonian wells divested | 3,500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Oil and gas assets sale price before adjustments | ' | $20,600,000 | ' | ' | $173,900,000 | ' | ' | ' | ' | ' | $5,100,000 |
Proceeds from Sale of Oil and Gas Property and Equipment | ' | 900,000 | 177,600,000 | 189,200,000 | ' | 13,200,000 | ' | ' | ' | ' | ' |
Proceeds To NonAffiliated Investor Partners | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax | ' | ' | -2,300,000 | 19,900,000 | ' | ' | -2,330,000 | 19,920,000 | 3,854,000 | ' | ' |
Notes Receivable from sale of oil and gas properties | ' | 3,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accounts Receivable from sale of oil and gas properties | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount ($) | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6,700,000 | ' |
ACQUISITIONS_Total_Identifiabl
ACQUISITIONS Total Identifiable Net Assets Acquired (Details) (USD $) | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | Merit Acquisition [Member] | Seneca Upshur [Domain] | 2003/2002-D Partnerships [Member] | 2005 Partnerships [Member] |
Business Acquisition [Line Items] | ' | ' | ' | ' |
Total acquisition cost | $304,643 | $69,618 | $29,960 | $43,015 |
Natural gas and crude oil properties - proved | 180,696 | 20,175 | 27,940 | 39,825 |
Natural gas and crude oil properties - unproved | 151,428 | 49,100 | 0 | 0 |
Other assets | 3,631 | 10,196 | 3,455 | 3,848 |
Total assets acquired | 335,755 | 79,471 | 31,395 | 43,673 |
Asset retirement obligation | 14,833 | 8,157 | 497 | 300 |
Other accrued expenses | 9,574 | 0 | 0 | 0 |
Other Liabilities | 6,705 | 1,696 | 938 | 358 |
Total liabilities assumed | $31,112 | $9,853 | $1,435 | $658 |
ACQUISITIONS_Additional_Inform
ACQUISITIONS Additional Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Acquisition costs: | ' | ' | ' |
Title defect reimbursements | $7,579,000 | $14,469,000 | $0 |
Michigan Assets Deferred Tax Liabilities | 96,393,000 | 112,276,000 | ' |
Merit Acquisition [Member] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Total acquisition cost | ' | 304,643,000 | ' |
Seneca Upshur [Domain] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Total acquisition cost | ' | ' | 69,618,000 |
Title defect reimbursements | ' | 14,500,000 | ' |
2003/2002-D Partnerships [Member] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Total acquisition cost | ' | ' | 29,960,000 |
2005 Partnerships [Member] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Total acquisition cost | ' | ' | 43,015,000 |
PDCM [Member] | Seneca Upshur [Domain] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Acquisition Costs, Cumulative | ' | ' | 139,200,000 |
Title defect reimbursements | ' | 28,900,000 | ' |
Segment, Discontinued Operations [Member] | ' | ' | ' |
Acquisition costs: | ' | ' | ' |
Gain on sale of Michigan assets | ($2,330,000) | $19,920,000 | $3,854,000 |
ACQUISITIONS_Pro_Forma_Informa
ACQUISITIONS Pro Forma Information (Details) (Merit Acquisition [Member], USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2011 |
Merit Acquisition [Member] | ' | ' |
Business Acquisition, Pro Forma Information [Abstract] | ' | ' |
Revenues | $370,488 | $438,204 |
Total costs, expenses and other | 521,178 | 366,120 |
Net Income (Loss) | ($119,343) | $45,688 |
Basic | ($4.31) | $1.94 |
Diluted | ($4.31) | $1.91 |
TRANSACTIONS_WITH_AFFILIATES_A2
TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Transactions with Affiliates and Other Related Parties (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
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 | |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Production costs | $22,299,000 | $19,057,000 | $16,176,000 | $15,858,000 | $13,594,000 | $15,797,000 | $12,373,000 | $12,936,000 | $73,390,000 | $54,700,000 | $44,832,000 |
Exploration expense | 1,883,000 | 2,030,000 | 1,437,000 | 1,689,000 | 14,875,000 | 1,773,000 | 2,374,000 | 1,872,000 | 7,039,000 | 20,894,000 | 5,734,000 |
