Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended |
Sep. 30, 2014 | |
Document And Entity Information [Abstract] | ' |
Document Type | 'S-1/A |
Amendment Flag | 'false |
Document Period End Date | 30-Sep-14 |
Trading Symbol | 'MRD |
Entity Registrant Name | 'MEMORIAL RESOURCE DEVELOPMENT CORP. |
Entity Central Index Key | '0001599222 |
Entity Filer Category | 'Non-accelerated Filer |
CONSOLIDATED_AND_COMBINED_BALA
CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Current assets: | ' | ' | ' |
Cash and cash equivalents | $10,316 | $77,721 | $49,391 |
Restricted cash | ' | 35,000 | 2,013 |
Accounts receivable: | ' | ' | ' |
Oil and natural gas sales | 102,578 | 68,764 | 64,128 |
Joint interest owners and other | 19,116 | 19,958 | 17,701 |
Affiliates | ' | 4,652 | 77 |
Short-term derivative instruments | 37,421 | 9,289 | 41,921 |
Prepaid expenses and other current assets | 20,696 | 19,513 | 13,577 |
Total current assets | 190,127 | 234,897 | 188,808 |
Property and equipment, at cost: | ' | ' | ' |
Oil and natural gas properties, successful efforts method | 4,544,176 | 3,037,298 | 2,637,466 |
Other | 15,477 | 10,331 | 9,920 |
Accumulated depreciation, depletion and impairment | -877,843 | -627,925 | -471,949 |
Oil and natural gas properties, net | 3,681,810 | 2,419,704 | 2,175,437 |
Long-term derivative instruments | 34,515 | 48,616 | 17,179 |
Restricted investments | 76,268 | 73,385 | 68,024 |
Restricted cash | 260 | 15,506 | ' |
Other long-term assets | 38,687 | 37,053 | 9,856 |
Total assets | 4,021,667 | 2,829,161 | 2,459,304 |
Current liabilities: | ' | ' | ' |
Accounts payable | 16,846 | 20,734 | 36,633 |
Accounts payable - affiliates | 810 | 1,975 | ' |
Revenues payable | 59,512 | 56,091 | 50,967 |
Accrued liabilities | 179,381 | 98,130 | 33,487 |
Short-term derivative instruments | 5,109 | 9,711 | 4,667 |
Total current liabilities | 261,658 | 186,641 | 125,754 |
Noncurrent liabilities: | ' | ' | ' |
Asset retirement obligations | 119,510 | 111,679 | 101,990 |
Long-term derivative instruments | 15,275 | 6,080 | 11,623 |
Deferred tax liabilities | 50,643 | 3,106 | ' |
Other long-term liabilities | ' | 3,412 | 3,846 |
Other long-term liabilities | 3,782 | 306 | ' |
Total liabilities | 2,562,668 | 1,971,029 | 1,182,595 |
Commitments and contingencies | ' | ' | ' |
Stockholders' equity (deficit): | ' | ' | ' |
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding | 0 | 0 | ' |
Common stock, $.01 par value: 600,000,000 shares authorized; 193,568,422 shares issued and outstanding at June 30, 2014; no shares authorized, issued or outstanding at December 31, 2013 | 1,936 | ' | ' |
Additional paid-in capital | 1,386,143 | ' | ' |
Accumulated earnings (deficit) | -951,801 | ' | ' |
Total stockholders' equity | 436,278 | ' | ' |
Members' equity: | ' | ' | ' |
Members | ' | 237,186 | 811,614 |
Previous Owners | ' | 40,331 | 233,433 |
Total members' equity | ' | 277,517 | 1,045,047 |
Noncontrolling interests | 1,022,721 | 580,615 | 231,662 |
Total equity | 1,458,999 | 858,132 | 1,276,709 |
Total liabilities and equity | 4,021,667 | 2,829,161 | 2,459,304 |
MRD [Member] | ' | ' | ' |
Noncurrent liabilities: | ' | ' | ' |
Long-term debt | 628,000 | 871,150 | 309,200 |
MEMP [Member] | ' | ' | ' |
Noncurrent liabilities: | ' | ' | ' |
Long-term debt | $1,483,800 | $792,067 | $630,182 |
CONSOLIDATED_AND_COMBINED_BALA1
CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
Statement of Financial Position [Abstract] | ' | ' |
Preferred stock, par value | $0.01 | ' |
Preferred stock, shares authorized | 50,000,000 | ' |
Preferred stock, shares issued | 0 | ' |
Preferred stock, shares outstanding | 0 | ' |
Common stock, par value | $0.01 | $0 |
Common stock, shares authorized | 600,000,000 | 0 |
Common stock, shares issued | 193,559,211 | 0 |
Common stock, shares outstanding | 193,559,211 | 0 |
STATEMENTS_OF_CONSOLIDATED_AND
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $) | 9 Months Ended | 12 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Revenues: | ' | ' | ' | ' | ||
Oil & natural gas sales | $669,301 | $420,857 | $571,948 | $393,631 | ||
Pipeline tariff income and other | 3,584 | 1,884 | 3,075 | 3,237 | ||
Total revenues | 672,885 | 422,741 | 575,023 | 396,868 | ||
Costs and expenses: | ' | ' | ' | ' | ||
Lease operating | 111,887 | 81,746 | 113,640 | 103,754 | ||
Pipeline operating | 1,596 | 1,343 | 1,835 | 2,114 | ||
Exploration | 1,465 | 2,265 | 2,356 | 9,800 | ||
Production and ad valorem taxes | 33,623 | 23,478 | 27,146 | 23,624 | ||
Depreciation, depletion, and amortization | 215,906 | 132,328 | 184,717 | 138,672 | ||
Impairment of proved oil and natural gas properties | 67,181 | 21 | 6,600 | 28,871 | ||
Incentive unit compensation expense | 969,390 | 19,069 | ' | ' | ||
General and administrative | 61,061 | 55,982 | 125,358 | 69,187 | ||
Accretion of asset retirement obligations | 4,601 | 4,016 | 5,581 | 5,009 | ||
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 | ||
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 | ||
Other, net | -12 | 622 | 649 | 502 | ||
Total costs and expenses | 1,481,335 | 205,096 | 352,967 | 336,867 | ||
Operating income (loss) | -808,450 | 217,645 | 222,056 | 60,001 | ||
Other income (expense): | ' | ' | ' | ' | ||
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 | ||
Loss on extinguishment of debt | -37,248 | ' | ' | ' | ||
Amortization of investment premium | ' | ' | ' | -194 | ||
Other, net | 102 | 81 | 145 | 535 | ||
Total other income (expense) | -142,074 | -41,913 | -69,105 | -32,897 | ||
Income (loss) before income taxes | -950,524 | 175,732 | 152,951 | 27,104 | ||
Income tax benefit (expense) | -14,398 | -1,432 | -1,619 | -107 | ||
Net income (loss) | -964,922 | 174,300 | 151,332 | 26,997 | ||
Net income (loss) attributable to noncontrolling interest | -34,851 | 42,134 | 49,830 | -2,701 | ||
Net income (loss) attributable to Memorial Resource Development Corp. | -930,071 | 132,166 | 101,502 | 29,698 | ||
Net (income) loss allocated to members | -20,305 | -122,639 | 90,712 | -7,620 | ||
Net (income) loss allocated to previous owners | -1,425 | -9,527 | 10,790 | 37,318 | ||
Net income (loss) available to common stockholders | -951,801 | ' | ' | ' | ||
Net income (loss) attributable to Memorial Resource Development LLC | -930,071 | 132,166 | 101,502 | 29,698 | ||
Earnings per common share: | ' | ' | ' | ' | ||
Basic | ($4.94) | ' | ' | ' | ||
Diluted | ($4.94) | ' | ' | ' | ||
Pro forma basic earnings per share | ' | ' | $0.31 | ($0.03) | ||
Weighted average common and common equivalent shares outstanding: | ' | ' | ' | ' | ||
Basic | 192,500 | ' | ' | ' | ||
Diluted | 192,500 | ' | ' | ' | ||
Pro forma diluted earnings per share | ' | ' | $0.30 | ($0.03) | ||
Pro forma basic weighted average shares outstanding | ' | ' | 192,500 | 192,500 | ||
Pro forma diluted weighted average shares outstanding | ' | ' | 193,676 | [1] | 193,676 | [1] |
Pro Forma [Member] | ' | ' | ' | ' | ||
Other income (expense): | ' | ' | ' | ' | ||
Income (loss) before income taxes | ' | ' | 152,951 | 27,104 | ||
Income tax benefit (expense) | ' | ' | -55,154 | -9,592 | ||
Net income (loss) | ' | ' | 97,797 | 17,512 | ||
Net income (loss) attributable to noncontrolling interest | ' | ' | 31,861 | -1,745 | ||
Net (income) loss allocated to previous owners | ' | ' | -6,899 | -24,111 | ||
Net income (loss) available to common stockholders | ' | ' | $59,037 | ($4,854) | ||
[1] | Includes dilutive effect of 1,176 restricted common shares. |
STATEMENTS_OF_CONSOLIDATED_AND1
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | ' | ' | ' | ' |
Net income (loss) | ($964,922) | $174,300 | $151,332 | $26,997 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ' | ' | ' | ' |
Depreciation, depletion, and amortization | 215,906 | 132,328 | 184,717 | 138,672 |
Impairment of proved oil and natural gas properties | 67,181 | 21 | 6,600 | 28,871 |
(Gain) loss on derivative instruments | 12,737 | -29,487 | -29,533 | -29,323 |
Cash settlements (paid) received on derivative instruments | 22,174 | 21,356 | 30,403 | 72,045 |
Loss on extinguishment of debt | 30,248 | ' | ' | ' |
Premiums paid for derivatives | ' | ' | ' | -411 |
Amortization of deferred financing costs | 5,492 | 6,193 | 8,343 | 3,584 |
Accretion of senior notes net discount | 1,888 | 161 | 554 | ' |
Accretion of asset retirement obligations | 4,601 | 4,016 | 5,581 | 5,009 |
Amortization of equity awards | 6,874 | 2,322 | 3,557 | 1,423 |
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 |
Non-cash compensation expense | 941,659 | 1,057 | 1,057 | ' |
Exploration costs | 868 | ' | 181 | 6,980 |
Deferred income tax expense (benefit) | 13,916 | ' | 76 | -312 |
Amortization of investment premium | ' | ' | ' | 194 |
Changes in operating assets and liabilities: | ' | ' | ' | ' |
Accounts receivable | -22,117 | 560 | -15,758 | -7,382 |
Prepaid expenses and other assets | 297 | -2,562 | -2,986 | -1,574 |
Payables and accrued liabilities | 67,324 | 13,034 | 19,320 | 5,392 |
Other | 2,625 | 95 | ' | ' |
Net cash provided by operating activities | 365,460 | 237,176 | 277,823 | 240,404 |
Cash flows from investing activities: | ' | ' | ' | ' |
Acquisition of oil and natural gas properties | -1,083,167 | -104,926 | -105,762 | -360,678 |
Additions to oil and gas properties | -457,838 | -257,513 | -360,015 | -273,334 |
Additions to other property and equipment | -9,134 | -1,184 | -2,670 | -2,674 |
Additions to restricted investments | -2,883 | -4,263 | -5,361 | -4,599 |
Deposits for property acquisitions | ' | -25,310 | ' | ' |
Decrease (increase) in restricted cash | 49,946 | 653 | -49,347 | -3 |
Proceeds from the sale of oil and natural gas properties | 6,700 | 156,799 | 155,712 | 34,521 |
Other | -301 | -139 | ' | 29 |
Net cash (used in) provided by investing activities | -1,496,677 | -235,883 | -367,443 | -606,738 |
Cash flows from financing activities: | ' | ' | ' | ' |
Distributions to noncontrolling interests | -101,327 | -51,319 | -78,083 | -15,208 |
Advances on revolving credit facilities | 2,464,800 | 478,055 | 1,132,755 | 619,450 |
Distributions to the Funds | ' | -363,437 | -732,362 | ' |
Payments on revolving credit facilities | -2,441,900 | -900,368 | -1,766,037 | -251,569 |
Borrowings under second lien credit facility | ' | 325,000 | 325,000 | ' |
Redemption of second lien credit facility | -328,282 | ' | ' | ' |
Proceeds from the issuances of senior notes | 1,092,425 | 397,563 | 1,031,563 | ' |
Redemption of senior notes | -351,808 | ' | ' | ' |
Deferred financing costs | -30,284 | -23,839 | -41,175 | -3,501 |
Purchase of additional interests in consolidated subsidiaries | -3,292 | -1,270 | -15,135 | ' |
Contributions from previous owners | ' | 1,214 | 1,214 | 44,072 |
Proceeds from changes in ownership interests of MEMP | ' | ' | 135,012 | ' |
Distributions made by previous owners | ' | -3,130 | -4,005 | -28,772 |
Cash retained by previous owners | ' | ' | -7,909 | ' |
Other | 213 | ' | 455 | ' |
Net cash (used in) provided by financing activities | 1,063,812 | 32,261 | 117,950 | 361,761 |
Net change in cash and cash equivalents | -67,405 | 33,554 | 28,330 | -4,573 |
Cash and cash equivalents, beginning of period | 77,721 | 49,391 | 49,391 | 53,964 |
Cash and cash equivalents, end of period | 10,316 | 82,945 | 77,721 | 49,391 |
Supplemental cash flows: | ' | ' | ' | ' |
Cash paid for interest | 67,449 | 22,959 | 61,140 | 23,525 |
Noncash investing and financing activities: | ' | ' | ' | ' |
Change in capital expenditures in payables and accrued liabilities | 29,137 | 25,017 | 41,017 | 17,158 |
Assumptions of asset retirement obligations related to properties acquired or drilled | 5,053 | 3,478 | 4,227 | 7,962 |
Accounts receivable related to acquisitions and divestitures | 4,271 | ' | ' | ' |
Distributions to noncontrolling interests | ' | ' | ' | 47 |
Natural Gas Partners [Member] | ' | ' | ' | ' |
Cash flows from financing activities: | ' | ' | ' | ' |
Contributions from NGP affiliates related to sale of properties | 1,165 | 2,013 | 2,013 | 45,158 |
Distribution to NGP affiliates | -66,693 | ' | -355,494 | -242,174 |
Distribution to NGP affiliates related to sale of assets, net of cash received | -32,770 | ' | ' | ' |
Noncash investing and financing activities: | ' | ' | ' | ' |
Contribution of oil and gas properties | ' | ' | ' | 6,893 |
Accrued distribution | ' | ' | 4,352 | ' |
Contribution related to sale of assets | ' | ' | ' | 2,013 |
MRD Holdco LLC [Member] | ' | ' | ' | ' |
Cash flows from financing activities: | ' | ' | ' | ' |
Distributions to MRD Holdco | -59,803 | ' | ' | ' |
MRD [Member] | ' | ' | ' | ' |
Cash flows from financing activities: | ' | ' | ' | ' |
Proceeds from public offering | 408,500 | ' | ' | ' |
Costs incurred in conjunction with initial public offering | -28,198 | ' | ' | ' |
MEMP [Member] | ' | ' | ' | ' |
Cash flows from financing activities: | ' | ' | ' | ' |
Proceeds from public offering | 553,228 | 179,371 | 511,204 | 202,573 |
Costs incurred in conjunction with initial public offering | -12,222 | -7,592 | -21,066 | -8,268 |
Noncash investing and financing activities: | ' | ' | ' | ' |
Accrued equity offering costs | ' | ' | ' | $171 |
STATEMENTS_OF_CONSOLIDATED_AND2
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $) | Total | Preferred Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated earnings (deficit) [Member] | Noncontrolling Interest [Member] | Members Equity [Member] | Members Equity [Member] |
In Thousands | Previous Owners [Member] | |||||||
Total equity, beginning balance at Dec. 31, 2011 | $1,276,364 | ' | ' | ' | ' | ' | ' | ' |
Noncontrolling interests, beginning balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | 161,588 | ' | ' |
Members' equity, beginning balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | ' | 853,436 | 261,340 |
Total stockholders' equity | ' | ' | ' | ' | ' | ' | ' | ' |
Total members' equity | 1,045,047 | ' | ' | ' | ' | ' | 811,614 | 233,433 |
Total equity | 1,276,709 | ' | ' | ' | ' | ' | ' | ' |
Net income (loss) | 26,997 | ' | ' | ' | ' | -2,701 | -7,620 | 37,318 |
Contributions | 44,072 | ' | ' | ' | ' | ' | ' | 44,072 |
Contribution of oil and gas properties from NGP affiliate | 6,893 | ' | ' | ' | ' | ' | ' | 6,893 |
Net proceeds from MEMP public equity offering | 194,134 | ' | ' | ' | ' | 194,134 | ' | ' |
Distributions | -44,027 | ' | ' | ' | ' | -15,255 | ' | -28,772 |
Net book value of net assets acquired from affiliates | ' | ' | ' | ' | ' | 41,479 | 52,217 | -93,696 |
Amortization of MEMP equity awards | 1,423 | ' | ' | ' | ' | 1,423 | ' | ' |
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | ' | ' | ' | ' | ' | -727 | 727 | ' |
Contribution related to sale of assets to NGP affiliate | 47,171 | ' | ' | ' | ' | 742 | 6,291 | 40,138 |
Net book value of assets acquired by NGP affiliate | -34,506 | ' | ' | ' | ' | -68 | -579 | -33,859 |
Distribution to affiliate in connection with acquisition of assets | -242,174 | ' | ' | ' | ' | -107,210 | -134,964 | ' |
Impact from equity transactions of MEMP | ' | ' | ' | ' | ' | -41,930 | 41,930 | ' |
Other | 362 | ' | ' | ' | ' | 187 | 176 | -1 |
Noncontrolling interests, ending balance at Dec. 31, 2012 | 231,662 | ' | ' | ' | ' | 231,662 | ' | ' |
Total equity, ending balance at Dec. 31, 2012 | 1,276,709 | ' | ' | ' | ' | ' | ' | ' |
Stock holders' equity, ending balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | ' |
Members' equity, ending balance at Dec. 31, 2012 | 1,045,047 | ' | ' | ' | ' | ' | 811,614 | 233,433 |
Total stockholders' equity | ' | ' | ' | ' | ' | ' | ' | ' |
Total members' equity | 836,098 | ' | ' | ' | ' | ' | 597,353 | 238,745 |
Total equity | 1,204,821 | ' | ' | ' | ' | ' | ' | ' |
Net income (loss) | 174,300 | ' | ' | ' | ' | 42,134 | 122,639 | 9,527 |
Contributions | ' | ' | ' | ' | ' | ' | ' | 1,214 |
Net proceeds from MEMP public equity offering | ' | ' | ' | ' | ' | 171,779 | ' | ' |
Distributions | ' | ' | ' | ' | ' | -51,319 | -363,437 | -3,130 |
Amortization of MEMP equity awards | ' | ' | ' | ' | ' | 2,321 | ' | ' |
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | ' | ' | ' | ' | ' | -2,560 | 2,560 | ' |
Purchase of noncontrolling interests | ' | ' | ' | ' | ' | -1,270 | ' | ' |
Impact from equity transactions of MEMP | ' | ' | ' | ' | ' | -24,024 | 24,024 | ' |
Other | ' | ' | ' | ' | ' | ' | -47 | -2,299 |
Noncontrolling interests, ending balance at Sep. 30, 2013 | ' | ' | ' | ' | ' | 368,723 | ' | ' |
Total equity, ending balance at Sep. 30, 2013 | 1,204,821 | ' | ' | ' | ' | ' | ' | ' |
Stock holders' equity, ending balance at Sep. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' |
Members' equity, ending balance at Sep. 30, 2013 | 836,098 | ' | ' | ' | ' | ' | 597,353 | 238,745 |
Total equity, beginning balance at Dec. 31, 2012 | 1,276,709 | ' | ' | ' | ' | ' | ' | ' |
Stock holders' equity, beginning balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | ' |
Members' equity, beginning balance at Dec. 31, 2012 | 1,045,047 | ' | ' | ' | ' | ' | 811,614 | 233,433 |
Noncontrolling interests, beginning balance at Dec. 31, 2012 | 231,662 | ' | ' | ' | ' | 231,662 | ' | ' |
Total stockholders' equity | ' | ' | ' | ' | ' | ' | ' | ' |
Total members' equity | 277,517 | ' | ' | ' | ' | ' | 237,186 | 40,331 |
Total equity | 858,132 | ' | ' | ' | ' | ' | ' | ' |
Net income (loss) | 151,332 | ' | ' | ' | ' | 49,830 | 90,712 | 10,790 |
Contributions | 1,214 | ' | ' | ' | ' | ' | ' | 1,214 |
Net proceeds from MEMP public equity offering | 490,138 | ' | ' | ' | ' | 490,138 | ' | ' |
Sale of MEMP common units | 135,012 | ' | ' | ' | ' | 74,311 | 60,701 | ' |
Distributions | -814,450 | ' | ' | ' | ' | -78,083 | -732,362 | -4,005 |
Net book value of net assets acquired from affiliates | ' | ' | ' | ' | ' | 130,805 | 50,751 | -181,556 |
Amortization of MEMP equity awards | 3,557 | ' | ' | ' | ' | 3,557 | ' | ' |
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | ' | ' | ' | ' | ' | 24 | -24 | ' |
Distribution to affiliate in connection with acquisition of assets | -351,235 | ' | ' | ' | ' | -253,055 | -98,180 | ' |
Purchase of noncontrolling interests | -15,135 | ' | ' | ' | ' | -14,832 | -303 | ' |
Impact from equity transactions of MEMP | ' | ' | ' | ' | ' | -54,183 | 54,183 | ' |
Other | -1,764 | ' | ' | ' | ' | 441 | 94 | -2,299 |
Net assets retained by previous owners | -17,246 | ' | ' | ' | ' | ' | ' | -17,246 |
Noncontrolling interests, ending balance at Dec. 31, 2013 | 580,615 | ' | ' | ' | ' | 580,615 | ' | ' |
Total equity, ending balance at Dec. 31, 2013 | 858,132 | ' | ' | ' | ' | ' | ' | ' |
Stock holders' equity, ending balance at Dec. 31, 2013 | ' | ' | ' | ' | ' | ' | ' | ' |
Members' equity, ending balance at Dec. 31, 2013 | 277,517 | ' | ' | ' | ' | ' | 237,186 | 40,331 |
Total stockholders' equity | 436,278 | ' | 1,936 | 1,386,143 | -951,801 | ' | ' | ' |
Issuance of shares in connection with restructuring transactions | ' | ' | 1,710 | 913,152 | ' | ' | ' | ' |
Total members' equity | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of shares in connection with initial public offering | ' | ' | 215 | 379,962 | ' | ' | ' | ' |
Total equity | 1,458,999 | ' | ' | ' | ' | ' | ' | ' |
Tax related effects in connection with restructuring transactions and initial public offering | ' | ' | ' | -43,251 | ' | ' | ' | ' |
Net income (loss) | -964,922 | ' | ' | ' | -951,801 | -34,851 | 20,305 | 1,425 |
Restricted stock awards | ' | ' | 11 | -11 | ' | ' | ' | ' |
Amortization of restricted stock awards | ' | ' | ' | 1,487 | ' | ' | ' | ' |
Contribution related to MRD Holdco incentive unit compensation expense | ' | ' | ' | 137,307 | ' | ' | ' | ' |
Net proceeds from MEMP public equity offering | ' | ' | ' | ' | ' | 540,987 | ' | ' |
Distributions | ' | ' | ' | ' | ' | -101,327 | ' | ' |
Amortization of MEMP equity awards | ' | ' | ' | ' | ' | 5,387 | ' | ' |
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | ' | ' | ' | ' | ' | 2,659 | -2,659 | ' |
Contribution related to sale of assets to NGP affiliate | ' | ' | ' | ' | ' | ' | 1,165 | ' |
Net book value of assets sold to NGP affiliate | ' | ' | ' | ' | ' | ' | -621 | ' |
Net book value of assets acquired by NGP affiliate | ' | ' | ' | ' | ' | ' | 45,059 | -41,756 |
Distribution to affiliate in connection with acquisition of assets | ' | ' | ' | ' | ' | ' | -66,693 | ' |
Distribution of net assets to MRD Holdco | ' | ' | ' | ' | ' | 29,994 | -123,078 | ' |
Distribution of shares received in connection with restructuring transactions to MRD Holdco | ' | ' | ' | ' | ' | ' | -110,510 | ' |
Purchase of noncontrolling interests | ' | ' | ' | -2,881 | ' | -411 | ' | ' |
Impact from equity transactions of MEMP | ' | ' | ' | ' | ' | 0 | ' | ' |
Other | ' | ' | ' | 378 | ' | -332 | -154 | ' |
Noncontrolling interests, ending balance at Sep. 30, 2014 | 1,022,721 | ' | ' | ' | ' | 1,022,721 | ' | ' |
Total equity, ending balance at Sep. 30, 2014 | 1,458,999 | ' | ' | ' | ' | ' | ' | ' |
Stock holders' equity, ending balance at Sep. 30, 2014 | 436,278 | ' | 1,936 | 1,386,143 | -951,801 | ' | ' | ' |
Members' equity, ending balance at Sep. 30, 2014 | ' | ' | ' | ' | ' | ' | ' | ' |
Background_Organization_and_Ba
Background, Organization and Basis of Presentation | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||
Accounting Policies [Abstract] | ' | ' | ||||||
Background, Organization and Basis of Presentation | ' | ' | ||||||
Note 1. Background, Organization and Basis of Presentation | Note 1. Background, Organization and Basis of Presentation | |||||||
Overview | Background & Organization | |||||||
Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. | Memorial Resource Development LLC (“Memorial Resource”) is a Delaware limited liability company (the “Company”) formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Company” are intended to mean the business and operations of Memorial Resource Development LLC and its consolidated subsidiaries. | |||||||