General and administrative expense | 16,991,000 | 16,080,000 | 15,783,000 | 15,115,000 | 16,019,000 | 13,710,000 | 14,378,000 | 14,708,000 | 63,969,000 | 58,815,000 | 61,454,000 |
PDCM | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related party transactions included in cost of natural gas marketing | ' | ' | ' | ' | ' | ' | ' | ' | 18,100,000 | 10,900,000 | 9,500,000 |
Well operating and administrative services on behalf of PDCM | ' | ' | ' | ' | ' | ' | ' | ' | 14,500,000 | 12,100,000 | 10,400,000 |
Affiliated Partnerships | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related party transactions included in cost of natural gas marketing | ' | ' | ' | ' | ' | ' | ' | ' | 1,300,000 | 500,000 | 1,300,000 |
PDCE proportionate share | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Production costs | ' | ' | ' | ' | ' | ' | ' | ' | 4,097,000 | 3,945,000 | 3,441,000 |
Exploration expense | ' | ' | ' | ' | ' | ' | ' | ' | 502,000 | 492,000 | 430,000 |
General and administrative expense | ' | ' | ' | ' | ' | ' | ' | ' | 2,649,000 | 1,630,000 | 1,543,000 |
Former Executive Officer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
General and administrative expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,700,000 |
Separation Compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,100,000 |
Non-qualified supplemental retirement benefit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $30,000 |
TRANSACTIONS_WITH_AFFILIATES_A3
TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Additional Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
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 | |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
General and administrative expense | $16,991,000 | $16,080,000 | $15,783,000 | $15,115,000 | $16,019,000 | $13,710,000 | $14,378,000 | $14,708,000 | $63,969,000 | $58,815,000 | $61,454,000 |
Former Executive Officer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Separation Compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,100,000 |
Non-qualified supplemental retirement benefit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000 |
General and administrative expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6,700,000 |
Recovered_Sheet1
BUSINESS SEGMENTS Business segments (Details) (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 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment revenues | $141,067 | $77,116 | $121,305 | $71,826 | $97,139 | $32,720 | $99,740 | $91,006 | $411,314 | $320,605 | $337,289 |
Segment income (loss) before income taxes | 21,258 | -25,373 | 26,293 | -63,447 | -31,392 | -43,279 | 29,391 | 10,884 | -41,269 | -34,396 | 34,364 |
Expenditures for segment long-lived assets | ' | ' | ' | ' | ' | ' | ' | ' | 404,606 | 659,952 | 480,390 |
Segment assets | 2,025,203 | ' | ' | ' | 1,826,848 | ' | ' | ' | 2,025,203 | 1,826,848 | ' |
Oil and Gas Properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment revenues | ' | ' | ' | ' | ' | ' | ' | ' | 341,527 | 275,234 | 273,819 |
Segment income (loss) before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 79,527 | 103,111 | 138,616 |
Expenditures for segment long-lived assets | ' | ' | ' | ' | ' | ' | ' | ' | 403,227 | 656,443 | 479,027 |
Segment assets | 1,934,466 | ' | ' | ' | 1,723,011 | ' | ' | ' | 1,934,466 | 1,723,011 | ' |
Marketing | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment revenues | ' | ' | ' | ' | ' | ' | ' | ' | 69,787 | 45,371 | 63,470 |
Segment income (loss) before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -298 | 349 | 639 |
Segment assets | 20,342 | ' | ' | ' | 11,090 | ' | ' | ' | 20,342 | 11,090 | ' |
Corporate and Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment income (loss) before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -120,498 | -137,856 | -104,891 |
Expenditures for segment long-lived assets | ' | ' | ' | ' | ' | ' | ' | ' | 1,379 | 3,509 | 1,363 |