The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to exploit, develop and acquire natural gas, NGL and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. | These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of Memorial Resource Development Corp. (“MRDC”). In connection with the closing of the Offering, Memorial Resource will contribute its ownership interests in all of its directly owned subsidiaries except for BlueStone Natural Resources Holdings, LLC (“BlueStone Holdings”), Golden Energy Partners LLC (“Golden Energy”) and Classic Pipeline & Gathering, LLC (“Classic Pipeline”) as well as two immaterial subsidiaries that were recently formed, and 50% of the incentive distribution rights of Memorial Production Partners LP (“MEMP”) in exchange for shares of common stock of MRDC. MRDC will become a subsidiary of Memorial Resource. Memorial Resource’s consolidated and combined financial statements represent MRDC’s predecessor for accounting and financial reporting purposes. | |||||||
Initial Public Offering and Restructuring Transactions | At December 31, 2013, BlueStone Holdings’ total assets were less than 1% of consolidated total assets and the MRD Segment’s total assets. BlueStone Holdings’ total revenues were approximately 3% of consolidated total revenues and 7% of the MRD Segment’s total revenues for the year ended December 31, 2013. BlueStone Holdings’ production volumes were approximately 2% of consolidated production volumes and 4% of the MRD Segment’s production volumes for the year ended December 31, 2013. | |||||||
On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: | As of December 31, 2013, Memorial Resource’s significant consolidating subsidiaries consisted of the following: | |||||||
• | The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; | • | Memorial Production Partners GP LLC (“MEMP GP”), a wholly-owned subsidiary, owns a 0.1% general partner interest in MEMP represented by 61,300 general partner units as of December 31, 2013. MEMP is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market under the symbol “MEMP.” MEMP was formed in April 2011 to own and acquire oil and natural gas properties in North America and completed its initial public offering on December 14, 2011. MEMP’s business activities are conducted through its wholly-owned subsidiary Memorial Production Operating LLC (“OLLC”) and its subsidiaries. All of OLLC’s consolidating subsidiaries are wholly-owned either directly or indirectly, except for one indirect majority-owned subsidiary. At December 31, 2013, Memorial Resource owned all of the 5,360,912 subordinated units outstanding. The Funds collectively indirectly own 50% of MEMP’s incentive distribution rights (“IDRs”). Memorial Resource owns the remaining IDRs. MEMP’s assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico, and offshore Southern California. | |||||
• | WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company will provide transition services to WildHorse Resources; | • | Black Diamond Minerals, LLC (“Black Diamond”), a wholly-owned subsidiary, together with its majority-owned subsidiary are engaged in the exploration, development, production, and operations of oil and natural gas properties located in Colorado, Oklahoma, and Wyoming. | |||||
• | Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; | • | BlueStone Holdings, a majority-owned subsidiary, together with its consolidated subsidiaries (collectively, “BlueStone”) are engaged in the exploration, development, production, and operations of oil and natural gas properties located in Texas. As of December 31, 2013, Memorial Resource owned an 89.45% membership interest in BlueStone Holdings and other individuals owned the remaining membership interests. All of BlueStone Holdings’ consolidating subsidiaries are wholly-owned either directly or indirectly. | |||||
• | MRD LLC contributed to us substantially all of its assets, comprised of: (i)100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; | • | Classic Hydrocarbons Holdings, L.P. (“Classic”), an indirect wholly-owned subsidiary, together with its consolidated subsidiaries are engaged in the exploration, development, production, and sale of oil and natural gas primarily in East Texas and Louisiana. As of December 31, 2013, Classic Hydrocarbons GP CO., L.L.C. (“Classic GP”) owned a 0.41% general partner interest in Classic and Memorial Resource owned a 99.59% limited partner interest in Classic. All of Classic’s consolidating subsidiaries are wholly-owned either directly or indirectly. As of December 31, 2013, Memorial Resource owned a 100% membership interest in Classic GP. | |||||
• | We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; | • | WildHorse Resources, LLC (“WildHorse”), a majority-owned subsidiary, together with its wholly-owned subsidiary are engaged in the acquisition, exploitation, and development of natural gas and crude oil properties located in Louisiana and Texas. As of December 31, 2013, Memorial Resource owned a 99.89% membership interest in WildHorse and other individuals owned the remaining membership interests. In connection with the closing of the Offering, the remaining membership interests will be contributed to MRDC and incentive units held by certain members of management will be exchanged for shares of common stock of MRDC and cash consideration. | |||||
• | We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | • | Beta Operating Company, LLC (“Beta Operating”), a wholly-owned subsidiary, employs those employees who operate and support MEMP’s offshore Southern California oil and gas properties. Beta Operating was contributed to Memorial Resource by MEMP in December 2012. This entity was formerly owned by an affiliate of NGP. MEMP’s acquisition of Beta Operating in December 2012 and the subsequent contribution to Memorial Resource were accounted for as common control transactions at historical cost. | |||||
• | Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; | • | Memorial Resource Finance Corp. (“MRD Finance Corp.”), a wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto. | |||||
• | We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; | MEMP acquired certain oil and natural gas producing properties in East Texas from Tanos Energy, LLC (“Tanos”) on April 2, 2012. Prior to April 1, 2013, Memorial Resource owned a 98.94% membership interest in Tanos. On April 1, 2013, Memorial Resource purchased the remaining membership interest in Tanos (see Note 11). MEMP acquired certain oil and natural gas producing properties in East Texas from Classic on May 14, 2012; acquired all of the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse and Tanos on March 28, 2013; acquired all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond on October 1, 2013; acquired all of the outstanding membership interests in Tanos from Memorial Resource on October 1, 2013; acquired certain of the oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) from Memorial Resource on October 1, 2013; and acquired certain oil and natural gas producing properties in East Texas from WildHorse on April 1, 2014. These intercompany transactions have been eliminated in preparation of our consolidated and combined financial statements. | ||||||
• | We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | References to “previous owners” for accounting and financial reporting purposes refer collectively to: | ||||||
• | Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; | • | Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition. MEMP acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, in December 2012 from Rise Energy Partners, LP (“Rise”). Beta Operating was a wholly-owned subsidiary of Rise Energy Operating, LLC until it was contributed to Memorial Resource by MEMP in December 2012. Rise is primarily owned by two of the Funds. | |||||
• | MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; | • | Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. | |||||
• | MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; | • | A net profits interest that WildHorse purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse sold a net profits interest in these properties to NGPCIF (see Note 12). Since WildHorse sold the net profits interest, the historical results are accounted for as a working interest for all periods. | |||||
• | We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and | Basis of Presentation | ||||||
• | MRD LLC merged into MRD Operating. | Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of the previous owners for the periods that those entities were under common control. | ||||||
Previous Owners | All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments necessary for a fair presentation of the financial statements have been made. Certain amounts in the prior year financial statements have been reclassified to conform to the presentation in the current year financial statements. | |||||||
References to “the previous owners” for accounting and financial reporting purposes refer collectively to: | We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties (See Note 13). Our reportable business segments are as follows: | |||||||
• | Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. | • | MRD—reflects the combined operations of Memorial Resource, WildHorse and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | |||||
• | A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. | • | MEMP—reflects the combined operations of MEMP, its previous owners, and any dropdown transactions between MEMP and other Memorial Resource subsidiaries. | |||||
Our unaudited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions on October 1, 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. | Segment financial information has been retrospectively revised for the following common control transactions between MEMP and other Memorial Resource subsidiaries for comparability purposes: | |||||||
Basis of Presentation | • | acquisition by MEMP of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013; | ||||||
The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. | • | acquisition by MEMP of all the outstanding membership interests in Prospect Energy for a purchase price of approximately $16.3 million on October 1, 2013; | ||||||
All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the nine months ended September 30, 2014 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). | • | acquisition by MEMP of all the outstanding membership interests in WHT for a purchase price of approximately $200.0 million on March 28, 2013; | ||||||
We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: | • | acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and | ||||||
• | MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | • | acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million. | |||||
• | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | |||||||
Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: | ||||||||
• | acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; | |||||||
• | acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; | |||||||
• | acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and | |||||||
• | acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Accounting Policies [Abstract] | ' | ' | ||||||||||||||||
Summary of Significant Accounting Policies | ' | ' | ||||||||||||||||
Note 2. Summary of Significant Accounting Policies | Note 2. Summary of Significant Accounting Policies | |||||||||||||||||
Use of Estimates | Use of Estimates | |||||||||||||||||
The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations; and asset retirement obligations. | Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. | |||||||||||||||||
Principles of Consolidation and Combination | Principles of Consolidation and Combination | |||||||||||||||||
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of our predecessor and the previous owners. | Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of the previous owners. All material intercompany balances and transactions have been eliminated. | |||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||
Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | |||||||||||||||||
Concentrations of Credit Risk | Concentrations of Credit Risk | |||||||||||||||||
Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments. | Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments. | |||||||||||||||||
Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both September 30, 2014 and December 31, 2013, respectively. | Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2013 and 2012, respectively. | |||||||||||||||||
If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | |||||||||||||||||
Oil and Natural Gas Properties | Oil and Natural Gas Properties | |||||||||||||||||
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | |||||||||||||||||
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | |||||||||||||||||
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | |||||||||||||||||
Impairments | There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2013 and December 31, 2012. | |||||||||||||||||
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. | Impairments | |||||||||||||||||
Unproved oil and natural gas properties are assessed for impairment on a property-by-property basis. A loss is recognized by providing a valuation allowance if the assessment indicates an impairment. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2013 and 2012 was approximately $6.6 million and $28.9 million, respectively. | |||||||||||||||||
Asset Retirement Obligations | Nonproducing oil and natural gas properties, which consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. | |||||||||||||||||
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | Asset Retirement Obligations | |||||||||||||||||
Oil and Gas Reserves | An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | |||||||||||||||||
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. | Oil and Gas Reserves | |||||||||||||||||
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to prepare our reserves estimates at December 31, 2013. | |||||||||||||||||
Other Property & Equipment | Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | |||||||||||||||||
Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years. | Other Property & Equipment | |||||||||||||||||
Restricted Investments | Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years. | |||||||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense—net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. At September 30, 2014, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | Restricted Investments | |||||||||||||||||
Debt Issuance Costs | Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense—net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. At December 31, 2013, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | |||||||||||||||||
These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. | Debt Issuance Costs | |||||||||||||||||
Revenue Recognition | These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. Amortization expense, including write-offs of debt issuance costs, for the years ended December 31, 2013 and 2012 was approximately $8.3 million and $3.6 million, respectively. | |||||||||||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. | Revenue Recognition | |||||||||||||||||
Derivative Instruments | Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2013 or 2012. | |||||||||||||||||
Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | |||||||||||||||||
Income Tax | ||||||||||||||||||
Years Ending December 31, | ||||||||||||||||||
Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas. | 2013 | 2012 | ||||||||||||||||
Consolidated & Combined: | ||||||||||||||||||
Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. There were no uncertain tax positions that required recognition in the financial statements at both September 30, 2014 and December 31, 2013, respectively. | Energy Transfer Equity, L.P. and subsidiaries | 35 | % | 13 | % | |||||||||||||
In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. | MRD Segment: | |||||||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 77 | % | 39 | % | ||||||||||||||
Earnings Per Share | Sunoco, Inc.(1) | n/a | 15 | % | ||||||||||||||
Dominion Gas Ventures LP | n/a | 15 | % | |||||||||||||||
Basic earnings per share (“EPS”) is computed based on the average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock awards if the inclusion of these awards is dilutive. See Note 10 for additional information. | ||||||||||||||||||
MEMP Segment: | ||||||||||||||||||
Incentive-Based Compensation Arrangements | Phillips 66(2) | 15 | % | 13 | % | |||||||||||||
ConocoPhillips(2) | n/a | 14 | % | |||||||||||||||
The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | ||||||||||||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||||||||
Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | -2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. | ||||||||||||||||
In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco. | Derivative Instruments | |||||||||||||||||
See Notes 11 and 12 for further information. | Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | |||||||||||||||||
Current Liabilities—Accrued liabilities | Income Tax | |||||||||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | We are organized as a pass-through entity for federal income tax purposes. As a result, our members are responsible for federal income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations and subject to federal income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas. Deferred taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Deferred tax liabilities as of December 31, 2013 were approximately $3.2 million and total tax expense for the year was approximately $1.6 million. Deferred tax liabilities as of December 31, 2012 were approximately $3.1 million and total tax expense for the year was approximately $0.1 million. | |||||||||||||||||
We must recognize the tax effects of any uncertain tax positions we may adopt if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2013 or 2012. | ||||||||||||||||||
September 30, | December 31, | |||||||||||||||||
2014 | 2013 | Upon closing of the Offering, MRDC will be treated as a taxable C corporation and will be subject to federal and certain state income taxes. Accordingly, a pro forma income tax provision has been disclosed as if Memorial Resource was a taxable corporation for all periods presented. Pro forma tax expense was computed using a blended corporate level federal and state tax rate of 36.06% and 35.39% for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||
Accrued capital expenditures | $ | 77,716 | $ | 48,579 | ||||||||||||||
Accrued lease operating expense | 18,142 | 13,240 | Unaudited Pro Forma Earnings Per Share | |||||||||||||||
Accrued general and administrative expenses | 11,986 | 14,485 | ||||||||||||||||
Accrued ad valorem and production taxes | 26,466 | 3,541 | Memorial Resource has presented pro forma earnings per share (“EPS”) for all periods presented. Pro forma net income (loss) per basic share is determined by dividing the pro forma net income (loss) available to common shareholders by the number of common shares expected to be outstanding immediately following the Offering. | |||||||||||||||
Accrued interest payable | 41,857 | 11,934 | ||||||||||||||||
Accrued environmental | 571 | 577 | The following sets forth the calculation of pro forma EPS for the periods indicated (in thousands, except per share amounts): | |||||||||||||||
Other miscellaneous, including operator advances | 2,643 | 5,774 | ||||||||||||||||
$ | 179,381 | $ | 98,130 | For the Year Ended December 31, | ||||||||||||||
2013 | 2012 | |||||||||||||||||
Numerator: | ||||||||||||||||||
New Accounting Pronouncements | Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | |||||||||||||
Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | |||||||||||||||
Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its financial consolidated financial statements and footnote disclosures. | Previous owners interest in pro forma net (income) loss, net of tax | (6,899 | ) | (24,111 | ) | |||||||||||||
Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015. | Pro forma net income (loss) available to common shareholders | $ | 59,037 | $ | (4,854 | ) | ||||||||||||
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows. | ||||||||||||||||||
Denominator: | ||||||||||||||||||
Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | ||||||||||||||||
Basic EPS | $ | 0.31 | $ | (0.03 | ) | |||||||||||||
Diluted EPS | $ | 0.3 | $ | (0.03 | ) | |||||||||||||
-1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||
The following sets forth the calculation of our supplemental pro forma EPS, for the periods indicated (in thousands, except per share amounts): | ||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Numerator: | ||||||||||||||||||
Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | ||||||||||||||
Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | |||||||||||||||
Pro forma net income (loss) available to common shareholders | $ | 65,936 | $ | 19,257 | ||||||||||||||
Denominator: | ||||||||||||||||||
Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | ||||||||||||||||
Basic and diluted EPS | $ | 0.34 | $ | 0.1 | ||||||||||||||
-1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||
Our supplemental basic and diluted EPU includes all the earnings generated by the previous owners for all periods presented due to common control considerations. | ||||||||||||||||||
Unit-Based Compensation Arrangements | ||||||||||||||||||
The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | ||||||||||||||||||
The governing documents of Memorial Resource and certain of its subsidiaries, including WildHorse and BlueStone, provide for the issuance of incentive units. The incentive units are subject to performance conditions that affect their vesting. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. | ||||||||||||||||||
See Note 10 and 11 for further information. | ||||||||||||||||||
Current Accrued Liabilities | ||||||||||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | ||||||||||||||||||
December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Accrued capital expenditures | $ | 48,579 | $ | 14,352 | ||||||||||||||