Segment assets | 67,610 | ' | ' | ' | 92,747 | ' | ' | ' | 67,610 | 92,747 | ' |
Assets Held-for-sale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment assets | $2,785 | ' | ' | ' | $0 | ' | ' | ' | $2,785 | $0 | ' |
BUSINESS_SEGMENTS_Additional_I
BUSINESS SEGMENTS Additional Information (Details) (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 |
Crude oil and natural gas segment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation, depletion and amortization from continuing operations | $40,641 | $30,870 | $27,800 | $27,949 | $24,906 | $22,121 | $23,839 | $27,912 | $127,260 | $98,778 | $87,633 |
Oil and Gas Properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Crude oil and natural gas segment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation, depletion and amortization from continuing operations | ' | ' | ' | ' | ' | ' | ' | ' | $122,200 | $94,100 | $83,600 |
SUPPLEMENTAL_INFORMATION_NATUR2
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Crude Oil (Bbls) | ' | ' | ' |
Schedule of Prices Used to Estimate Reserves [Line Items] | ' | ' | ' |
prices used to estimate oil and gas reserves | $82.18 | $87.51 | $88.94 |
Natural Gas (Mcf) | ' | ' | ' |
Schedule of Prices Used to Estimate Reserves [Line Items] | ' | ' | ' |
prices used to estimate oil and gas reserves | 3.22 | 2.35 | 3.41 |
Natural Gas Liquids (Bbls) | ' | ' | ' |
Schedule of Prices Used to Estimate Reserves [Line Items] | ' | ' | ' |
prices used to estimate oil and gas reserves | $29.92 | $28.02 | $39.59 |
SUPPLEMENTAL_INFORMATION_NATUR3
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) | 12 Months Ended | ||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | ||||
bbl | bbl | bbl | bbl | ||||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | 265,774,000 | 192,810,000 | 169,248,000 | ' | |||
Undeveloped Reserves Converted to Developed | 0 | 0 | ' | ' | |||
Revisions of Previous Estimates | -46,480,000 | -58,639,000 | ' | ' | |||
Extensions, Discoveries, and Other Additions | 141,935,000 | 67,941,000 | ' | ' | |||
Purchases of Reserves | 1,043,000 | 33,420,000 | ' | ' | |||
Dispositions | -16,104,000 | -10,891,000 | ' | ' | |||
Production | -7,430,000 | -8,269,000 | ' | ' | |||
Crude Oil (Bbls) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | 93,830,000 | 59,310,000 | [1] | 37,636,000 | [2] | 23,236,000 | |
Revisions of Previous Estimates | -18,420,000 | -6,729,000 | -1,904,000 | ' | |||
Extensions, Discoveries, and Other Additions | 55,759,000 | 27,482,000 | 17,092,000 | ' | |||
Purchases of Reserves | 343,000 | 10,801,000 | 1,605,000 | ' | |||
Dispositions | -252,000 | -7,854,000 | -435,000 | ' | |||
Production | -2,910,000 | -2,026,000 | -1,958,000 | ' | |||
Proved Developed Reserves | 23,997,000 | 20,412,000 | [1] | 16,910,000 | [2] | 8,287,000 | |
Proved Undeveloped Reserve | 69,833,000 | 38,898,000 | [1] | 20,726,000 | [2] | 14,949,000 | |
Natural Gas (Mcf) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | 739,640,000 | 604,038,000 | [1] | 672,145,000 | [2] | 657,306,000 | |
Revisions of Previous Estimates | -117,068,000 | -289,436,000 | -161,654,000 | ' | |||
Extensions, Discoveries, and Other Additions | 365,563,000 | 172,933,000 | 176,689,000 | ' | |||
Purchases of Reserves | 2,894,000 | 87,212,000 | 32,761,000 | ' | |||
Dispositions | -94,927,000 | -6,406,000 | -2,070,000 | ' | |||
Production | -20,860,000 | -32,410,000 | -30,887,000 | ' | |||
Proved Developed Reserves | 220,387,000 | 281,925,000 | [1] | 299,369,000 | [2] | 227,341,000 | |
Proved Undeveloped Reserve | 519,253,000 | 322,113,000 | [1] | 372,776,000 | [2] | 429,965,000 | |
Natural Gas Liquids (Bbls) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | 48,671,000 | 32,827,000 | [1] | 19,588,000 | [2] | 10,649,000 | |
Revisions of Previous Estimates | -8,549,000 | -3,671,000 | 3,163,000 | ' | |||
Extensions, Discoveries, and Other Additions | 25,249,000 | 11,637,000 | 5,633,000 | ' | |||