Accrued lease operating expense | 13,240 | 6,701 | ||||||||||||||||
Accrued general and administrative expenses | 14,485 | 2,290 | ||||||||||||||||
Accrued ad valorem and production taxes | 3,541 | 3,753 | ||||||||||||||||
Accrued interest payable | 11,934 | 1,239 | ||||||||||||||||
Accrued environmental | 577 | 1,012 | ||||||||||||||||
Other miscellaneous, including operator advances | 5,774 | 4,140 | ||||||||||||||||
$ | 98,130 | $ | 33,487 | |||||||||||||||
New Accounting Pronouncements | ||||||||||||||||||
Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The new disclosure requirements required the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures became effective for annual and interim periods beginning on or after January 1, 2013 and were applied retrospectively. The adoption of this new guidance did not have a significant impact on our financial statements. |
Acquisitions_and_Divestitures
Acquisitions and Divestitures | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||
Business Combinations [Abstract] | ' | ' | ||||||||||||||||||||||||
Acquisitions and Divestitures | ' | ' | ||||||||||||||||||||||||
Note 3. Acquisitions and Divestitures | Note 3. Acquisitions and Divestitures | |||||||||||||||||||||||||
Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | The third party acquisitions discussed below were 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 acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under credit facilities. | |||||||||||||||||||||||||
The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. | ||||||||||||||||||||||||||
For the Nine Months | ||||||||||||||||||||||||||
Ended September 30, | MEMP has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 12, from certain affiliates of NGP. These acquisitions were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost. | |||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||
$5,480 | $5,073 | Acquisition-related costs | ||||||||||||||||||||||||
2014 Acquisitions | Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | |||||||||||||||||||||||||
On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $911.7 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). Revenues of $41.6 million were recorded in the statement of operations generated earnings of approximately $16.5 million related to the Wyoming Acquisition subsequent to the closing date. | ||||||||||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||||||||||
On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million, including estimated customary post-closing adjustments (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the nine months ended September 30, 2014, revenues of approximately $25.9 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $13.3 million. | 2013 | 2012 | ||||||||||||||||||||||||
$8,313 | $4,538 | |||||||||||||||||||||||||
The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): | ||||||||||||||||||||||||||
2013 Acquisitions | ||||||||||||||||||||||||||
Eagle Ford | Wyoming | On March 18, 2013, a purchase and sale agreement was executed by WildHorse for the purchase of certain oil and gas properties and leases in Louisiana from a third party (“Louisiana Acquisition”). The final adjusted purchase price was $67.1 million. This transaction closed on April 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of the acquisition date (in thousands): | ||||||||||||||||||||||||
Acquisition | Acquisition | |||||||||||||||||||||||||
Oil and gas properties | $ | 168,606 | $ | 922,686 | ||||||||||||||||||||||
Asset retirement obligations | (285 | ) | (3,328 | ) | Louisiana | |||||||||||||||||||||
Revenue payable | — | (444 | ) | Acquisition | ||||||||||||||||||||||
Accrued liabilities | (250 | ) | (7,237 | ) | Oil and gas properties | $ | 68,887 | |||||||||||||||||||
Asset retirement obligations | (1,789 | ) | ||||||||||||||||||||||||
Total identifiable net assets | $ | 168,071 | $ | 911,677 | ||||||||||||||||||||||
Total identifiable net assets | $ | 67,098 | ||||||||||||||||||||||||
The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | ||||||||||||||||||||||||||
MEMP closed two separate transactions during the year ended December 31, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands): | ||||||||||||||||||||||||||
For the Nine Months | ||||||||||||||||||||||||||
Ended September 30, | East Texas | Rockies | ||||||||||||||||||||||||
2014 | 2013 | Acquisition | Acquisition | |||||||||||||||||||||||
(In thousands, except per | Oil and gas properties | $ | 9,974 | $ | 20,744 | |||||||||||||||||||||
unit amounts) | Asset retirement obligations | (78 | ) | (1,163 | ) | |||||||||||||||||||||
Revenues | $ | 764,084 | $ | 561,359 | Accrued liabilities | — | (118 | ) | ||||||||||||||||||
Net income (loss) | (931,903 | ) | 218,870 | |||||||||||||||||||||||
Basic and diluted earnings per share | $ | (4.94 | ) | $ | — | Total identifiable net assets | $ | 9,896 | $ | 19,463 | ||||||||||||||||
2014 Divestitures | ||||||||||||||||||||||||||
Propel Energy also acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from two third parties in three separate transactions for approximately $9.3 million. | ||||||||||||||||||||||||||
On May 9, 2014, Golden Energy sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million, including estimated customary post-closing adjustments, and recorded a loss of $3.2 million. | ||||||||||||||||||||||||||
2012 Acquisitions | ||||||||||||||||||||||||||
2013 Acquisitions | ||||||||||||||||||||||||||
Third Party. On May 1, 2012, MEMP and WildHorse jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $112.1 million. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $22.1 million of revenue and $9.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date. | ||||||||||||||||||||||||||
On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million. | ||||||||||||||||||||||||||
On September 28, 2012, MEMP acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”) for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under MEMP’s revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date. | ||||||||||||||||||||||||||
MEMP closed two separate transactions during the nine months ended September 30, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. | ||||||||||||||||||||||||||
Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $147.9 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final net purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statement of operations related to the Menemsha Acquisition subsequent to the closing date. | ||||||||||||||||||||||||||
During the nine months ended September 30, 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $8.5 million. | ||||||||||||||||||||||||||
The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). | ||||||||||||||||||||||||||
2013 Divestitures | ||||||||||||||||||||||||||
On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. During the nine months ended September 30, 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million. | Undisclosed | Goodrich | Menemsha | Other Previous | ||||||||||||||||||||||
Seller | Acquisition | Acquisition | Owner | |||||||||||||||||||||||
On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013. | Acquisition | Acquisitions | ||||||||||||||||||||||||
Oil and gas properties | $ | 115,633 | $ | 91,187 | $ | 75,114 | $ | 77,764 | ||||||||||||||||||
During the nine months ended September 30, 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $90.2 million. The transaction closed on July 31, 2013. | Prepaid expenses and other current assets | — | 425 | — | — | |||||||||||||||||||||
Revenues payable | (1,602 | ) | (875 | ) | — | — | ||||||||||||||||||||
Asset retirement obligations | (1,592 | ) | (161 | ) | (408 | ) | (4,558 | ) | ||||||||||||||||||
Accrued liabilities | (297 | ) | (153 | ) | — | — | ||||||||||||||||||||
Total identifiable net assets | $ | 112,142 | $ | 90,423 | $ | 74,706 | $ | 73,206 | ||||||||||||||||||
The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | ||||||||||||||||||||||||||
Revenues | 431,061 | |||||||||||||||||||||||||
Net income | 40,940 | |||||||||||||||||||||||||
During 2012, we also acquired certain interests in oil and gas properties through several individually immaterial acquisitions for an aggregate purchase price of $10.2 million. | ||||||||||||||||||||||||||
Divestitures | ||||||||||||||||||||||||||
On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the next three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. Tanos also sold certain non-operated oil and gas properties in 2013 for $2.9 million and recorded a gain of $1.4 million. | ||||||||||||||||||||||||||
On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013. | ||||||||||||||||||||||||||
BlueStone entered into an agreement with a publicly traded third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013. | ||||||||||||||||||||||||||
During 2012, certain of our subsidiaries sold certain interests in oil and gas properties for an aggregate $3.3 million. Losses of approximately $0.1 million were recognized related to these divestures. | ||||||||||||||||||||||||||
The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing. As of December 31, 2012, the remaining proceeds were held in escrow and included in restricted cash on the balance sheet. The remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and recognized in the equity statement as a net contribution. | ||||||||||||||||||||||||||
On July 11, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million. | ||||||||||||||||||||||||||
The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties. |
Fair_Value_Measurements_of_Fin
Fair Value Measurements of Financial Instruments | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||
Fair Value Measurements of Financial Instruments | ' | ' | ||||||||||||||||||||||||||||||||
Note 4. Fair Value Measurements of Financial Instruments | Note 4. Fair Value Measurements of Financial Instruments | |||||||||||||||||||||||||||||||||
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. | Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: | |||||||||||||||||||||||||||||||||
The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. | Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | |||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Level 2—Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2013 and 2012, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. | |||||||||||||||||||||||||||||||||
The fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 2014 and December 31, 2013 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. | Level 3—Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). | |||||||||||||||||||||||||||||||||
The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014 and December 31, 2013 for each of the fair value hierarchy levels: | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||||||||||||||
The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying balance sheets approximated fair value at December 31, 2013 and 2012. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. | ||||||||||||||||||||||||||||||||||
Fair Value Measurements at September 30, 2014 Using | ||||||||||||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Fair Value | The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2013 and 2012 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013 and 2012 for each of the fair value hierarchy levels: | ||||||||||||||||||||||||||||||
Active Market | Observable Inputs | Unobservable Inputs | ||||||||||||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||||||||||||||||||||
(In thousands) | Fair Value Measurements at December 31, 2013 Using | |||||||||||||||||||||||||||||||||
Assets: | Quoted Prices in | Significant Other | Significant | Fair Value | ||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 129,711 | $ | — | $ | 129,711 | Active Market | Observable | Unobservable | |||||||||||||||||||||||
Interest rate derivatives | — | 95 | — | 95 | (Level 1) | Inputs (Level 2) | Inputs (Level 3) | |||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||
Total assets | $ | — | $ | 129,806 | $ | — | $ | 129,806 | Assets: | |||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | ||||||||||||||||||||||||||
Liabilities: | Interest rate derivatives | — | 884 | — | 884 | |||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 74,542 | $ | — | $ | 74,542 | ||||||||||||||||||||||||||
Interest rate derivatives | — | 3,712 | — | 3,712 | Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | |||||||||||||||||||||
Total liabilities | $ | — | $ | 78,254 | $ | — | $ | 78,254 | Liabilities: | |||||||||||||||||||||||||
Commodity derivatives | — | $ | 58,234 | — | $ | 58,234 | ||||||||||||||||||||||||||||
Interest rate derivatives | — | 5,590 | — | 5,590 | ||||||||||||||||||||||||||||||
Fair Value Measurements at December 31, 2013 Using | Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | |||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Fair Value | |||||||||||||||||||||||||||||||
Active Market | Observable Inputs | Unobservable Inputs | ||||||||||||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||||||||||||||||||||
(In thousands) | Fair Value Measurements at December 31, 2012 Using | |||||||||||||||||||||||||||||||||
Assets: | Quoted Prices in | Significant Other | Significant | Fair | ||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | Active Market | Observable | Unobservable | Value | ||||||||||||||||||||||
Interest rate derivatives | — | 884 | — | 884 | (Level 1) | Inputs (Level 2) | Inputs (Level 3) | |||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||
Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | Assets: | |||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 95,586 | $ | — | $ | 95,586 | ||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 58,234 | $ | — | $ | 58,234 | Liabilities: | |||||||||||||||||||||||||
Interest rate derivatives | — | 5,590 | — | 5,590 | Commodity derivatives | — | $ | 45,938 | — | $ | 45,938 | |||||||||||||||||||||||
Interest rate derivatives | — | 6,838 | — | 6,838 | ||||||||||||||||||||||||||||||
Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | ||||||||||||||||||||||||||
Total liabilities | $ | — | $ | 52,776 | $ | — | $ | 52,776 | ||||||||||||||||||||||||||
See Note 5 for additional information regarding our derivative instruments. | ||||||||||||||||||||||||||||||||||
See Note 5 for additional information regarding our derivative instruments. | ||||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis | ||||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis | ||||||||||||||||||||||||||||||||||
Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: | ||||||||||||||||||||||||||||||||||
Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: | ||||||||||||||||||||||||||||||||||
• | The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. | |||||||||||||||||||||||||||||||||
• | The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. | |||||||||||||||||||||||||||||||||
• | If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. | |||||||||||||||||||||||||||||||||
• | If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. | |||||||||||||||||||||||||||||||||
• | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. | |||||||||||||||||||||||||||||||||
• | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. | |||||||||||||||||||||||||||||||||
• | During the nine months ending September 30, 2014, we recognized $67.2 million of impairments primarily related to certain MEMP properties located in South Texas. The estimated future cash flows expected for these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. We recognized impairment charges of less than $0.1 million on a consolidated basis for the nine months ending September 30, 2013. | |||||||||||||||||||||||||||||||||
• | During the year ended December 31, 2013, we recognized $6.6 million of impairments. The impairments primarily related to certain properties located in South Texas. The estimated future cash flows expected from South Texas properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. | |||||||||||||||||||||||||||||||||
• | During the year ended December 31, 2012, we recognized $28.9 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The remaining $20.9 million of impairments primarily related to certain fields in East Texas. The carrying values of these fields were determined to be unrecoverable due to a decline in gas prices. |
Risk_Management_and_Derivative
Risk Management and Derivative Instruments | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management and Derivative Instruments | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
Note 5. Risk Management and Derivative Instruments | Note 5. Risk Management and Derivative Instruments | |||||||||||||||||||||||||||||||||||||||||||||||||
Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. | Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. | |||||||||||||||||||||||||||||||||||||||||||||||||
Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At September 30, 2014, after taking into effect netting arrangements, MEMP did not have any counterparty exposure related to its derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $37.5 million against amounts outstanding under its revolving credit facility at September 30, 2014. At September 30, 2014, after taking into effect netting arrangements, we did not have any counterparty exposure related to our derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $29.0 million against amounts outstanding under our revolving credit facility at September 30, 2014. See Note 8 for additional information regarding our revolving credit facilities. | Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender in our credit agreements. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. See Note 8 for additional information in regards to our revolving credit facilities. | |||||||||||||||||||||||||||||||||||||||||||||||||
Commodity Derivatives | Commodity Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||
We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. | A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. Generally, natural gas derivative contracts are entered into and indexed to NYMEX Henry Hub and regional indices that are in proximity to our areas of production. Generally, oil derivative contracts are entered into and indexed to NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At December 31, 2013, the MRD Segment had the following open commodity positions: | |||||||||||||||||||||||||||||||||||||||||||||||||
We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At September 30, 2014, the MRD Segment had the following open commodity positions: | ||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | 2018 | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||||||||
2014 | Average Monthly Volume (MMBtu) | 1,190,000 | 880,000 | 670,000 | 520,000 | |||||||||||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | Weighted-average fixed price | $ | 4.1 | $ | 4.19 | $ | 4.32 | $ | 4.45 | |||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 4,540,000 | 2,250,000 | 1,670,000 | 1,270,000 | 1,500,000 | Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 4.18 | $ | 4.08 | $ | 4.18 | $ | 4.3 | $ | 4.3 | Average Monthly Volume (MMBtu) | 330,000 | 130,000 | — | — | |||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 4.09 | $ | 4 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||
Collar contracts: | Weighted-average ceiling price | $ | 5.24 | $ | 4.64 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 730,000 | 1,580,000 | 1,100,000 | 1,050,000 | — | |||||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 4.11 | $ | 4.14 | $ | 4 | $ | 4 | $ | — | Basis swaps: | |||||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 5.15 | $ | 4.61 | $ | 4.71 | $ | 5.06 | $ | — | Average Monthly Volume (MMBtu) | 270,000 | 180,000 | 220,000 | 200,000 | |||||||||||||||||||||||||||||||||||
Spread | $ | (0.07 | ) | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | ||||||||||||||||||||||||||||||||||||||
TGT Z1 basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,270,000 | 1,730,000 | 220,000 | 200,000 | — | Crude Oil Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.08 | ) | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | $ | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 18,000 | 6,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | Weighted-average fixed price | $ | 91.66 | $ | 88.5 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 56,000 | 33,500 | — | 9,500 | 7,625 | Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 94.43 | $ | 93.86 | $ | — | $ | 87.62 | $ | 87 | Average Monthly Volume (Bbls) | 8,000 | 2,000 | — | — | |||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 85 | $ | 85 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||
Collar contracts: | Weighted-average ceiling price | $ | 117.5 | $ | 101.35 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 12,000 | 2,000 | 27,000 | — | — | |||||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 86.67 | $ | 85 | $ | 80 | $ | — | $ | — | NGL Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 112.33 | $ | 101.35 | $ | 99.7 | $ | — | $ | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 18,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Put option contracts: | Weighted-average fixed price | $ | 64.27 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | — | 26,000 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | — | $ | 85 | $ | — | $ | — | $ | — | At December 31, 2013, the MEMP Segment had the following open commodity positions: | |||||||||||||||||||||||||||||||||||||||
Weighted-average deferred premium | $ | — | $ | (3.80 | ) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||
NGL Derivative Contracts: | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | Natural Gas Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 184,000 | 151,000 | 148,500 | — | — | Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 44.84 | $ | 41.61 | $ | 39.75 | $ | — | $ | — | Average Monthly Volume (MMBtu) | 2,575,458 | 2,145,278 | 2,342,442 | 2,230,067 | 2,060,000 | 1,814,583 | |||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 4.34 | $ | 4.3 | $ | 4.42 | $ | 4.31 | $ | 4.52 | $ | 4.77 | ||||||||||||||||||||||||||||||||||||||