Purchases of Reserves | 217,000 | 8,084,000 | 1,052,000 | ' | |||
Dispositions | -30,000 | -1,970,000 | -94,000 | ' | |||
Production | -1,043,000 | -841,000 | -815,000 | ' | |||
Proved Developed Reserves | 14,825,000 | 14,353,000 | [1] | 11,753,000 | [2] | 4,013,000 | |
Proved Undeveloped Reserve | 33,846,000 | 18,474,000 | [1] | 7,835,000 | [2] | 6,636,000 | |
Crude Oil Equivalent (Boe) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | 265,774,000 | 192,810,000 | [1] | 169,248,000 | [2] | 143,436,000 | |
Revisions of Previous Estimates | -46,480,000 | -58,639,000 | -25,683,000 | ' | |||
Extensions, Discoveries, and Other Additions | 141,935,000 | 67,941,000 | 52,173,000 | ' | |||
Purchases of Reserves | 1,043,000 | 33,420,000 | 8,117,000 | ' | |||
Dispositions | -16,104,000 | -10,891,000 | -874,000 | ' | |||
Production | -7,430,000 | -8,269,000 | -7,921,000 | ' | |||
Proved Developed Reserves | 75,553,000 | 81,753,000 | [1] | 78,558,000 | [2] | 50,190,000 | |
Proved Undeveloped Reserve | 190,221,000 | 111,058,000 | [1] | 90,690,000 | [2] | 93,246,000 | |
Permian Asset Group | Crude Oil (Bbls) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | ' | ' | 7,825,000 | [2] | ' | ||
Proved Developed Reserves | ' | ' | 1,815,000 | [2] | ' | ||
Proved Undeveloped Reserve | ' | ' | 6,010,000 | [2] | ' | ||
Permian Asset Group | Natural Gas (Mcf) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | ' | ' | 6,242,000 | [2] | ' | ||
Proved Developed Reserves | ' | ' | 1,750,000 | [2] | ' | ||
Proved Undeveloped Reserve | ' | ' | 4,492,000 | [2] | ' | ||
Permian Asset Group | Natural Gas Liquids (Bbls) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | ' | ' | 1,970,000 | [2] | ' | ||
Proved Developed Reserves | ' | ' | 550,000 | [2] | ' | ||
Proved Undeveloped Reserve | ' | ' | 1,420,000 | [2] | ' | ||
Permian Asset Group | Crude Oil Equivalent (Boe) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Reserves | ' | ' | 10,835,000 | [2] | ' | ||
Proved Developed Reserves | ' | ' | 2,657,000 | [2] | ' | ||
Proved Undeveloped Reserve | ' | ' | 8,179,000 | [2] | ' | ||
Piceance and NECO Asset Group [Member] | Crude Oil (Bbls) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Developed Reserves | 148,000 | [2] | ' | ' | ' | ||
Piceance and NECO Asset Group [Member] | Natural Gas (Mcf) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Developed Reserves | 83,656,000 | [2] | ' | ' | ' | ||
Piceance and NECO Asset Group [Member] | Crude Oil Equivalent (Boe) | ' | ' | ' | ' | |||
Reserve Quantities [Line Items] | ' | ' | ' | ' | |||
Proved Developed Reserves | 14,091,000 | [2] | ' | ' | ' | ||
[1] | Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. | ||||||
[2] | Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. |
SUPPLEMENTAL_INFORMATION_NATUR4
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | 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 | |||
bbl | bbl | bbl | Crude Oil Equivalent (Boe) | Crude Oil Equivalent (Boe) | Crude Oil Equivalent (Boe) | Crude Oil Equivalent (Boe) | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Year-over-Year Activity [Domain] | Developed [Member] | Developed [Member] | Developed [Member] | Undeveloped [Member] | Undeveloped [Member] | Undeveloped [Member] | |||
bbl | bbl | bbl | bbl | Rate | Rate | Rate | Rate | Rate | bbl | bbl | bbl | bbl | bbl | bbl | bbl | bbl | bbl | ||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Proved Developed and Undeveloped Reserves, Net | 265,774,000 | 192,810,000 | 169,248,000 | 265,774,000 | 192,810,000 | [1] | 169,248,000 | [2] | 143,436,000 | ' | ' | ' | ' | ' | ' | ' | ' | 75,553,000 | 81,753,000 | 78,558,000 | 190,221,000 | 111,057,000 | 90,690,000 |
Undeveloped Reserves Converted to Developed | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,212,000 | 7,655,000 | ' | -3,212,000 | -7,655,000 | ' | ||
Revisions of Previous Estimates | -46,480,000 | -58,639,000 | ' | -46,480,000 | -58,639,000 | -25,683,000 | ' | ' | ' | ' | ' | ' | 46,000,000 | 59,000,000 | 26,000,000 | -6,751,000 | -18,318,000 | ' | -39,729,000 | -40,321,000 | ' | ||
Extensions, Discoveries, and Other Additions | 141,935,000 | 67,941,000 | ' | 141,935,000 | 67,941,000 | 52,173,000 | ' | ' | ' | ' | ' | ' | 142,000,000 | 68,000,000 | 52,000,000 | 19,830,000 | 11,298,000 | ' | 122,105,000 | 56,643,000 | ' | ||
Purchases of Reserves | 1,043,000 | 33,420,000 | ' | 1,043,000 | 33,420,000 | 8,117,000 | ' | ' | ' | ' | ' | ' | 1,000,000 | 33,000,000 | ' | 1,043,000 | 13,542,000 | ' | 0 | 19,878,000 | ' | ||
Dispositions | -16,104,000 | -10,891,000 | ' | -16,104,000 | -10,891,000 | -874,000 | ' | ' | ' | ' | ' | ' | -16,000,000 | -11,000,000 | -800,000 | -16,104,000 | -2,713,000 | ' | 0 | -8,178,000 | ' | ||
Production | -7,430,000 | -8,269,000 | ' | -7,430,000 | -8,269,000 | -7,921,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,430,000 | -8,269,000 | ' | 0 | 0 | ' | ||
Increase in reserves during period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Majority of downward revision of our previous estimate of proved reserves | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -55,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Downward revisions due to adjustments in previous PUD well spacing plans | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Downward revisions in reserves due to abandoned leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Downward revisions in reserves due to our shift from vertical to horizontal drilling | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Downward revision in reserves due to increase in operating costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | ' | ' | ' | ' | ' | ' | ' | ||
Revisions due to asset performance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 2,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ||
Revision in reserves due to production from uneconomic or divested wells | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revisions due to change in commodity pricing | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | -40,000,000 | -700,000 | ' | ' | ' | ' | ' | ' | ||
Reserve discoveries from non-PUD drilling | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Extension and discoveries from new proved undeveloped reserves | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 125,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Extension and discoveries due to adjustments in wells spacing in Wattenberg Field and Marcellus Shale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Extension and discoveries in the Marcellus Shale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Extension and discoveries in the Utica Shale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Adjustments for geological reasons | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,000,000 | ' | ' | ' | ' | ' | ' | ' | ||
PUD conversion rate | ' | ' | ' | ' | ' | ' | ' | 19.00% | 24.00% | 27.00% | 22.00% | 7.40% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Revision due to SEC 5 Year Rule | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -13,000,000 | -29,000,000 | ' | ' | ' | ' | ' | ' | ||
Revisions due to interest adjustments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | 500,000 | 800,000 | ' | ' | ' | ' | ' | ' | ||
Revisions due to transfers from PUD to PDNP | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ||
Revisions due to changes in production costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserve discoveries, Eastern Operating Region | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | 9,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserve discoveries, Wattenberg Field | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 110,000,000 | 59,000,000 | 24,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserve discoveries, Piceance Basin | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserve discoveries, Permian | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserves acquired, Eastern Operating Region | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserves acquired, Wattenberg Field | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserves acquired, Piceance Basin | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ||