At September 30, 2014, the MEMP Segment had the following open commodity positions: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 340,000 | 350,000 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | 2018 | 2019 | Weighted-average floor price | $ | 4.93 | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||
2014 | Weighted-average ceiling price | $ | 6.12 | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | Call spreads(1): | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,580,200 | 2,605,278 | 2,692,442 | 2,450,067 | 2,160,000 | 1,914,583 | Average Monthly Volume (MMBtu) | 120,000 | 80,000 | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 4.34 | $ | 4.28 | $ | 4.4 | $ | 4.31 | $ | 4.51 | $ | 4.75 | Weighted-average sold strike price | $ | 5.08 | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||
Weighted-average bought strike price | $ | 6.31 | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 340,000 | 350,000 | — | — | — | — | Basis swaps: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 5 | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (MMBtu) | 2,822,083 | — | — | — | — | — | |||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 6.31 | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | Spread | $ | (0.09 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||
Call spreads (1): | Crude Oil Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 120,000 | 80,000 | — | — | — | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average sold strike price | $ | 5.17 | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (Bbls) | 136,444 | 148,281 | 142,313 | 130,600 | 122,000 | 40,000 | |||||||||||||||||||||||||||||||
Weighted-average bought strike price | $ | 6.53 | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | Weighted-average fixed price | $ | 95.82 | $ | 93.07 | $ | 86.85 | $ | 85.96 | $ | 85.62 | $ | 85 | |||||||||||||||||||||||||
Basis swaps: | Collar contracts: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,830,000 | 2,940,000 | 1,635,000 | 300,000 | — | — | Average Monthly Volume (Bbls) | 23,000 | 5,000 | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Spread | $ | (0.09 | ) | $ | (0.12 | ) | $ | (0.06 | ) | $ | (0.05 | ) | $ | — | $ | — | Weighted-average floor price | $ | 82.83 | $ | 80 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||
Weighted-average ceiling price | $ | 105.31 | $ | 94 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | Basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 283,452 | 314,281 | 332,813 | 326,600 | 312,000 | 160,000 | Average Monthly Volume (Bbls) | 57,292 | 57,500 | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 95.83 | $ | 90.96 | $ | 85.83 | $ | 84.38 | $ | 83.74 | $ | 85.52 | Spread | $ | (9.21 | ) | $ | (9.73 | ) | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
Collar contracts: | NGL Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 23,000 | 5,000 | — | — | — | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 82.83 | $ | 80 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (Bbls) | 118,500 | 112,800 | — | — | — | — | |||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 105.31 | $ | 94 | $ | — | $ | — | $ | — | $ | — | Weighted-average fixed price | $ | 36.23 | $ | 35.04 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||
Basis swaps: | -1 | These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | ||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 134,000 | 97,500 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (4.32 | ) | $ | (7.07 | ) | $ | — | $ | — | $ | — | $ | — | Interest Rate Swaps | |||||||||||||||||||||||||||||||||||
NGL Derivative Contracts: | Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2013, we had the following interest rate swap open positions: | |||||||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 167,500 | 149,200 | 55,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 43.13 | $ | 43.02 | $ | 39.28 | $ | — | $ | — | $ | — | Credit Facility (see Note 8) | 2014 | 2015 | 2016 | ||||||||||||||||||||||||||||||||||
MEMP Segment: | ||||||||||||||||||||||||||||||||||||||||||||||||||
-1 | These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | Average Monthly Notional (in thousands) | $ | 173,958 | $ | 280,833 | $ | 150,000 | ||||||||||||||||||||||||||||||||||||||||||
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: | Weighted-average fixed rate | 1.306 | % | 1.416 | % | 1.193 | % | |||||||||||||||||||||||||||||||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | |||||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | MRD Segment: | ||||||||||||||||||||||||||||||||||||||||||||||
2014 | Average Monthly Notional (in thousands) | $ | 118,750 | $ | 100,000 | $ | — | |||||||||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | Weighted-average fixed rate | 0.773 | % | 0.758 | % | — | ||||||||||||||||||||||||||||||||||||||||||||
NGPL TexOk basis swaps: | Floating rate | 1 Month LIBOR | 1 Month LIBOR | — | ||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,260,000 | 2,280,000 | 1,500,000 | 300,000 | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.09 | ) | $ | (0.11 | ) | $ | (0.07 | ) | $ | (0.05 | ) | Balance Sheet Presentation | |||||||||||||||||||||||||||||||||||||
NGPL STX basis swaps: | The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation on the balance sheet and the net recorded fair value as reflected on the balance sheet at December 31: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 380,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.11 | ) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||
HSC basis swaps: | Type | Balance Sheet Location | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 190,000 | 150,000 | 135,000 | — | (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.07 | ) | $ | (0.08 | ) | $ | 0.07 | $ | — | Commodity contracts | Short-term derivative instruments | $ | 21,759 | $ | 48,901 | $ | 19,739 | $ | 8,072 | ||||||||||||||||||||||||||||||
Interest rate swaps | Short-term derivative instruments | 845 | — | 3,287 | 3,575 | |||||||||||||||||||||||||||||||||||||||||||||
CIG basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | — | 210,000 | — | — | Gross fair value | 22,604 | 48,901 | 23,026 | 11,647 | |||||||||||||||||||||||||||||||||||||||||
Spread | $ | — | $ | (0.25 | ) | $ | — | $ | — | Netting arrangements | Short-term derivative instruments | (13,315 | ) | (6,980 | ) | (13,315 | ) | (6,980 | ) | |||||||||||||||||||||||||||||||
TETCO STX basis swaps: | Net recorded fair value | Short-term derivative instruments | $ | 9,289 | $ | 41,921 | $ | 9,711 | $ | 4,667 | ||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | — | 300,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | — | $ | (0.09 | ) | $ | — | $ | — | Commodity contracts | Long-term derivative instruments | $ | 83,295 | $ | 46,685 | $ | 38,495 | $ | 37,866 | |||||||||||||||||||||||||||||||
Interest rate swaps | Long-term derivative instruments | 39 | — | 2,303 | 3,263 | |||||||||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Midway-Sunset basis swaps: | Gross fair value | 83,334 | 46,685 | 40,798 | 41,129 | |||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 60,000 | 57,500 | — | — | Netting arrangements | Long-term derivative instruments | (34,718 | ) | (29,506 | ) | (34,718 | ) | (29,506 | ) | ||||||||||||||||||||||||||||||||||||
Spread—Brent | $ | (9.25 | ) | $ | (9.73 | ) | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 48,616 | $ | 17,179 | $ | 6,080 | $ | 11,623 | |||||||||||||||||||||||||||||||||||||||||
Midland basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 40,000 | 40,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread—WTI | $ | (3.68 | ) | $ | (3.25 | ) | $ | — | $ | — | Gains & Losses on Derivatives | |||||||||||||||||||||||||||||||||||||||
LLS Crude basis swaps: | We do not designate derivative instruments as hedging instruments for financial reporting purposes and neither did our predecessor. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2013 and 2012: | |||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 34,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread—WTI | $ | 3.61 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate Swaps | Derivative Instruments | Statements of Operations Location | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2014, we had the following interest rate swap open positions: | Commodity derivative contracts | (Gain) loss on commodity derivative instruments | $ | (29,294 | ) | $ | (34,905 | ) | ||||||||||||||||||||||||||||||||||||||||||
Interest rate swaps | Interest expense, net | (239 | ) | 5,582 | ||||||||||||||||||||||||||||||||||||||||||||||
Credit Facility | Remaining | 2015 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||||||||||||||||||||||||
MEMP: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Notional (in thousands) | $ | 248,333 | $ | 280,833 | $ | 150,000 | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed rate | 1.299 | % | 1.416 | % | 1.193 | % | ||||||||||||||||||||||||||||||||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | |||||||||||||||||||||||||||||||||||||||||||||||
On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Balance Sheet Presentation | ||||||||||||||||||||||||||||||||||||||||||||||||||
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2014 and December 31, 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||
September 30, | December 31, | September 30, | December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
Type | Balance Sheet Location | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Short-term derivative instruments | $ | 48,405 | $ | 21,759 | $ | 12,458 | $ | 19,739 | |||||||||||||||||||||||||||||||||||||||||
Interest rate swaps | Short-term derivative instruments | — | 845 | 3,635 | 3,287 | |||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 48,405 | 22,604 | 16,093 | 23,026 | ||||||||||||||||||||||||||||||||||||||||||||||
Netting arrangements | Short-term derivative instruments | (10,984 | ) | (13,315 | ) | (10,984 | ) | (13,315 | ) | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Short-term derivative instruments | $ | 37,421 | $ | 9,289 | $ | 5,109 | $ | 9,711 | |||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Long-term derivative instruments | $ | 81,306 | $ | 83,295 | $ | 62,084 | $ | 38,495 | |||||||||||||||||||||||||||||||||||||||||
Interest rate swaps | Long-term derivative instruments | 95 | 39 | 77 | 2,303 | |||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 81,401 | 83,334 | 62,161 | 40,798 | ||||||||||||||||||||||||||||||||||||||||||||||
Netting arrangements | Long-term derivative instruments | (46,886 | ) | (34,718 | ) | (46,886 | ) | (34,718 | ) | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 34,515 | $ | 48,616 | $ | 15,275 | $ | 6,080 | |||||||||||||||||||||||||||||||||||||||||
(Gains) Losses on Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||
All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the nine months ended September 30, 2014 and 2013 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||
Statements of | For the Nine Months | |||||||||||||||||||||||||||||||||||||||||||||||||
Operations Location | Ended September 30, | |||||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative contracts | (Gain) loss on commodity derivatives | $ | 11,580 | $ | (29,556 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Interest rate derivatives | Interest expense, net | 1,157 | 69 |
Asset_Retirement_Obligations
Asset Retirement Obligations | 9 Months Ended | 12 Months Ended | ||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | ' | ||||||||||||
Asset Retirement Obligations | ' | ' | ||||||||||||
Note 6. Asset Retirement Obligations | Note 6. Asset Retirement Obligations | |||||||||||||
Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. | Asset retirement obligations primarily relate to our portion of future plugging and abandonment of wells and related facilities. The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2013 and 2012: | |||||||||||||
The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2014 (in thousands): | ||||||||||||||
2013 | 2012 | |||||||||||||
(in thousands) | ||||||||||||||
Asset retirement obligations at beginning of period | $ | 111,769 | Asset retirement obligations at beginning of year | $ | 102,380 | $ | 90,699 | |||||||
Liabilities added from acquisitions or drilling | 5,053 | Liabilities added from acquisitions or drilling | 4,227 | 7,962 | ||||||||||
Liabilities removed upon sale of wells to an affiliate | (1,636 | ) | Liabilities removed upon sale of wells | (1,765 | ) | (1,931 | ) | |||||||
Liabilities removed upon plugging and abandoning | (344 | ) | Liabilities removed upon plugging and abandoning | (170 | ) | (119 | ) | |||||||
Revisions | 67 | Accretion expense | 5,581 | 5,009 | ||||||||||
Accretion expense | 4,601 | Revision of estimates | 1,516 | 760 | ||||||||||
Asset retirement obligations at end of period | $ | 119,510 | Asset retirement obligations at end of year | 111,769 | 102,380 | |||||||||
Less: Current portion | 90 | 390 | ||||||||||||
Asset retirement obligations—long-term portion | 111,679 | 101,990 | ||||||||||||
Restricted_Investments
Restricted Investments | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Text Block [Abstract] | ' | ' | ||||||||||||||||
Restricted Investments | ' | ' | ||||||||||||||||
Note 7. Restricted Investments | ||||||||||||||||||
Note 7. Restricted Investments | ||||||||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. The components of the restricted investment balance, which are all attributable to our MEMP Segment, are as follows at December 31: | ||||||||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||
BOEM platform abandonment (See Note 14) | $ | 66,373 | $ | 61,389 | ||||||||||||||
BOEM lease bonds | 794 | 776 | ||||||||||||||||
The components of the restricted investment balance consisted of the following at the dates indicated: | ||||||||||||||||||
SPBPC Collateral: | ||||||||||||||||||
Contractual pipeline and surface facilities abandonment (See Note 14) | 2,306 | 1,959 | ||||||||||||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,000 | ||||||||||||||||
September 30, | December 31, | City of Long Beach pipeline facility permit | 500 | 500 | ||||||||||||||
2014 | 2013 | Federal pipeline right-of-way bond | 307 | 300 | ||||||||||||||
(In thousands) | Port of Long Beach pipeline license | 100 | 100 | |||||||||||||||
BOEM platform abandonment (See Note 15) | $ | 68,970 | $ | 66,373 | ||||||||||||||
BOEM lease bonds | 794 | 794 | Restricted investments | $ | 73,385 | $ | 68,024 | |||||||||||
SPBPC Collateral: | ||||||||||||||||||
Contractual pipeline and surface facilities abandonment | 2,592 | 2,306 | ||||||||||||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,005 | ||||||||||||||||
City of Long Beach pipeline facility permit | 500 | 500 | ||||||||||||||||
Federal pipeline right-of-way bond | 307 | 307 | ||||||||||||||||
Port of Long Beach pipeline license | 100 | 100 | ||||||||||||||||
Restricted investments |
Long_Term_Debt
Long Term Debt | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Debt Disclosure [Abstract] | ' | ' | ||||||||||||||||
Long Term Debt | ' | ' | ||||||||||||||||
Note 8. Long Term Debt | Note 8. Long Term Debt | |||||||||||||||||
The following table presents our consolidated and combined debt obligations at the dates indicated: | Our debt obligations under revolving credit facilities consisted of the following at December 31: | |||||||||||||||||
September 30, | December 31, | 2013 | 2012 | |||||||||||||||
2014 | 2013 | (in thousands) | ||||||||||||||||
(In thousands) | MRD Segment: | |||||||||||||||||
MRD Segment: | Memorial Resource $1.0 billion revolving credit facility, variable-rate, terminated December 2013 | $ | — | $ | 80,000 | |||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 28,000 | $ | — | 10.00%/10.75% senior PIK toggle notes due December 2018(1) | 350,000 | — | |||||||||||
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 | — | 203,100 | 10.00%/10.75% senior PIK toggle notes unamortized discounts | (6,950 | ) | — | ||||||||||||
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 | — | 325,000 | WildHorse $1.0 billion revolving credit facility, variable-rate, due April 2018 | 203,100 | 202,200 | |||||||||||||
10.00%/10.75% senior PIK toggle notes redeemed June 2014(1) | — | 350,000 | WildHorse $325.0 million second lien term facility, variable-rate, due December 2018 | 325,000 | — | |||||||||||||
5.875% senior unsecured notes, due July 2022(2) | 600,000 | — | Black Diamond $150.0 million revolving credit facility, variable-rate, terminated November 2013 | — | 27,000 | |||||||||||||
10.00%/10.75% senior PIK toggle notes unamortized discounts | — | (6,950 | ) | BlueStone $150.0 million revolving credit facility, variable-rate, terminated August 2013 | — | — | ||||||||||||
Subtotal | 628,000 | 871,150 | Subtotal | 871,150 | 309,200 | |||||||||||||
MEMP Segment: | MEMP Segment: | |||||||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 301,000 | 103,000 | MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 103,000 | 371,000 | |||||||||||||
7.625% senior notes, fixed-rate, due May 2021(3) | 700,000 | 700,000 | 7.625% senior notes, fixed-rate, due May 1, 2021(2) | 700,000 | — | |||||||||||||
6.875% senior unsecurred notes, due August 2022(4) | 500,000 | — | 7.625% senior notes unamortized discounts | (10,933 | ) | — | ||||||||||||
Unamortized discounts | (17,200 | ) | (10,933 | ) | WHT $400.0 million revolving credit facility, variable-rate, terminated March 2013 | — | 89,300 | |||||||||||
Tanos $250.0 million revolving credit facility, variable-rate, terminated April 2013 | — | 25,250 | ||||||||||||||||
Subtotal | 1,483,800 | 792,067 | Stanolind $250.0 million revolving credit facility, variable-rate, due July 2017 | — | 85,750 | |||||||||||||
Boaz $75.0 million revolving credit facility, variable-rate, terminated October 2013 | — | 29,500 | ||||||||||||||||
Total long-term debt | $ | 2,111,800 | $ | 1,663,217 | Crown $75.0 million revolving credit facility, variable-rate, terminated October 2013 | — | 13,882 | |||||||||||
Propel Energy $200.0 million revolving credit facility, variable-rate, due June 2015 | — | 15,500 | ||||||||||||||||
-1 | The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | Subtotal | 792,067 | 630,182 | ||||||||||||||
-2 | The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
-3 | The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | Total long-term debt | $ | 1,663,217 | $ | 939,382 | ||||||||||||
-4 | The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
Borrowing Base | -1 | The estimated fair value of this fixed-rate debt was $348.3 million. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||||||
-2 | The estimated fair value of this fixed-rate debt was $721.0 million. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at the date indicated (in thousands): | ||||||||||||||||||
Each of the revolving credit facilities contain customary covenants and restrictive provisions including but not limited to: (i) limitation on indebtedness and liens, (ii) limitations on restricted payments, (iii) limitation on investments and acquisitions, (iv) limitations on transactions with affiliates, (v) limitation on mergers, consolidation and asset sales, and (vi) limitations on commodity hedging and interest rate hedging. Each of the revolving credit facilities also includes financial maintenance covenants that require each borrower to meet certain financial performance criteria periodically (e.g., minimum interest coverage ratio and maximum leverage). The definitions and required ratios are set forth in each credit facility. | ||||||||||||||||||
September 30, | Each of the credit facilities contain customary and other events of default including but not limited to: (i) failure to make payments when due, (ii) breach of any covenants continuing beyond the cure period, (iii) default under any other material debt, (iv) change in management or change of control, and (v) certain material adverse effects on the business of the loan parties. Upon an event of default, revolving credit commitments could be terminated and any outstanding indebtedness under such revolving credit facility, together with accrued interest, fees and other obligations under such credit facility, could be declared immediately due and payable. | |||||||||||||||||
2014 | ||||||||||||||||||
MRD Segment: | Borrowing Base | |||||||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 668,500 | ||||||||||||||||
MEMP Segment: | Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at December 31: | |||||||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 1,315,000 | |||||||||||||||||
Subsequent events. On October 3, 2014, the borrowing base under the MRD revolving credit facility was increased to $725.0 million, and we entered into an amendment to the credit agreement to, among other things, permit us to hedge a larger portion of our anticipated production from our proved reserves. On October 10, 2014, MEMP’s borrowing base under its revolving credit facility was redetermined and increased to $1.44 billion. | 2013 | |||||||||||||||||
(in thousands) | ||||||||||||||||||
MRD Revolving Credit Facility | MRD Segment: | |||||||||||||||||
WildHorse $1.0 billion revolving credit facility, variable-rate, due April 2018 | 300,000 | |||||||||||||||||
On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million. | MEMP Segment: | |||||||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 845,000 | |||||||||||||||||
We are permitted to borrow under the revolving credit facility in an amount up to the least of (i) the face amount of our revolving credit facility, (ii) the borrowing base and (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date. | ||||||||||||||||||