Reserves disposition, North Dakota | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -300,000 | ' | ' | ' | ' | ' | ' | ||
Reserves disposition, Permian Basin | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -500,000 | ' | ' | ' | ' | ' | ' | ||
Development Wells Drilled, Net Productive | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ||
[1] | Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. | ||||||||||||||||||||||
[2] | Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. |
SUPPLEMENTAL_INFORMATION_NATUR5
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' |
Natural gas, NGL and crude oil sales | $379,796 | $274,783 | $304,157 |
Commodity price risk management | -23,905 | 32,339 | 46,090 |
Total Revenues from Oil and Gas Producing Activities | 355,891 | 307,122 | 350,247 |
Production Costs | 81,365 | 77,537 | 75,717 |
Exploration Expense | 7,071 | 22,605 | 6,289 |
Impairment of Oil and Gas Properties | 53,438 | 162,287 | 25,159 |
Depreciation, Depletion and Amortization | 124,202 | 146,879 | 128,458 |
Accretion of Asset Retirement Obligations | 4,747 | 4,060 | 1,897 |
Gain on Sale of Properties and Equipment | 3,722 | -24,273 | -4,050 |
Total Expense from Oil and Gas Producing Activities | 274,545 | 389,095 | 233,470 |
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes | 81,346 | -81,973 | 116,777 |
Provision for Income Taxes | -29,400 | 31,163 | -36,785 |
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs | $51,946 | ($50,810) | $79,992 |
SUPPLEMENTAL_INFORMATION_NATUR6
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Proved Properties | $28,698,000 | [1] | $105,303,000 | [1] | $79,554,000 | [1] |
Unproved Properties | 3,390,000 | [1] | 276,225,000 | [1] | 95,081,000 | [1] |
Development Costs | 332,250,000 | [2] | 233,144,000 | [2] | 301,008,000 | [2] |
Exploratory drilling | 58,988,000 | [3] | 18,803,000 | [3] | 3,626,000 | [3] |
Geological and geophysical | 752,000 | [3] | 1,925,000 | [3] | 1,846,000 | [3] |
Total Costs Incurred | 424,078,000 | 635,400,000 | 481,115,000 | |||
Cost Incurred to Convert PUDs to PDNP | $40,100,000 | $62,000,000 | $80,600,000 | |||
[1] | Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. | |||||
[2] | Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended DecemberB 31, 2013, 2012 and 2011, $40.1 million, $62.0 million and $80.6 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. | |||||
[3] | Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. |
SUPPLEMENTAL_INFORMATION_NATUR7
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' |
Proved natural gas and crude oil properties | $1,781,681 | $2,075,924 |
Unproved natural gas and crude oil properties | 307,203 | 319,327 |
Capitalized Costs, Uncompleted Wells, Equipment and Facilities | 51,773 | 62,392 |
Capitalized Costs | 2,140,657 | 2,457,643 |
Less accumulated DD&A | -529,607 | -905,458 |
Capitalized Costs, Net | $1,611,050 | $1,552,185 |
SUPPLEMENTAL_INFORMATION_NATUR8
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' |
Future Estimated Cash Flows | $11,550,917 | $7,529,292 | $6,415,255 |
Future Estimated Production Costs | -2,329,836 | -1,690,453 | -1,704,645 |
Future Estimated Development Costs | -2,778,148 | -1,852,177 | -1,474,137 |
Future Estimated Income Tax Expense | -2,119,615 | -1,230,294 | -946,849 |
Future Net Cash Flows | 4,323,318 | 2,756,368 | 2,289,624 |
10% Annual Discount for Estimated Timing of Cash Flows | -2,541,155 | -1,587,871 | -1,348,415 |
Standardized Measure of Disconted Future Estimated Net Cash Flows | $1,782,163 | $1,168,497 | $941,209 |
SUPPLEMENTAL_INFORMATION_NATUR9