Total borrowing base | 1,145,000 | |||||||||||||||||
Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. | ||||||||||||||||||
The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0. | Weighted-Average Interest Rates | |||||||||||||||||
Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness. | The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented: | |||||||||||||||||
Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. | ||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||
MRD 5.875% Senior Unsecured Notes Offering | Credit facility | 2013 | 2012 | |||||||||||||||
MRD Segment: | ||||||||||||||||||
On July 10, 2014, the Company completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries. The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP. | Memorial Resource | 3.17 | % | 4.11 | % | |||||||||||||
Classic | n/a | 4.5 | % | |||||||||||||||
The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately. | WildHorse revolver | 2.3 | % | 3 | % | |||||||||||||
WildHorse second lien | 7.6 | % | n/a | |||||||||||||||
PIK notes | Black Diamond | 3.97 | % | 3.62 | % | |||||||||||||
BlueStone | n/a | n/a | ||||||||||||||||
On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. | MEMP Segment: | |||||||||||||||||
MEMP | 3.25 | % | 2.74 | % | ||||||||||||||
A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. | Tanos | 3.1 | % | 2.31 | % | |||||||||||||
WHT | 2.29 | % | 2.6 | % | ||||||||||||||
WildHorse Resources Revolving Credit Facility and Second Lien Facility | REO | n/a | 3.4 | % | ||||||||||||||
Stanolind | 3.52 | % | 3.76 | % | ||||||||||||||
On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. | Crown | 3.38 | % | 4.2 | % | |||||||||||||
Propel Energy | 3.08 | % | 3.28 | % | ||||||||||||||
On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default. | ||||||||||||||||||
Generally, borrowings under each revolving credit facility bear interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus a margin that varies according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies according to the borrowing base usage. The unused portion of the borrowing base will be subject a commitment fee that may vary from 0.375% to 0.50% per annum according to the borrowing base usage. | ||||||||||||||||||
On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds. | ||||||||||||||||||
Memorial Resource Revolving Credit Agreement & Senior Notes | ||||||||||||||||||
In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan. | ||||||||||||||||||
On July 13, 2012, Memorial Resource entered into a two-year $50.0 million senior secured revolving credit facility with an initial borrowing base of $35.0 million. Memorial Resource pledged 7,061,294 of MEMP common units and 5,360,912 of MEMP subordinated units as security under the revolving credit facility as well as its oil and gas properties and certain other assets of Memorial Resource. This revolving credit facility was also guaranteed by certain of Memorial Resource’s wholly-owned subsidiaries. | ||||||||||||||||||
MEMP Revolving Credit Facility & Senior Notes | ||||||||||||||||||
On November 20, 2012, Memorial Resource entered into a first amendment to its credit agreement, which among other things: (i) increased the aggregate maximum credit to $1.0 billion, (ii) increased the borrowing base to $120.0 million and (iii) extended the maturity date to November 20, 2016. On April 25, 2013, Memorial Resource entered into a second amendment to its credit agreement, which among other things: (i) increased the borrowing base to $170.0 million and (ii) designated Tanos together with its consolidating subsidiaries as additional guarantors. On October 1, 2013, Tanos and its consolidating subsidiaries were removed as guarantors and the borrowing base was reduced to $120.0 million. On November 1, 2013, Memorial Resource entered into a third amendment to its credit agreement, which among other things: (i) designated Black Diamond together with its consolidating subsidiaries as additional guarantors, (ii) reduced the borrowing base to $100.0 million, and (iii) permitted second lien indebtedness. On November 22, 2013, the borrowing base was automatically reduced to $60.0 million upon Memorial Resource’s sale of 7,061,294 MEMP common units in a secondary offering. | ||||||||||||||||||
Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). | ||||||||||||||||||
On December 18, 2013, indebtedness then outstanding under the revolving credit facility of $59.7 million and all accrued interest was paid off in full and the revolving credit facility was terminated in connection with the issuance of senior notes discussed below. | ||||||||||||||||||
Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. | ||||||||||||||||||
On December 18, 2013, Memorial Resource and its wholly-owned subsidiary, Memorial Resource Finance Corp. (“MRD Finance Corp.” and collectively, the “MRD Issuers”), completed a private placement of $350.0 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”). The PIK notes were issued at 98% of par and will mature on December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under Memorial Resource’s revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. | ||||||||||||||||||
On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately. | ||||||||||||||||||
Interest on the PIK notes will be payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. Subject to conditions in the indenture governing the PIK notes, Memorial Resource will be required to pay interest on the PIK notes in cash or through issuing additional notes (such an issuance, “PIK Interest”). The interest rate on the PIK notes is 10.00% per annum for interest paid in cash or 10.75% per annum for PIK Interest. PIK Interest will be paid by issuing additional notes having the same terms as the PIK notes. The PIK notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MRD Issuers may also be required to repurchase the PIK notes upon a change of control. | ||||||||||||||||||
On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions on a joint and several basis by all of MEMP’s subsidiaries other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. The net proceeds from the notes offering of approximately $484.9 million, after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility and for general partnership purposes. | ||||||||||||||||||
At the time the PIK notes were issued, all of Memorial Resource’s subsidiaries other than MEMP and BlueStone (and their respective subsidiaries) were designated as restricted subsidiaries. The indenture governing the PIK notes contains customary covenants and restrictive provisions that apply to both Memorial Resource and its restricted subsidiaries, many of which will terminate if at any time no default exists under the indenture and the PIK notes receive an investment grade rating from both of two specified ratings agencies. The PIK notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Memorial Resource’s restricted subsidiaries, except MEMP GP, WildHorse and MRD Royalty LLC. | ||||||||||||||||||
Weighted-Average Interest Rates | ||||||||||||||||||
The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency, all outstanding PIK notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding PIK notes may declare all the PIK notes to be due and payable immediately. | ||||||||||||||||||
The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: | ||||||||||||||||||
Classic Revolving Credit Facility | ||||||||||||||||||
For the Nine Months | On November 1, 2007, Classic entered into a four-year, $150.0 million revolving credit facility, which was collateralized by its oil and gas properties. The revolving credit facility was amended on June 21, 2010 to extend the maturity date to June 21, 2014. On November 20, 2012, indebtedness then outstanding under the revolving credit facility of $80.0 million and all accrued interest was paid off in full with borrowings under the Memorial Resource revolving credit facility and the Classic revolving credit facility was terminated. | |||||||||||||||||
Ended September 30, | ||||||||||||||||||
Credit Facility | 2014 | 2013 | WildHorse Revolving Credit Facility & Second Lien Facility | |||||||||||||||
MRD Segment: | ||||||||||||||||||
MRD revolving credit facility | 2.4 | % | n/a | On May 12, 2010, WildHorse entered into a revolving credit facility. Borrowings under the amended revolving credit facility are secured by liens on substantially all of WildHorse’s properties, but in any event, not less than 80% of the total value of the WildHorse’s oil and natural gas properties. | ||||||||||||||
MRD LLC revolver terminated December 2013 | n/a | 3.2 | % | |||||||||||||||
WildHorse Resources revolver terminated June 2014 | 4.04 | % | 3.44 | % | On April 3, 2013, WildHorse entered into an amended and restated credit agreement. The new revolving credit facility provides for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and has an initial borrowing base of $300.0 million. The new revolving credit facility matures on April 13, 2018. The borrowing base is subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility are secured by liens on substantially all of WildHorse’s properties, but in any event, not less than 80% of the total value of the WildHorse’s oil and natural gas properties. | |||||||||||||
WildHorse Resources second lien terminated June 2014 | 6.44 | % | 6.5 | % | ||||||||||||||
Black Diamond terminated November 2013 | n/a | 3.34 | % | On June 13, 2013, WildHorse entered into a $325.0 million second lien term loan agreement and matures on December 13, 2018. No amount of second lien term loans once repaid may be reborrowed. Borrowings bear interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement are secured by second-priority liens on substantially all of WildHorse’s properties, but in any event, not less than 80% of the total value of the WildHorse’s oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights is set forth in an intercreditor agreement. The second lien term loan agreement contains customary affirmative and negative covenants, restrictive provisions and events of default. | ||||||||||||||
MEMP Segment: | ||||||||||||||||||
MEMP revolving credit facility | 2.08 | % | 2.55 | % | On June 13, 2013, WildHorse borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a one-time special $225.0 million distribution to Memorial Resource. This $225.0 million distribution was subsequently distributed to NGP. | |||||||||||||
WHT revolver terminated March 2013 | n/a | 2.29 | % | |||||||||||||||
Tanos revolver terminated April 2013 | n/a | 2.12 | % | Black Diamond Revolving Credit Facility | ||||||||||||||
Stanolind revolver paid off by MEMP October 2013 | n/a | 3.52 | % | |||||||||||||||
Boaz revolver terminated October 2013 | n/a | 2.97 | % | On July 27, 2011, the Black Diamond entered into a second amended and restated revolving credit facility, which extended the maturity date of the original agreement to May 9, 2015. Borrowings under the revolving credit facility were collateralized by Black Diamond’s oil and natural gas properties. On November 1, 2013, the Black Diamond revolving credit facility was terminated. There was no indebtedness outstanding or accrued interest payable on such date. | ||||||||||||||
Crown revolver terminated October 2013 | n/a | 3.38 | % | |||||||||||||||
Propel Energy revolver paid off by MEMP October 2013 | n/a | 3.08 | % | BlueStone Revolving Credit Facility | ||||||||||||||
Unamortized Deferred Financing Costs | On July 8, 2009, BlueStone entered into a $150.0 million revolving credit facility with various lenders. The line of credit was available until July 8, 2012, at which time all principal and accrued interest amounts would have been payable. On June 25, 2010, BlueStone refinanced its existing credit agreement and entered into a new $150.0 million revolving credit facility. Amounts outstanding under this credit facility were payable on June 25, 2014. There were no amounts outstanding under these facilities at December 31, 2012. Borrowings under the revolving credit facility were secured by BlueStone’s assets and its equity interests in its subsidiaries. On August 27, 2013, the BlueStone revolving credit facility was terminated. There was no indebtedness outstanding or accrued interest payable on such date. | |||||||||||||||||
Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated: | MEMP Revolving Credit Facility & Senior Notes | |||||||||||||||||
OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and certain of its current and future subsidiaries. A sixth amendment to the credit agreement was entered into on September 23, 2013, which among other things: (i) increased the facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of MEMP’s $603.0 million acquisition that closed October 1, 2013. The borrowing base was automatically reduced by $100.0 million in conjunction with the issuances of senior notes in April and May 2013 as discussed below in accordance with the terms of the credit facility. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional senior notes. | ||||||||||||||||||
September 30, | December 31, | |||||||||||||||||
2014 | 2013 | Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. | ||||||||||||||||
(In thousands) | ||||||||||||||||||
MRD Segment: | On April 17, 2013, MEMP and its wholly-owned subsidiary, Memorial Production Finance Corporation (“Finance Corp.” and collectively, the “Issuers”), completed a private placement of $300.0 million aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes were issued at 98.521% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the Senior Notes, and certain immaterial subsidiaries). On May 23, 2013, the Issuers issued an additional $100.0 million aggregate principal amount of the Senior Notes at 102% of par. On October 10, 2013, the Issuers issued additional $300.0 million aggregate principal amounts at 97% of par. The Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year, commencing November 1, 2013. The Senior Notes are governed by an indenture. The Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Senior Notes may declare all the Senior Notes to be due and payable immediately. The Issuers have agreed pursuant to registration rights agreements to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement with respect to the Senior Notes no later than April 17, 2014. | |||||||||||||||||
MRD revolving credit facility | $ | 4,433 | $ | — | ||||||||||||||
MRD senior notes | 12,825 | — | Tanos Revolving Credit Facility | |||||||||||||||
WildHorse Resources revolving credit facility | — | 2,436 | ||||||||||||||||
WildHorse Resources second lien term loan | — | 9,030 | On December 16, 2010, Tanos entered into an amended and restated credit agreement with various lenders, which consisted of a four-year, $250 million revolving credit facility, which was collateralized by Tanos’ oil and gas properties. On April 1, 2013, indebtedness then outstanding under the revolving credit facility of $27.0 million was repaid and on April 25, 2013 all accrued interest was paid off in full and the Tanos revolving credit facility was terminated. | |||||||||||||||
PIK notes | — | 8,261 | ||||||||||||||||
MEMP Segment: | WHT Revolving Credit Facility | |||||||||||||||||
MEMP revolving credit facility | 6,882 | 5,413 | ||||||||||||||||
2021 Senior Notes | 13,836 | 15,053 | On April 8, 2011, WHT entered into a revolving credit facility. Borrowings under the revolving credit facility were secured by liens on substantially all of WHT’s properties, but in any event, not less than 80% of the total value of the WHT’s oil and natural gas properties. On March 28, 2013, the debt balance then outstanding under the revolving credit facility of $89.3 million and all accrued interest was paid off in full and the WHT revolving credit facility was terminated. | |||||||||||||||
2022 Senior Notes | 8,222 | — | ||||||||||||||||
Stanolind Revolving Credit Facility | ||||||||||||||||||
$ | 46,198 | $ | 40,193 | |||||||||||||||
On September 9, 2010, Stanolind entered into a multi-year $50.0 million senior secured revolving credit agreement, which is collateralized by substantially all of Stanolind’s oil and gas properties. During 2012, the credit agreement was amended, which among other things: (i) increased the aggregate maximum credit to $250.0 million and (ii) increased the borrowing base to $75.0 million. The borrowing base was redetermined subsequent to the amendment date and set at $97.0 million. The maturity date of the credit facility was July 13, 2017. All of Stanolind’s indebtedness outstanding under the revolving credit facility was attributable to Stanolind SPV. On October 1, 2013, the debt balance then outstanding under the revolving credit facility and all accrued interest was paid off in full by MEMP on behalf of Stanolind. | ||||||||||||||||||
Boaz Revolving Credit Facility | ||||||||||||||||||
On August 1, 2011, Boaz entered into a multi-year $75.0 million senior secured revolving credit agreement, which was collateralized by substantially all of Boaz’s oil and gas properties. The maturity date of the credit facility was August 31, 2015. On October 1, 2013, the debt balance then outstanding under the revolving credit facility and all accrued interest was paid off in full and the Boaz revolving credit facility was terminated. | ||||||||||||||||||
Crown Revolving Credit Facility | ||||||||||||||||||
On January 28, 2010, Crown entered into a multi-year $75.0 million senior secured revolving credit agreement, which was collateralized by substantially all of Crown’s oil and gas properties. The maturity date of the credit facility was October 25, 2016. On October 1, 2013, the debt balance then outstanding under the revolving credit facility and all accrued interest was paid off in full and the Crown revolving credit facility was terminated. | ||||||||||||||||||
Propel Energy Revolving Credit Facility | ||||||||||||||||||
On June 15, 2011, Propel Energy entered into a multi-year $200.0 million senior secured revolving credit agreement, which was collateralized by substantially all of Propel Energy’s oil and gas properties. The maturity date of the credit facility was June 15, 2015. All of Propel Energy’s indebtedness outstanding under the revolving credit facility was attributable to Propel SPV. On October 1, 2013, the debt balance then outstanding under the revolving credit facility and all accrued interest was paid off in full by MEMP on behalf of Propel Energy. | ||||||||||||||||||
REO Revolving Credit Facility | ||||||||||||||||||
On October 26, 2011, REO entered into a three-year, $150.0 million revolving credit facility, which was collateralized by its assets. On December 12, 2012, indebtedness then outstanding under the revolving credit facility of $28.5 million and all accrued interest was paid off in full and the revolving credit facility was terminated. | ||||||||||||||||||
Unamortized Deferred Financing Costs | ||||||||||||||||||
Unamortized deferred financing costs associated with our combined debt obligations were as follows at December 31: | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
(in thousands) | ||||||||||||||||||
MRD Segment: | ||||||||||||||||||
Memorial Resource revolving credit facility | $ | — | $ | 653 | ||||||||||||||
PIK notes | 8,261 | — | ||||||||||||||||
Classic revolving credit facility | — | 160 | ||||||||||||||||
WildHorse revolving credit facility | 2,436 | 921 | ||||||||||||||||
WildHorse second lien term loan | 9,030 | — | ||||||||||||||||
Black Diamond revolving credit facility | — | 233 | ||||||||||||||||
MEMP Segment: | ||||||||||||||||||
MEMP revolving credit facility | 5,413 | 3,359 | ||||||||||||||||
Senior Notes | 15,053 | — | ||||||||||||||||
Tanos revolving credit facility | — | 416 | ||||||||||||||||
WHT revolving credit facility | — | 1,419 | ||||||||||||||||
Stanolind revolving credit facility | — | 580 | ||||||||||||||||
Boaz revolving credit facility | — | 153 | ||||||||||||||||
Crown revolving credit facility | — | 96 | ||||||||||||||||
Propel Energy revolving credit facility | — | 236 | ||||||||||||||||
$ | 40,193 | $ | 8,226 | |||||||||||||||
Stockholders_Equity_and_Noncon
Stockholders' Equity and Noncontrolling Interests | 9 Months Ended | ||||
Sep. 30, 2014 | |||||
Equity [Abstract] | ' | ||||
Stockholders' Equity and Noncontrolling Interests | ' | ||||
Note 9. Stockholders’ Equity and Noncontrolling Interests | |||||
Common Stock | |||||
The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2014: | |||||
Balance January 1, 2014 | — | ||||
Shares of common stock issued in connection with restructuring transactions (Note 1) | 171,000,000 | ||||
Shares of common stock issued sold in initial public offering (Note 1) | 21,500,000 | ||||
Restricted common shares issued (Note 11) | 1,068,422 | ||||
Restricted common shares forfeited | (9,211 | ) | |||
Balance September 30, 2014 | 193,559,211 | ||||
See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are considered issued and outstanding on the grant date of restricted stock award. | |||||
Preferred Stock | |||||
Our amended and restated certificate of incorporation authorizes our board of directors (“Board”), subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares issued and outstanding as of September 30, 2014. | |||||
Dividend Policy | |||||
We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant. | |||||
Noncontrolling Interests | |||||
Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP, including the subordinated units currently held by MRD Holdco, and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. | |||||
Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC. | |||||
Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. | |||||
On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT. | |||||
On July 15, 2014, MEMP sold 9,890,000 common units representing limited partner interests in MEMP (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. | |||||
On September 9, 2014, MEMP issued 14,950,000 common units representing limited partner interests in MEMP (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.6 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. | |||||
On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information. | |||||
In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information. |
Earnings_per_Share
Earnings per Share | 9 Months Ended | ||||
Sep. 30, 2014 | |||||
Earnings Per Share [Abstract] | ' | ||||
Earnings per Share | ' | ||||
Note 10. Earnings per Share | |||||
The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): | |||||
For the Nine | |||||
Months Ended | |||||
September 30, | |||||
2014 | |||||
Numerator: | |||||
Net income (loss) available to common stockholders | $ | (951,801 | ) | ||
Denominator: | |||||
Weighted average common shares outstanding | 192,500 | ||||
Restricted common shares(1) | — | ||||
Weighted average common and common equivalent shares outstanding | 192,500 | ||||
Basic EPS | $ | (4.94 | ) | ||
Diluted EPS | $ | (4.94 | ) | ||
-1 | The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014. | ||||
Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for all periods presented due to common control considerations. The following sets forth the calculation of our supplemental EPS, for the periods indicated (in thousands, except per share amounts): | |||||
For the Nine | |||||
Months Ended | |||||
September 30, | |||||
2014 | |||||
Numerator: | |||||
Net income (loss) attributable to Memorial Resource Development Corp. | $ | (930,071 | ) | ||
Denominator: | |||||
Weighted average common shares outstanding | 192,500 | ||||
Restricted common shares(1) | — | ||||
Weighted average common and common equivalent shares outstanding | 192,500 | ||||
Basic EPS | $ | (4.83 | ) | ||
Diluted EPS | $ | (4.83 | ) | ||
-1 | The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014. |
LongTerm_Incentive_Plans
Long-Term Incentive Plans | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | ' | ||||||||||||||||
Long-Term Incentive Plans | ' | ' | ||||||||||||||||
Note 11. Long-Term Incentive Plans | Note 10. Long-Term Incentive Plan | |||||||||||||||||
MRD | In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates, including Memorial Resource, who perform services for MEMP. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. During the years ended December 31, 2013 and 2012, there were multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of MEMP GP and other Memorial Resource employees who provide services for MEMP. | |||||||||||||||||
In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof. | The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. | |||||||||||||||||
In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions. | Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to MEMP GP’s executive officers and other Memorial Resource employees during the years ended December 31, 2013 and 2012 was $9.7 million and $5.0 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of MEMP GP are also recognized as compensation cost on a straight-line basis over the requisite service period. The compensation costs associated with these awards are recorded as general and administrative expenses. | |||||||||||||||||
Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires. | The following table summarizes information regarding restricted common unit awards for the periods presented: | |||||||||||||||||
The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: | ||||||||||||||||||
Number of | Weighted Average | |||||||||||||||||
Units | Grant Date Fair | |||||||||||||||||
Number | Weighted- | Value per Unit(1) | ||||||||||||||||
of Shares | Average Grant | Restricted common units outstanding at January 1, 2012 | — | $ | — | |||||||||||||
Date Fair Value | Granted(2) | 287,943 | $ | 18.07 | ||||||||||||||
per Share(1) | Forfeited | (2,334 | ) | $ | 17.14 | |||||||||||||
Restricted common shares outstanding at December 31, 2013 | — | $ | — | |||||||||||||||
Granted(2) | 1,068,422 | $ | 19 | Restricted common units outstanding at December 31, 2012 | 285,609 | $ | 18.08 | |||||||||||
Forfeited | (9,211 | ) | $ | 19 | Granted(3) | 524,718 | $ | 18.83 | ||||||||||
Forfeited | (11,734 | ) | $ | 17.24 | ||||||||||||||
Restricted common units outstanding at September 30, 2014 | 1,059,211 | $ | 19 | Vested | (91,666 | ) | $ | 18.31 | ||||||||||
Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | |||||||||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards issued. | |||||||||||||||||
-2 | The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on a grant date market price of $19.00 per share. | |||||||||||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | |||||||||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | -2 | The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices of MEMP ranging from of $17.14 to $18.58 per unit. | ||||||||||||||||
-3 | The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices of MEMP ranging from of $18.33 to $20.35 per unit. | |||||||||||||||||
For the Nine Months | The unrecognized compensation cost associated with restricted common unit awards was an aggregate $9.9 million at December 31, 2013, which will be recognized over a weighted-average period of 2.2 years. | |||||||||||||||||
Ended September 30, | ||||||||||||||||||
2014 | 2013 | Since the restricted common units are participating securities of MEMP, any distributions received by the restricted common unitholders are reflected as a component of cash distributions to noncontrolling interest as presented on our statements of consolidated and combined cash flows. During the years ended December 31, 2013 and 2012, the restricted common unitholders received a distribution of approximately $1.0 million and $0.2 million, respectively. | ||||||||||||||||
$1,487 | $— | |||||||||||||||||
The unrecognized compensation cost associated with restricted common share awards was $18.6 million at September 30, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.68 years. | ||||||||||||||||||
MEMP | ||||||||||||||||||
In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. | ||||||||||||||||||
The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. | ||||||||||||||||||
The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: | ||||||||||||||||||
Number of Units | Weighted- | |||||||||||||||||
Average Grant | ||||||||||||||||||
Date Fair Value | ||||||||||||||||||
per Unit(1) | ||||||||||||||||||
Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | |||||||||||||||
Granted(2) | 684,954 | $ | 22.39 | |||||||||||||||
Forfeited | (36,112 | ) | $ | 20.43 | ||||||||||||||
Vested | (260,067 | ) | $ | 18.56 | ||||||||||||||
Restricted common units outstanding at September 30, 2014 | 1,095,702 | $ | 20.93 | |||||||||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards issued. | |||||||||||||||||
-2 | The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on a grant date market price range of $21.99 – $23.40 per unit | |||||||||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | ||||||||||||||||||
For the Nine Months | ||||||||||||||||||
Ended September 30, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
$5,387 | $2,322 | |||||||||||||||||
The unrecognized compensation cost associated with restricted common unit awards was $19.1 million at September 30, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.3 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows. |
Incentive_Units
Incentive Units | 9 Months Ended | 12 Months Ended | |||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | ||||||||||||
Compensation Related Costs [Abstract] | ' | ' | |||||||||||
Incentive Units | ' | ' | |||||||||||
Note 12. Incentive Units | Note 11. Incentive Units | ||||||||||||
General | Each of the governing documents of BlueStone Holdings, Tanos, WildHorse, Classic, Black Diamond and Memorial Resource either currently provide or previously provided for the issuance of incentive units. The incentive units are subject to performance conditions that affects their vesting. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. | ||||||||||||
Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | BlueStone Holdings, Tanos, WildHorse, Classic, Black Diamond and Memorial Resource each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units are entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) have been achieved. Payouts are generally triggered after the recovery of specified members’ capital contributions plus a rate of return. On December 14, 2011 and in connection with MEMP’s initial public offering, BlueStone Holdings’ Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders will participate in 16.5% of any future distributions made by BlueStone Holdings. | ||||||||||||
BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone. | Vesting of the incentive units is generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended). | ||||||||||||
Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended). | Except for the following, no compensation cost has been recorded related to incentive units for the years ended December 31, 2013 and 2012: | ||||||||||||
On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to Memorial Resource and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the nine months ended September 30, 2013. | • | During 2012, a special distribution of $9.5 million was approved and declared to the WildHorse incentive unit holders as an advance on a future potential final distribution. This special distribution was included in general and administrative expense in the accompanying statement of operations for the year ended December 31, 2012. | |||||||||||
Compensation expense of approximately $1.0 million and $19.1 million was recorded by BlueStone (see Note 3) and recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 and 2013, respectively. | • | On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to Memorial Resource and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013. | |||||||||||
In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock. | • | Compensation expense of approximately $19.1 million was recorded by BlueStone and recognized as general and administrative expense during July 2013. Net proceeds generated from the sale of oil and gas properties (see Note 3) were used to pay the distribution. | |||||||||||
MRD Holdco | • | On November 1, 2013, Memorial Resource purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Total consideration remitted by Memorial Resource was approximately $28.5 million, of which $2.0 million is payable in quarterly installments commencing February 1, 2014. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate and recognized as general and administrative expense during November 2013. | |||||||||||
MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). | • | In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013 with a corresponding amount in accrued liabilities on our balance sheet at December 31, 2013 as payment was not made until January 2, 2014. | |||||||||||
The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco. The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. We recognized $136.7 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $158.5 million as of September 30, 2014 will be recognized over the remaining expected service period. The fair value of the Exchanged Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions. As such, these awards are not dilutive to our stockholders. | In connection with the Offering, certain former management members of WildHorse Resources will contribute their 0.1% membership interest in WildHorse as well as their incentive units in exchange for shares of common stock of MRDC and cash consideration. As such, WildHorse is expected to recognize additional compensation cost in 2014 upon the closing of the Offering. | ||||||||||||
Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved. The payment likelihood was deemed probable at September 30, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. We recognized $0.6 million of compensation expense and the unrecognized compensation expense of approximately $5.3 million as of September 30, 2014 will be recognized over the remaining expected service period. The fair value of the Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. No payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions. As such, these awards are not dilutive to our stockholders. | |||||||||||||
The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: | |||||||||||||
Exchanged Incentive Units | Subsequent Incentive Units | ||||||||||||
Valuation date | 9/30/14 | 9/30/14 | |||||||||||
Dividend yield | 0 | % | 0 | % | |||||||||
Expected volatility | 21.47 | % | 21.47 | % | |||||||||
Risk-free rate | 0.9 | % | 0.9 | % | |||||||||
Expected life (years) | 2.67 | 2.67 |
Related_Party_Transactions
Related Party Transactions | 9 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||
Related Party Transactions [Abstract] | ' | ' | ||||||||
Related Party Transactions | ' | ' | ||||||||
Note 13. Related Party Transactions | Note 12. Related Party Transactions | |||||||||
Amounts due to (due from) MRD Holdco and certain affiliates of NGP at September 30, 2014 and December 31, 2013 are presented as “Accounts receivable—affiliates” and “Accounts payable—affiliates” in the accompanying balance sheets. | Common Control Transactions between MEMP and Other Memorial Resource Subsidiaries | |||||||||
NGPCIF NPI Acquisition | During the year ended December 31, 2012, MEMP acquired additional oil and natural gas properties from Tanos and Classic. MEMP acquired all of the outstanding membership interests in WHT from WildHorse and Tanos on March 28, 2013; acquired all the outstanding membership interests in Prospect Energy from Black Diamond on October 1, 2013; acquired all of the outstanding membership interests in Tanos from Memorial Resource on October 1, 2013; and acquired the MRD Assets from Memorial Resource on October 1, 2013. These intercompany transactions eliminate in preparation of our consolidated and combined financial statements. | |||||||||
WildHorse Resources purchased a net profits interest from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands): | Beta Acquisition | |||||||||
On December 12, 2012, MEMP acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under MEMP’s revolving credit facility and the net proceeds generated from its December 12, 2012 public offering of common units. The effective date for this transaction was September 1, 2012. The acquired properties, which are referred to as the Beta properties, primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. MEMP recorded the following net assets (in thousands): | ||||||||||
Accounts receivable | $ | 2,274 | ||||||||
Oil and natural gas properties, net | 40,056 | |||||||||
Accrued liabilities | (297 | ) | Cash and cash equivalents | $ | 6,021 | |||||
Asset retirement obligations | (277 | ) | Accounts receivable | 16,284 | ||||||
Short-term derivative instruments, net | 2,926 | |||||||||
Net assets | $ | 41,756 | Prepaid expenses and other current assets | 4,521 | ||||||
Oil and natural gas properties, net | 108,342 | |||||||||
Restricted investments | 68,009 | |||||||||
Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates. | Accounts payable | (9,092 | ) | |||||||
Accrued liabilities | (9,140 | ) | ||||||||
Common Control Transactions between MEMP and Other MRD LLC Subsidiaries | Asset retirement obligations | (58,746 | ) | |||||||
Credit facilities | (28,500 | ) | ||||||||
MEMP acquired all of the outstanding membership interests in WHT from WildHorse Resources and Tanos on March 28, 2013 for a purchase price of approximately $200.0 million. On April 1, 2014, MEMP acquired certain oil and natural gas producing properties in East Texas from WildHorse Resources for approximately $33.3 million, including estimated customary post-closing adjustments. | Deferred tax liability | (1,674 | ) | |||||||
Noncontrolling interest | (5,255 | ) | ||||||||
MEMP acquired of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013. | ||||||||||
Net assets | $ | 93,696 | ||||||||
MEMP acquired of all the outstanding membership interests in Prospect from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013. | ||||||||||
MEMP acquired of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013. | An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million during the year ended December 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations. | |||||||||
Other Acquisitions or Dispositions | October 2013 Cinco Group Acquisition | |||||||||
On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. | On October 1, 2013, MEMP acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from Memorial Resource and certain affiliates of NGP for an aggregate preliminary purchase price of approximately $603 million (subject to customary post-closing adjustments), of which approximately $507.1 million was received by certain affiliates of NGP. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. | |||||||||
On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement. | ||||||||||
Cash and cash equivalents | $ | 2,820 | ||||||||
On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands): | Accounts receivable | 5,184 | ||||||||
Prepaid expenses and other current assets | 1,454 | |||||||||
Oil and natural gas properties, net | 342,759 | |||||||||
Cash and cash equivalents | $ | 33,001 | Other long-term assets | 344 | ||||||
Restricted cash | 300 | Accounts payable | (2,346 | ) | ||||||
Accounts receivable | 5,256 | Revenue payable | (2,910 | ) | ||||||
Prepaid expenses and other current assets | 379 | Accrued liabilities | (1,799 | ) | ||||||
Property, plant and equipment, net | 3,410 | Short-term derivative instruments, net | (1,828 | ) | ||||||
Other long-term assets | 4 | Long-term derivative instruments, net | (826 | ) | ||||||
Accounts payable | (19,959 | ) | Asset retirement obligations | (9,606 | ) | |||||
Accounts payable—affiliates | (17,099 | ) | Credit facilities | (151,690 | ) | |||||
Accrued liabilities | (5,061 | ) | ||||||||
Net assets | $ | 181,556 | ||||||||
Net assets | $ | 231 | ||||||||
Net Profits Interest Sold to NGP | ||||||||||
Related Party Agreements | ||||||||||
Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions. | ||||||||||
We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. | ||||||||||
The net profits agreements for these transactions provide for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements do not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments are made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments include credits for revenue receipts which are offset with production costs, capital expenditures and the management fee and are adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse cannot collect funds owed by NGPCIF to WildHorse, but WildHorse can net amounts due from future quarterly payments. | ||||||||||
Registration Rights Agreement | ||||||||||
As a result of these transactions, WildHorse paid NGPCIF a total of $2.6 million and $2.3 million during 2013 and 2012, respectively. NGPCIF owed WildHorse $0.2 million at December 31, 2013. WildHorse owed NGPCIF $0.4 million at December 31, 2012. | ||||||||||
In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. | ||||||||||
On February 28, 2014, WildHorse repurchased these net profits interests from NGPCIF for a purchase price $63.4 million after customary adjustments. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method and our consolidated and combined financial statements presented herein have been retrospectively revised. | ||||||||||
Voting Agreement | ||||||||||
WildHorse Management Services Agreement | ||||||||||
In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above. | ||||||||||
WildHorse Resources II, LLC (“WHR II”) is an independent energy company engaged in the acquisition, exploitation, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse began providing general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities including administrative and land services, operator services and financial and accounting services. As operator, WildHorse receives operated and non-operated revenues on behalf of WHR II and bills and receives joint interest billings. In addition, WildHorse pays for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse and WHR II was executed. As part of the agreement, shared WildHorse costs are allocated between WildHorse and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarters capital expenditures and number of operated wells. Company specific costs are billed directly to the appropriate entity. As a result of these agreements, WildHorse received net payments of $4.4 million from WHR II during 2013. WildHorse owed WHR II $2.4 million as of December 31, 2013. | ||||||||||
Omnibus Agreement | ||||||||||
Cinco Group Transition Service Agreements | ||||||||||
On December 14, 2011, in connection with the closing of MEMP’s initial public offering, MRD LLC entered into an omnibus agreement with MEMP and its general partner. We succeeded to all of MRD LLC’s duties and obligations under the omnibus agreement. | ||||||||||
MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties can be smoothly transitioned. The term of these agreements are from October 1, 2013 through February 28, 2014. MEMP expects to pay transition service fees of approximately $0.8 million in the aggregate under these agreements. | ||||||||||
Pursuant to the omnibus agreement, MEMP is required to reimburse us for all expenses incurred by us (or payments made on MEMP’s behalf) in conjunction with our provision of general and administrative services to MEMP, including, but not limited to, public company expenses and an allocated portion of the salary and benefits of the executive officers of MEMP’s general partner and our other employees who perform services for MEMP or on MEMP’s behalf. MEMP is also obligated to reimburse us for insurance coverage expenses we incur with respect to MEMP’s business and operations and with respect to director and officer liability coverage for the officers and directors of MEMP’s general partner. | ||||||||||
Other | ||||||||||
Beta Management Agreement | ||||||||||