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Unuadited) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Rate | Rate | Rate | ||||
Principal Sources of Change: | ' | ' | ' | |||
Sales of natural gas, NGL and crude oil production, net of production costs | ($286,021,000) | ($194,346,000) | ($226,227,000) | |||
Net changes in prices and production costs | 89,527,000 | [1] | 95,501,000 | [1] | 383,293,000 | [1] |
Extensions, discoveries and improved recovery, less related costs | 1,529,006,000 | [2] | 632,781,000 | [2] | 467,347,000 | [2] |
Sales of reserves | -142,724,000 | [3] | -86,902,000 | [3] | -4,224,000 | [3] |
Purchases of reserves | 10,610,000 | [4] | 296,208,000 | [4] | 64,761,000 | [4] |
Development costs incurred during the period | 46,366,000 | 69,198,000 | 94,941,000 | |||
Revisions of previous quantity estimates | -397,738,000 | [5] | -452,775,000 | [5] | -112,468,000 | [5] |
Changes in estimated income taxes | -381,369,000 | [6] | -131,256,000 | [6] | -204,377,000 | [6] |
Net change in future development costs | -40,707,000 | -3,979,000 | -29,827,000 | |||
Accretion of discount | 142,040,000 | 124,105,000 | 65,284,000 | |||
Timing and other | 44,676,000 | -121,247,000 | -45,712,000 | |||
Total | 613,666,000 | 227,288,000 | 452,791,000 | |||
Notes to Changes in SMOG [Abstract] | ' | ' | ' | |||
Weighted-Average price, net of production cost | $24.24 | $20.70 | $19.14 | |||
Percentage Change in Extensions and Discoveries | 142.00% | 35.00% | ' | |||
Increase in Extensions and Discoveries | ' | 30.00% | ' | |||
Gas component of extensions and discoveries | ' | 52.20% | ' | |||
Liquids component of extensions and discoveries | ' | 47.80% | ' | |||
Increase in extensions and discoveries related to PUDs | ' | 86.00% | ' | |||
Long-Term Deferred Tax Rate | 38.00% | 38.20% | 38.10% | |||
[1] | Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves. | |||||
[2] | The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. | |||||
[3] | The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012. | |||||
[4] | The decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field. | |||||
[5] | The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. | |||||
[6] | The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0%, 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. |
SUPPLEMENTAL_INFORMATION_QUART1
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) (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: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Natural gas, NGL and crude oil sales | $120,286 | $82,136 | $77,537 | $79,439 | $67,773 | $52,291 | $51,342 | $66,955 | $359,398 | $238,361 | $223,297 |
Sales from natural gas marketing | 21,092 | 16,946 | 18,079 | 13,670 | 14,199 | 11,178 | 8,613 | 11,381 | 69,787 | 45,371 | 63,470 |
Commodity price risk management gain (loss), net | -2,636 | -23,638 | 24,724 | -22,355 | 14,052 | -31,943 | 38,729 | 11,501 | -23,905 | 32,339 | 46,090 |
Well operations, pipeline income and other | 2,325 | 1,672 | 965 | 1,072 | 1,115 | 1,194 | 1,056 | 1,169 | 6,034 | 4,534 | 4,432 |
Total revenues | 141,067 | 77,116 | 121,305 | 71,826 | 97,139 | 32,720 | 99,740 | 91,006 | 411,314 | 320,605 | 337,289 |
Costs, expenses and other: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Production costs | 22,299 | 19,057 | 16,176 | 15,858 | 13,594 | 15,797 | 12,373 | 12,936 | 73,390 | 54,700 | 44,832 |
Cost of natural gas marketing | 21,156 | 17,127 | 18,065 | 13,736 | 14,182 | 11,260 | 8,490 | 11,091 | 70,084 | 45,023 | 62,831 |
Exploration expense | 1,883 | 2,030 | 1,437 | 1,689 | 14,875 | 1,773 | 2,374 | 1,872 | 7,039 | 20,894 | 5,734 |
Impairment of natural gas and crude oil properties | 1,002 | 4,472 | 1,502 | 46,459 | 4,563 | 388 | 356 | 588 | 53,435 | 5,895 | 2,301 |
General and administrative expense | 16,991 | 16,080 | 15,783 | 15,115 | 16,019 | 13,710 | 14,378 | 14,708 | 63,969 | 58,815 | 61,454 |