Effective March 1, 2012, BlueStone entered into an agreement with CH4 Energy III, LLC, an NGP controlled entity, to sell an undivided 25% interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $7.0 million, which exceeded the net book value of the properties sold by $6.4 million. Due to common control considerations, the $6.4 million was recognized in the equity statement as a contribution. The transaction closed on July 13, 2012. | ||||||||||
On December 12, 2012, MRD LLC entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC pursuant to which MRD LLC agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with a subsidiary of MEMP, in exchange for an annual management fee. We succeeded to this management agreement and we will receive approximately $0.4 million from MEMP annually under that agreement. | ||||||||||
A company affiliated with one of the Classic’s employees provided certain land-related services to Classic. Classic paid approximately $1.0 million to this company for these services in 2012. | ||||||||||
Services Agreement | ||||||||||
Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 was approximately $0.4 million. There were no fees for the year ended December 31, 2013. | ||||||||||
In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company will provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we will pay a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits. | ||||||||||
During 2012, the previous owners received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties. | ||||||||||
WHR Management Company may only terminate the services agreement by providing 90-days prior written notice to us after the six-month anniversary of the date of the agreement. We may terminate the services agreement at any time by providing written notice to WHR Management Company. The services agreement may only be assigned by either party with the other party’s consent. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WildHorse Resources II, LLC. | ||||||||||
During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas. | ||||||||||
Gas Processing Agreement | ||||||||||
See Note 3 for additional information regarding the divestiture of certain interests in oil and gas properties offshore Louisiana that the previous owners sold during 2012 to an NGP controlled entity. | ||||||||||
On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco, through its subsidiary MRD Midstream LLC, owns a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by WildHorse Resources in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. WildHorse Resources will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, WildHorse Resources will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015. | ||||||||||
Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement | ||||||||||
On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. | ||||||||||
On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. |
Business_Segment_Data
Business Segment Data | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||
Business Segment Data | ' | ' | ||||||||||||||||||||||||||||||||
Note 14. Business Segment Data | Note 13. Business Segment Data | |||||||||||||||||||||||||||||||||
Our reportable business segments are organized in a manner that reflects how management manages those business activities. | Our reportable business segments are organized in a manner that reflects how management manages those business activities. | |||||||||||||||||||||||||||||||||
We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our reportable business segments are as follows: | We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our reportable business segments are as follows: | |||||||||||||||||||||||||||||||||
• | MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | • | MRD—reflects the combined operations of Memorial Resource, WildHorse, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating, and MEMP GP. | |||||||||||||||||||||||||||||||
• | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | • | MEMP—reflects the combined operations of MEMP, including the previous owners and any dropdown transactions between MEMP and other Memorial Resource subsidiaries. See Note 1 for additional information regarding dropdown transactions between MEMP and other Memorial Resource subsidiaries. | |||||||||||||||||||||||||||||||
We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items. | We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived assets; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of assets; unit-based compensation expenses; exploration costs; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items. | |||||||||||||||||||||||||||||||||
Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available. | Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available. | |||||||||||||||||||||||||||||||||
Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions. | Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions. | |||||||||||||||||||||||||||||||||
In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method. | In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method. | |||||||||||||||||||||||||||||||||
The following table presents selected business segment information for the periods indicated (in thousands): | The following table presents selected business segment information for the periods indicated (in thousands): | |||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||
Adjustments & | Combined | Adjustments & | and | |||||||||||||||||||||||||||||||
Eliminations | Totals | Eliminations | Combined | |||||||||||||||||||||||||||||||
Total revenues: | Totals | |||||||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | $ | 301,492 | $ | 371,530 | $ | (137 | ) | $ | 672,885 | Total revenues: | ||||||||||||||||||||||||
Nine months ended September 30, 2013 | 171,361 | 251,516 | (136 | ) | 422,741 | Year ended December 31, 2013 | $ | 231,558 | $ | 343,616 | $ | (151 | ) | $ | 575,023 | |||||||||||||||||||
Adjusted EBITDA: (1) | Year ended December 31, 2012 | 138,814 | 258,423 | (369 | ) | 396,868 | ||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | 247,335 | 218,842 | (18,912 | ) | 447,265 | Adjusted EBITDA: | ||||||||||||||||||||||||||||
Nine months ended September 30, 2013 | 153,679 | 157,160 | (19,554 | ) | 291,285 | Year ended December 31, 2013(1) | 197,903 | 222,185 | (25,232 | ) | 394,856 | |||||||||||||||||||||||
Segment assets: (2) | Year ended December 31, 2012(1) | 131,702 | 179,334 | (23,447 | ) | 287,589 | ||||||||||||||||||||||||||||
As of September 30, 2014 | 1,232,146 | 2,749,452 | 40,069 | 4,021,667 | Segment assets:(2) | |||||||||||||||||||||||||||||
As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | |||||||||||||||||||||||
Total cash expenditures for additions to long-lived assets: | As of December 31, 2012 | 1,102,406 | 1,489,404 | (132,506 | ) | 2,459,304 | ||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | (276,982 | ) | (1,273,157 | ) | — | (1,550,139 | ) | Total expenditures for additions to long-lived assets: | ||||||||||||||||||||||||||
Nine months ended September 30, 2013 | (198,220 | ) | (165,403 | ) | — | (363,623 | ) | Year ended December 31, 2013 | 267,870 | 200,577 | — | 468,447 | ||||||||||||||||||||||
Year ended December 31, 2012 | 249,526 | 387,160 | — | 636,686 | ||||||||||||||||||||||||||||||
-1 | Adjustments and eliminations for the nine months ended September 30, 2014 and 2013 include amounts related to the MRD’s Segment equity investments in the MEMP Segment as well as the elimination of $6.1 million of cash distributions that MEMP paid MRD for the nine months ended September 30, 2014, and $19.1 million of cash distributions that MEMP paid MRD LLC for the nine months ended September 30, 2013, related to MRD LLC’s partnership interests in MEMP. | |||||||||||||||||||||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD’s Segment equity investments in the MEMP Segment. The adjustment at September 30, 2014 and December 31, 2013 also includes $47.3 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | -1 | Adjustments and eliminations for the years ended December 31, 2013 and 2012 include amounts related to the MRD’s Segment equity investments in the MEMP Segment as well the elimination of $26.0 million and $19.3 million of cash distributions that MEMP paid Memorial Resource for the years ended December 31, 2013 and 2012, respectively, related to Memorial Resource’s partnership interests in MEMP. | |||||||||||||||||||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD’s Segment equity investments in the MEMP Segment. The adjustment at December 31, 2013 also includes $49.9 million related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | |||||||||||||||||||||||||||||||||
Calculation of Reportable Segments’ Adjusted EBITDA | ||||||||||||||||||||||||||||||||||
Calculation of Reportable Segments’ Adjusted EBITDA | ||||||||||||||||||||||||||||||||||
For the Nine Months | ||||||||||||||||||||||||||||||||||
Ended September 30, 2014 | For the Year Ended December 31, 2013 | |||||||||||||||||||||||||||||||||
MRD | MEMP | Combined | MRD | MEMP | Combined | |||||||||||||||||||||||||||||
Totals | Totals | |||||||||||||||||||||||||||||||||
(In thousands) | (in thousands) | |||||||||||||||||||||||||||||||||
Net income (loss) | $ | (930,149 | ) | $ | (45,037 | ) | $ | (975,186 | ) | Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 102,511 | ||||||||||||||||||
Interest expense, net | 44,355 | 60,573 | 104,928 | Interest expense, net | 27,349 | 41,901 | 69,250 | |||||||||||||||||||||||||||
Loss on extinguishment of debt | 37,248 | — | 37,248 | Income tax expense (benefit) | 1,311 | 308 | 1,619 | |||||||||||||||||||||||||||
Income tax expense (benefit) | 14,323 | 75 | 14,398 | DD&A | 87,043 | 97,269 | 184,312 | |||||||||||||||||||||||||||
DD&A | 107,496 | 105,830 | 213,326 | Impairment of proved oil and natural gas properties | 2,527 | 54,362 | 56,889 | |||||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 67,181 | 67,181 | Accretion of AROs | 728 | 4,853 | 5,581 | |||||||||||||||||||||||||||
Accretion of AROs | 495 | 4,106 | 4,601 | (Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | (29,294 | ) | ||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (17,130 | ) | 28,710 | 11,580 | Cash settlements received on commodity derivative instruments | 12,240 | 19,879 | 32,119 | ||||||||||||||||||||||||||
Cash settlements received (paid) on commodity derivative instruments | (4,930 | ) | (14,999 | ) | (19,929 | ) | Gain on sale of properties | (82,773 | ) | (2,848 | ) | (85,621 | ) | |||||||||||||||||||||
(Gain) loss on sale of properties | 3,057 | — | 3,057 | Acquisition related costs | 1,584 | 6,729 | 8,313 | |||||||||||||||||||||||||||
Acquisition related costs | 1,568 | 3,912 | 5,480 | Incentive unit compensation expense | 43,279 | 3,558 | 46,837 | |||||||||||||||||||||||||||
Incentive-based compensation expense | 970,877 | 5,387 | 976,264 | Non-cash compensation expense | — | 1,057 | 1,057 | |||||||||||||||||||||||||||
Exploration costs | 1,213 | 252 | 1,465 | Exploration costs | 1,226 | 1,130 | 2,356 | |||||||||||||||||||||||||||
Provision for environmental remediation | — | 2,852 | 2,852 | Equity (income) loss from MEMP | (1,847 | ) | — | (1,847 | ) | |||||||||||||||||||||||||
Non-cash equity (income) loss from MEMP | 12,844 | — | 12,844 | Cash distributions from MEMP | 26,006 | — | 26,006 | |||||||||||||||||||||||||||
Cash distributions from MEMP | 6,068 | — | 6,068 | |||||||||||||||||||||||||||||||
Adjusted EBITDA | $ | 197,903 | $ | 222,185 | $ | 420,088 | ||||||||||||||||||||||||||||
Adjusted EBITDA | $ | 247,335 | $ | 218,842 | $ | 466,177 | ||||||||||||||||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||||||||||||||||||||
For the Nine Months | MRD | MEMP | Combined | |||||||||||||||||||||||||||||||
Ended September 30, 2013 | Totals | |||||||||||||||||||||||||||||||||
MRD | MEMP | Combined | (in thousands) | |||||||||||||||||||||||||||||||
Totals | Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | 31,877 | ||||||||||||||||||||||||||
(In thousands) | Interest expense, net | 12,802 | 20,436 | 33,238 | ||||||||||||||||||||||||||||||
Net income (loss) | $ | 114,628 | $ | 9,359 | $ | 123,987 | Income tax expense (benefit) | (178 | ) | 285 | 107 | |||||||||||||||||||||||
Interest expense, net | 15,947 | 26,047 | 41,994 | DD&A | 62,636 | 76,036 | 138,672 | |||||||||||||||||||||||||||
Income tax expense (benefit) | 1,147 | 285 | 1,432 | Impairment of proved oil and natural gas properties | 18,339 | 10,532 | 28,871 | |||||||||||||||||||||||||||
DD&A | 62,605 | 69,723 | 132,328 | Accretion of AROs | 632 | 4,377 | 5,009 | |||||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 50,310 | 50,310 | (Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | (34,905 | ) | ||||||||||||||||||||||||
Accretion of AROs | 547 | 3,469 | 4,016 | Cash settlements received on commodity derivative instruments | 30,188 | 44,111 | 74,299 | |||||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (8,361 | ) | (21,195 | ) | (29,556 | ) | Gain on sale of properties | (2 | ) | (9,759 | ) | (9,761 | ) | |||||||||||||||||||||
Cash settlements received (paid) on commodity derivative instruments | 9,125 | 14,081 | 23,206 | Acquisition related costs | 403 | 4,135 | 4,538 | |||||||||||||||||||||||||||
(Gain) loss on sale of properties | (83,370 | ) | (2,848 | ) | (86,218 | ) | Incentive unit compensation expense | 9,510 | 1,423 | 10,933 | ||||||||||||||||||||||||
Acquisition related costs | 1,651 | 3,422 | 5,073 | Exploration costs | 7,337 | 2,463 | 9,800 | |||||||||||||||||||||||||||
Incentive-based compensation expense | 19,069 | 2,322 | 21,391 | Amortization of investment premium | — | 194 | 194 | |||||||||||||||||||||||||||
Non-cash compensation expense | — | 1,057 | 1,057 | Non-cash equity (income) loss from MEMP | (696 | ) | — | (696 | ) | |||||||||||||||||||||||||
Exploration costs | 1,137 | 1,128 | 2,265 | Cash distributions from MEMP | 19,263 | — | 19,263 | |||||||||||||||||||||||||||
Non-cash equity (income) loss from MEMP | 454 | — | 454 | |||||||||||||||||||||||||||||||
Cash distributions from MEMP | 19,100 | — | 19,100 | Adjusted EBITDA | $ | 132,105 | $ | 179,334 | $ | 311,439 | ||||||||||||||||||||||||
Adjusted EBITDA | $ | 153,679 | $ | 157,160 | $ | 310,839 | ||||||||||||||||||||||||||||
The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated. | ||||||||||||||||||||||||||||||||||
The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands). | ||||||||||||||||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||
For the Nine Months | (in thousands) | |||||||||||||||||||||||||||||||||
Ended September 30, | Total Reportable Segments’ Adjusted EBITDA | $ | 420,088 | $ | 311,439 | |||||||||||||||||||||||||||||
2014 | 2013 | Adjustment to reconcile Adjusted EBITDA to net income (loss): | ||||||||||||||||||||||||||||||||
Total Reportable Segments’ Adjusted EBITDA | $ | 466,177 | $ | 310,839 | Interest expense, net | (69,250 | ) | (33,238 | ) | |||||||||||||||||||||||||
Adjustments to reconcile Adjusted EBITDA to net income (loss): | Income tax benefit (expense) | (1,619 | ) | (107 | ) | |||||||||||||||||||||||||||||
Interest expense, net | (104,928 | ) | (41,994 | ) | DD&A | (184,717 | ) | (138,672 | ) | |||||||||||||||||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | Impairment of proved oil and natural gas properties | (6,600 | ) | (28,871 | ) | ||||||||||||||||||||||||||
Income tax benefit (expense) | (14,398 | ) | (1,432 | ) | Accretion of AROs | (5,581 | ) | (5,009 | ) | |||||||||||||||||||||||||
DD&A | (215,906 | ) | (132,328 | ) | Gains (losses) on commodity derivative instruments | 29,294 | 34,905 | |||||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | (67,181 | ) | (21 | ) | Cash settlements received on commodity derivative instruments | (32,119 | ) | (74,299 | ) | |||||||||||||||||||||||||
Accretion of AROs | (4,601 | ) | (4,016 | ) | Gain on sale of properties | 85,621 | 9,761 | |||||||||||||||||||||||||||
Gains (losses) on commodity derivative instruments | (11,580 | ) | 29,556 | Acquisition related costs | (8,313 | ) | (4,538 | ) | ||||||||||||||||||||||||||
Cash settlements paid (received) on commodity derivative instruments | 19,929 | (23,206 | ) | Incentive unit compensation expense | (46,837 | ) | (10,933 | ) | ||||||||||||||||||||||||||
Gain (loss) on sale of properties | (3,057 | ) | 86,218 | Non-cash compensation expense | (1,057 | ) | — | |||||||||||||||||||||||||||
Acquisition related costs | (5,480 | ) | (5,073 | ) | Exploration costs | (2,356 | ) | (9,800 | ) | |||||||||||||||||||||||||
Incentive-based compensation expense) | (976,264 | ) | (21,391 | ) | Amortization of investment premium | — | (194 | ) | ||||||||||||||||||||||||||
Non-cash compensation expense | — | (1,057 | ) | Cash distributions from MEMP | (26,006 | ) | (19,263 | ) | ||||||||||||||||||||||||||
Exploration costs | (1,465 | ) | (2,265 | ) | Non-cash equity (income) loss from WHT & MRD Assets | 784 | (4,184 | ) | ||||||||||||||||||||||||||
Provision for environmental remediation | (2,852 | ) | — | |||||||||||||||||||||||||||||||
Cash distributions from MEMP | (6,068 | ) | (19,100 | ) | Net income (loss) | $ | 151,332 | $ | 26,997 | |||||||||||||||||||||||||
Other non-cash equity (income) loss) | — | (430 | ) | |||||||||||||||||||||||||||||||
Net income (loss) | $ | (964,922 | ) | $ | 174,300 | Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated: | ||||||||||||||||||||||||||||
Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): | For the Year Ended December 31, 2013 | |||||||||||||||||||||||||||||||||
MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||||||
Adjustments & | and Combined | |||||||||||||||||||||||||||||||||
For the Nine Months Ended September 30, 2014 | Eliminations | Totals | ||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | (in thousands) | ||||||||||||||||||||||||||||||
Adjustments & | Combined | Revenues: | ||||||||||||||||||||||||||||||||
Eliminations | Totals | Oil & natural gas sales | $ | 230,751 | $ | 341,197 | $ | — | $ | 571,948 | ||||||||||||||||||||||||
Revenues: | Other revenues | 807 | 2,419 | (151 | ) | 3,075 | ||||||||||||||||||||||||||||
Oil & natural gas sales | $ | 300,931 | $ | 368,370 | $ | — | $ | 669,301 | ||||||||||||||||||||||||||
Other revenues | 561 | 3,160 | (137 | ) | 3,584 | Total revenues | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||||||||||||||
Total revenues | 301,492 | 371,530 | (137 | ) | 672,885 | Costs and expenses: | ||||||||||||||||||||||||||||
Lease operating | 25,006 | 88,893 | (259 | ) | 113,640 | |||||||||||||||||||||||||||||
Costs and expenses: | Pipeline operating | — | 1,835 | — | 1,835 | |||||||||||||||||||||||||||||
Lease operating | 18,657 | 93,367 | (137 | ) | 111,887 | Exploration | 1,226 | 1,130 | — | 2,356 | ||||||||||||||||||||||||
Pipeline operating | — | 1,596 | — | 1,596 | Production and ad valorem taxes | 9,362 | 17,784 | — | 27,146 | |||||||||||||||||||||||||
Exploration | 1,213 | 252 | — | 1,465 | Depreciation, depletion, and amortization | 87,043 | 97,269 | 405 | 184,717 | |||||||||||||||||||||||||
Production and ad valorem taxes | 10,494 | 23,129 | — | 33,623 | Impairment of proved oil and natural gas properties | 2,527 | 54,362 | (50,289 | ) | 6,600 | ||||||||||||||||||||||||
Depreciation, depletion, and amortization | 107,496 | 105,830 | 2,580 | 215,906 | General and administrative | 81,758 | 43,495 | 105 | 125,358 | |||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 67,181 | — | 67,181 | Accretion of asset retirement obligations | 728 | 4,853 | — | 5,581 | |||||||||||||||||||||||||
Incentive unit compensation expense | 969,390 | — | — | 969,390 | (Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | — | (29,294 | ) | ||||||||||||||||||||||
General and administrative | 29,301 | 31,760 | — | 61,061 | (Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | — | (85,621 | ) | ||||||||||||||||||||||
Accretion of asset retirement obligations | 495 | 4,106 | — | 4,601 | Other, net | 2 | 647 | — | 649 | |||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (17,130 | ) | 28,710 | — | 11,580 | |||||||||||||||||||||||||||||
(Gain) loss on sale of properties | 3,057 | — | — | 3,057 | Total costs and expenses | 121,866 | 281,139 | (50,038 | ) | 352,967 | ||||||||||||||||||||||||
Other, net | — | (12 | ) | — | (12 | ) | ||||||||||||||||||||||||||||
Operating income | 109,692 | 62,477 | 49,887 | 222,056 | ||||||||||||||||||||||||||||||
Total costs and expenses | 1,122,973 | 355,919 | 2,443 | 1,481,335 | Other income (expense): | |||||||||||||||||||||||||||||
Interest expense, net | (27,349 | ) | (41,901 | ) | — | (69,250 | ) | |||||||||||||||||||||||||||
Operating income (loss) | (821,481 | ) | 15,611 | (2,580 | ) | (808,450 | ) | Earnings from equity investments | 1,066 | — | (1,066 | ) | — | |||||||||||||||||||||
Other income (expense): | Other, net | 145 | — | — | 145 | |||||||||||||||||||||||||||||
Interest expense, net | (44,355 | ) | (60,573 | ) | — | (104,928 | ) | |||||||||||||||||||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | (37,248 | ) | Total other income (expense) | (26,138 | ) | (41,901 | ) | (1,066 | ) | (69,105 | ) | |||||||||||||||||||
Earnings from equity investments | (12,844 | ) | — | 12,844 | — | |||||||||||||||||||||||||||||
Other, net | 102 | — | — | 102 | Income before income taxes | 83,554 | 20,576 | 48,821 | 152,951 | |||||||||||||||||||||||||
Income tax benefit (expense) | (1,311 | ) | (308 | ) | — | (1,619 | ) | |||||||||||||||||||||||||||
Total other income (expense) | (94,345 | ) | (60,573 | ) | 12,844 | (142,074 | ) | |||||||||||||||||||||||||||
Net income | $ | 82,243 | $ | 20,268 | $ | 48,821 | $ | 151,332 | ||||||||||||||||||||||||||
Income (loss) before income taxes | (915,826 | ) | (44,962 | ) | 10,264 | (950,524 | ) | |||||||||||||||||||||||||||
Income tax benefit (expense) | (14,323 | ) | (75 | ) | — | (14,398 | ) | |||||||||||||||||||||||||||
-1 | During the year ended December 31, 2013 the MEMP Segment recorded impairments of $50.3 million related to certain properties in East Texas. Both the MRD and MEMP Segments own properties in the same field and on a consolidated basis the expected future cash flows exceeded the carrying value, and therefore, did not result in an impairment on a consolidated basis. | |||||||||||||||||||||||||||||||||