Depreciation, depletion and amortization | 40,641 | 30,870 | 27,800 | 27,949 | 24,906 | 22,121 | 23,839 | 27,912 | 127,260 | 98,778 | 87,633 |
Accretion of asset retirement obligations | 1,080 | 1,186 | 1,172 | 1,148 | 1,127 | 1,101 | 732 | 727 | 4,586 | 3,687 | 1,398 |
Gain on sale of Leaseholds | 2,151 | -712 | -9 | -38 | -445 | -1,508 | -2,246 | -154 | 1,392 | -4,353 | -196 |
Total cost, expenses and other | 107,203 | 90,110 | 81,926 | 121,916 | 88,821 | 64,642 | 60,296 | 69,680 | 401,155 | 283,439 | 265,987 |
Income (loss) from operations | 33,864 | -12,994 | 39,379 | -50,090 | 8,318 | -31,922 | 39,444 | 21,326 | 10,159 | 37,166 | 71,302 |
Loss on extinguishment of debt | ' | ' | ' | ' | -23,283 | 0 | 0 | 0 | 0 | -23,283 | 0 |
Interest expense | -12,943 | -12,509 | -13,089 | -13,357 | -16,430 | -11,360 | -10,053 | -10,444 | -51,898 | -48,287 | -36,985 |
Interest income | 337 | 130 | 3 | 0 | 3 | 3 | 0 | 2 | 470 | 8 | 47 |
Income (loss) from continuing operations before income taxes | 21,258 | -25,373 | 26,293 | -63,447 | -31,392 | -43,279 | 29,391 | 10,884 | -41,269 | -34,396 | 34,364 |
Provision for income taxes | -8,059 | 10,155 | -9,791 | 22,492 | 11,766 | 15,268 | -10,213 | -4,120 | 14,797 | 12,701 | -11,800 |
Income (loss) from continuing operations | 13,199 | -15,218 | 16,502 | -40,955 | -19,626 | -28,011 | 19,178 | 6,764 | -26,472 | -21,695 | 22,564 |
Income (loss) from discontinued operations, net of tax | 0 | -782 | 3,416 | 1,537 | -106,549 | -4,632 | -6,907 | 9,071 | 4,171 | -109,017 | -9,127 |
Net income (loss) | $13,199 | ($16,000) | $19,918 | ($39,418) | ($126,175) | ($32,643) | $12,271 | $15,835 | ($22,301) | ($130,712) | $13,437 |
Basic | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income (loss) from continuing operations | $0.37 | ($0.46) | $0.55 | ($1.35) | ($0.65) | ($0.93) | $0.72 | $0.29 | ($0.82) | ($0.78) | $0.96 |
Income (loss) from discontinued operations | $0 | ($0.02) | $0.11 | $0.05 | ($3.52) | ($0.15) | ($0.26) | $0.38 | $0.13 | ($3.94) | ($0.39) |
Net income (loss) attributable to shareholders | $0.37 | ($0.48) | $0.66 | ($1.30) | ($4.17) | ($1.08) | $0.46 | $0.67 | ($0.69) | ($4.72) | $0.57 |
Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income (loss) from continuing operations | $0.36 | ($0.46) | $0.53 | ($1.35) | ($0.65) | ($0.93) | $0.72 | $0.28 | ($0.82) | ($0.78) | $0.95 |
Income (loss) from discontinued operations | $0 | ($0.02) | $0.11 | $0.05 | ($3.52) | ($0.15) | ($0.26) | $0.38 | $0.13 | ($3.94) | ($0.39) |
Net income (loss) attributable to shareholders | $0.36 | ($0.48) | $0.64 | ($1.30) | ($4.17) | ($1.08) | $0.46 | $0.66 | ($0.69) | ($4.72) | $0.56 |
Weighted-average common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basic | 35,620 | 33,413 | 30,332 | 30,270 | 30,233 | 30,214 | 26,597 | 23,609 | 32,426 | 27,677 | 23,521 |
Diluted | 36,836 | 33,413 | 31,014 | 30,270 | 30,233 | 30,214 | 26,728 | 23,889 | 32,426 | 27,677 | 23,871 |
SCHEDULE_II_VALUATION_AND_QUAL
SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Allowance for Doubtful Accounts [Member] | ' | ' | ' | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | ' | ' | ' | |||
Beginning Balance, January 1 | $1,026 | $921 | $686 | |||
Deconsolidation/Purchase Price Adjustment for PDCM | 0 | 0 | 121 | |||
Charged to Cost and Expense | 423 | 258 | 135 | |||
Deductions | 188 | [1] | 153 | [1] | 21 | [1] |
Ending Balance, December 31 | 1,261 | 1,026 | 921 | |||
Valuation Allowance for Unproved Natural Gas and Crude Oil Properties [Member] | ' | ' | ' | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | ' | ' | ' | |||
Beginning Balance, January 1 | 8,036 | 12,204 | 16,996 | |||
Deconsolidation/Purchase Price Adjustment for PDCM | 0 | 0 | 260 | |||
Charged to Cost and Expense | 3,964 | 4,207 | 2,611 | |||
Deductions | 6,400 | [1] | 8,375 | [1] | 7,143 | [1] |
Ending Balance, December 31 | $5,600 | $8,036 | $12,204 | |||
[1] | For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. |