Net income (loss) | $ | (930,149 | ) | $ | (45,037 | ) | $ | 10,264 | $ | (964,922 | ) | |||||||||||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||||||||||||||||||||
MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | Adjustments & | and Combined | ||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | Eliminations | Totals | |||||||||||||||||||||||||||||
Adjustments & | Combined | (in thousands) | ||||||||||||||||||||||||||||||||
Eliminations | Totals | Revenues: | ||||||||||||||||||||||||||||||||
Revenues: | Oil & natural gas sales | $ | 138,032 | $ | 255,608 | $ | (9 | ) | $ | 393,631 | ||||||||||||||||||||||||
Oil & natural gas sales | $ | 171,013 | $ | 249,844 | $ | — | $ | 420,857 | Other revenues | 782 | 2,815 | (360 | ) | 3,237 | ||||||||||||||||||||
Other revenues | 348 | 1,672 | (136 | ) | 1,884 | |||||||||||||||||||||||||||||
Total revenues | 138,814 | 258,423 | (369 | ) | 396,868 | |||||||||||||||||||||||||||||
Total revenues | 171,361 | 251,516 | (136 | ) | 422,741 | |||||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||
Costs and expenses: | Lease operating | 24,438 | 80,116 | (800 | ) | 103,754 | ||||||||||||||||||||||||||||
Lease operating | 17,065 | 64,922 | (241 | ) | 81,746 | Pipeline operating | — | 2,114 | — | 2,114 | ||||||||||||||||||||||||
Pipeline operating | — | 1,343 | — | 1,343 | Exploration | 7,337 | 2,463 | — | 9,800 | |||||||||||||||||||||||||
Exploration | 1,137 | 1,128 | — | 2,265 | Production and ad valorem taxes | 7,576 | 16,048 | — | 23,624 | |||||||||||||||||||||||||
Production and ad valorem taxes | 8,563 | 14,915 | — | 23,478 | Depreciation, depletion, and amortization | 62,636 | 76,036 | — | 138,672 | |||||||||||||||||||||||||
Depreciation, depletion, and amortization | 62,605 | 69,723 | — | 132,328 | Impairment of proved oil and natural gas properties | 18,339 | 10,532 | — | 28,871 | |||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 50,310 | (50,289 | ) | 21 | General and administrative | 38,414 | 30,342 | 431 | 69,187 | ||||||||||||||||||||||||
Incentive unit compensation expense | 19,069 | — | — | 19,069 | Accretion of asset retirement obligations | 632 | 4,377 | — | 5,009 | |||||||||||||||||||||||||
General and administrative | 22,466 | 33,411 | 105 | 55,982 | (Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | — | (34,905 | ) | ||||||||||||||||||||||
Accretion of asset retirement obligations | 547 | 3,469 | — | 4,016 | (Gain) loss on sale of properties | (2 | ) | (9,759 | ) | — | (9,761 | ) | ||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (8,361 | ) | (21,195 | ) | — | (29,556 | ) | Other, net | 364 | 138 | — | 502 | ||||||||||||||||||||||
(Gain) loss on sale of properties | (83,370 | ) | (2,848 | ) | — | (86,218 | ) | |||||||||||||||||||||||||||
Other, net | (25 | ) | 647 | — | 622 | Total costs and expenses | 146,246 | 190,990 | (369 | ) | 336,867 | |||||||||||||||||||||||
Total costs and expenses | 39,696 | 215,825 | (50,425 | ) | 205,096 | Operating income | (7,432 | ) | 67,433 | — | 60,001 | |||||||||||||||||||||||
Other income (expense): | ||||||||||||||||||||||||||||||||||
Operating income (loss) | 131,665 | 35,691 | 50,289 | 217,645 | Interest expense, net | (12,802 | ) | (20,436 | ) | — | (33,238 | ) | ||||||||||||||||||||||
Other income (expense): | Amortization of investment premium | — | (194 | ) | — | (194 | ) | |||||||||||||||||||||||||||
Interest expense, net | (15,947 | ) | (26,047 | ) | — | (41,994 | ) | Earnings from equity investments | 4,880 | — | (4,880 | ) | — | |||||||||||||||||||||
Earnings from equity investments | (24 | ) | — | 24 | — | Other, net | 535 | — | — | 535 | ||||||||||||||||||||||||
Other, net | 81 | — | — | 81 | ||||||||||||||||||||||||||||||
Total other income (expense) | (7,387 | ) | (20,630 | ) | (4,880 | ) | (32,897 | ) | ||||||||||||||||||||||||||
Total other income (expense) | (15,890 | ) | (26,047 | ) | 24 | (41,913 | ) | |||||||||||||||||||||||||||
Income before income taxes | (14,819 | ) | 46,803 | (4,880 | ) | 27,104 | ||||||||||||||||||||||||||||
Income before income taxes | 115,775 | 9,644 | 50,313 | 175,732 | Income tax benefit (expense) | 178 | (285 | ) | — | (107 | ) | |||||||||||||||||||||||
Income tax benefit (expense) | (1,147 | ) | (285 | ) | — | (1,432 | ) | |||||||||||||||||||||||||||
Net income | $ | (14,641 | ) | $ | 46,518 | $ | (4,880 | ) | $ | 26,997 | ||||||||||||||||||||||||
Net income (loss) | $ | 114,628 | $ | 9,359 | $ | 50,313 | $ | 174,300 | ||||||||||||||||||||||||||
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Note 15. Commitments and Contingencies | Note 14. Commitments and Contingencies | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Litigation & Environmental | Litigation & Environmental | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. | As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. At December 31, 2012, we had an accrued liability of approximately $0.1 million relating primarily to a matter that has been settled. We did not have an accrued liability at December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014 and December 31, 2013, we had $2.3 million and $0.6 million of environmental reserves recorded on our balance sheets, respectively. During the nine months ended September 30, 2014, MEMP recorded $2.9 million of estimated environmental remediation expenses associated with its Permian and Wyoming oil and gas properties. These expenses are reflected as a component of lease operating expenses on our statement of operations. Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. | Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2013, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Bond for Decommissioning Liabilities Trust Agreement | The following table presents the activity of our environmental reserves for the periods presented: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The trust account is held by Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2014 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment | Amortized | Balance at beginning of period | $ | 1,469 | $ | 1,747 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost | Charged to costs and expenses | — | 193 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Bank Money Market Cash Equivalent | $ | 133,275 | Payments | (892 | ) | (471 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||
Less: Outside working interest owners share | (64,305 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at end of period | $ | 577 | $ | 1,469 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
$ | 68,970 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At December 31, 2013 and 2012, $0.6 million and $1.0 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sinking Fund Trust Agreement | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2015 | $ | 72,450 | REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within California state waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2013, the gross account balance included in restricted investments was approximately $2.3 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $1.0 million at December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2016 | $ | 76,590 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | $ | 78,660 | Supplemental Bond for Decommissioning Liabilities Trust Agreement | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2014, the maximum remaining obligation net to REO’s interest was approximately $9.7 million. | REO assumed an obligation with the Bureau of Ocean Energy Management (“BOEM”) in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase Commitment Assumed | In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2014 | $ | 68,310 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2015 | $ | 72,450 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | June 30, 2016 | $ | 76,590 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase commitment | Total | Remainder | 2015 | 2016 | 2017 | 2018 | Thereafter | December 31, 2016 | $ | 78,660 | ||||||||||||||||||||||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CO2 minimum purchase commitment: | In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2013, the maximum remaining obligation net to REO’s interest was approximately $12.2 million. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated payment obligation | $ | 62,103 | $ | 3,203 | $ | 12,222 | $ | 12,101 | $ | 11,624 | $ | 7,872 | $ | 15,081 | ||||||||||||||||||||||||||||||||||||||||||||
The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2013 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Processing Plant Expansions by Third Party Gatherer | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. The expansion project was complete and fully operational by July 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal 110% of the new facility cost. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand quantity (136,200 MMBtu per day) times $0.26 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.26 per MMBtu. The contract with the Gatherer for the Dubach processing plant was amended effective February 1, 2014 where the payback demand fee for the Dubach processing plant increased from $0.26 to $0.275 cents per MMbtu. | Investment | Amortized | Unrealized | Fair | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost | Gain | Market | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The expansion project was complete and fully operational by mid-December 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal to 110% of the pipeline and infrastructure improvement costs. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand fee times $0.31 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.31 per MMBtu. The monthly demand quantity is 56,750 MMBtu per day from the Dubberly start-up date through one full year thereafter and then increasing to 113,500 MMBtu per day until payout. The contract with the Gatherer for the new high pressure pipeline was amended effective February 1, 2014 where the payback demand fee decreased from $0.31 to $0.275 cents per MMbtu. | (Loss) | Value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Bank Money Market Cash Equivalent | $ | 105,184 | $ | — | $ | 105,184 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of September 30, 2014 were as follows (in thousands): | U.S. Government Treasury Note, maturity of June 30, 2014, and 1.75% coupon | 23,073 | 93 | 23,166 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Less: Outside working interest owners share | (61,884 | ) | (45 | ) | (61,929 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Dubach | Dubberly | $ | 66,373 | $ | 48 | $ | 66,421 | |||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | $ | 3,446 | $ | 1,436 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 13,671 | 11,393 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 13,709 | 11,424 | Processing Plant Expansions by Third Party Gatherer | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | In 2012, WildHorse contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. The expansion project was complete and fully operational by July 2013. WildHorse will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal 110% of the new facility cost. For each month from the commencement date through the month in which the payout date occurs, WildHorse will pay a payback demand fee equal to the monthly demand quantity (136,200 MMBtu per day) times $0.26 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse will pay a payback demand fee of $0.26 per MMBtu. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 57,269 | $ | 46,289 | In 2013, WildHorse contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The expansion project was complete and fully operational by mid-December 2013. WildHorse will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal to 110% of the pipeline and infrastructure improvement costs. For each month from the commencement date through the month in which the payout date occurs, WildHorse will pay a payback demand fee equal to the monthly demand fee times $0.31 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse will pay a payback demand fee of $0.31 per MMBtu. The monthly demand quantity is 56,750 MMBtu per day from the Dubberly start-up date through one full year thereafter and then increasing to 113,500 MMBtu per day until payout. | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Pursuant to the agreement, the Gatherer is obligated to process gas up to the maximum daily quantity of 158,000 MMBtu per day from the commencement date of the Dubach facility expansion through the start-up of the Dubberly pipeline. With the start-up of the Dubberly pipeline, the Gatherer is obligated to process gas up to the maximum daily quantity of 214,750 MMBtu per day through one full year thereafter. From and after the first anniversary of the Dubberly start-up date, the Gatherer is obligated to process gas up to the maximum daily quantity of 271,500 MMbtu per day. WildHorse is obligated to deliver all volumes of gas produced from the dedicated area to the Gatherer up to the maximum daily quantity. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Agreements | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total allowable costs for the Dubach Plant expansion and the Dubberly pipeline (new Facility Costs) cannot exceed $129.0 million. WildHorse expects that total payments by WildHorse to the Gatherer for the new Facility Costs will not exceed 60% of the total payment amounts after contributions made by other owners. Payments made will reduce revenue associated with the production and are reflected in our reserve report. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse’s minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2013 were as follows (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline. See Note 13 for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dubach | Dubberly | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Facility Costs | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | $ | 12,925 | $ | 6,421 | $ | 19,346 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 12,925 | 12,842 | 25,767 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 12,961 | 12,878 | 25,839 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | 12,925 | 12,842 | 25,767 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 10,766 | 10,697 | 21,463 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 62,502 | $ | 55,680 | $ | 118,182 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsequent event. The contract with the Gatherer for the Dubach processing plant was amended effective February 1, 2014 where the payback demand fee for the Dubach processing plant increased from $0.26 to $0.275 cents per MMbtu. Also, the contract with the Gatherer for the new high pressure pipeline was amended effective February 1, 2014 where the payback demand fee decreased from $0.31 to $0.275 cents per MMbtu. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse’s minimum commitments to the Gatherer, before other owner contributions, as of February 1, 2014 were as follows (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dubach | Dubberly | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Facility Costs | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | $ | 12,510 | $ | 5,212 | $ | 17,722 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 13,671 | 11,393 | 25,064 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 13,709 | 11,424 | 25,133 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | 25,064 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | 23,415 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 66,333 | $ | 50,065 | $ | 116,398 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Leases | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
We have leases for offshore Southern California pipeline right-of-way use and office space. We also incur surface rentals related to our business operations. For the years ended December 31, 2013 and 2012, we recognized $8.3 million and $5.0 million, respectively, of rent expense. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lease Obligations | Total | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating leases | 20,325 | 2,389 | 2,546 | 2,583 | 2,718 | 2,783 | 7,306 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Drilling & Compression Services | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
We have entered into drilling and compression services agreements with various terms. Amounts shown in the following table represent our minimum commitments as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Service Agreements | Total | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Drilling services | 20,323 | 20,323 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
Compression services | 7,090 | 7,079 | 11 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse Letter of Credit and Certificate of Deposit | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Standby letters of credit were issued to the Louisiana Office of Conservation and the Railroad Commission of Texas for the account of WildHorse for $1.2 million during 2011. The letters of credit are to insure compliance by WildHorse with regulatory requirements. These letters of credit are collateralized by two Certificates of Deposits; the fair value of the Certificates of Deposits was $0.5 million and $1.2 million at December 31, 2013 and 2012, respectively. The amount of the letter of credit and the Certificates of Deposit is adjusted depending on the requirements of the Office of Conservation. The Certificates of Deposit is classified as a restricted noncurrent asset and is not considered operating cash for the purposes of the statements of cash flows. |
Subsequent_Events
Subsequent Events | 9 Months Ended | 12 Months Ended |
Sep. 30, 2014 | Dec. 31, 2013 | |
Subsequent Events [Abstract] | ' | ' |
Subsequent Events | ' | ' |
Note 16. Subsequent Events | Note 16. Subsequent Events | |
Common Control Transaction | In preparing the consolidated and combined financial statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through April 4, 2014, the date the consolidated and combined financial statements were available for issuance. | |
On October 1, 2014, MRD sold certain oil and natural gas properties in Colorado to MEMP for a purchase price of $15 million, subject to customary post-closing adjustments. The properties are located in Weld County, Colorado in the Wattenberg Field. The properties are 100% non-operated and included interests in 74 gross wells. The transaction had an effective date of October 1, 2014 and was funded with borrowings under MEMP’s revolving credit facility. The transaction was approved by our Board and its audit committee, which is comprised entirely of independent directors. | Common Control Acquisition | |
MRD Revolving Credit Facility | On April 1, 2014, MEMP acquired certain oil and natural gas producing properties in East Texas from WildHorse for a purchase price of $34.0 million, subject to customary purchase price adjustments. This transaction was financed with borrowings under MEMP’s revolving credit facility. The acquired properties primarily represent additional working interests in wells currently owned by MEMP and located primarily in Polk and Tyler Counties in the Double A Field of East Texas, as well as the Sunflower, Segno and Sugar Creek Fields. | |
On October 3, 2014, the borrowing base under our credit facility was increased. For additional information regarding MRD’s revolving credit facility, see Note 8. | 3rd Party Acquisition | |
MEMP Revolving Credit Facility | On March 25, 2014, MEMP acquired certain oil and gas producing properties in the Eagle Ford trend from Alta Mesa Holdings, LP for a purchase price of $173 million, subject to customary purchase price adjustments. The acquired properties are located in Karnes County in the core of the Eagle Ford oil window. The properties are 100% non-operated. In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. MEMP acquired all of the seller’s working and net revenue interest in the producing wells subject to a net profits interest retained by the seller that reduces annually and terminates after three years. At the end of three years, MEMP will own all of the seller’s interests in the currently producing wells. | |
On October 10, 2014, the borrowing base under the MEMP credit facility was redetermined and increased. For additional information regarding MEMP’s revolving credit facility, see Note 8. | NGPCIF NPI Acquisition | |
Terryville Mineral & Royalty Partners LP | See Notes 1 and 12 for further information regarding WildHorse’s acquisition of NGPCIF NPI. | |
On November 4, 2014, the Company’s wholly-owned subsidiary, Terryville Mineral & Royalty Partners LP (“TRVL”), filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering of common units representing limited partner interests. In connection with the closing of the proposed offering, the Company will contribute to TRVL certain overriding royalty interests in approximately 27,000 gross acres in the Terryville Complex in exchange for limited partner interests in TRVL. The royalty interests will entitle TRVL to receive 7% of gross revenues from production within such acreage on all of the Company’s existing horizontal producing wells and future wells completed by the Company. TRVL intends to distribute the net proceeds from the proposed offering to the Company. A registration statement relating to these securities has been filed with the SEC but has not yet become effective. These securities may not be sold nor may any offers to buy be accepted prior to the time the registration statement becomes effective, and this prospectus does not constitute an offer to sell or a solicitation of any offers to buy these securities. | Recently Formed Subsidiaries | |
MRD Royalty LLC (“MRD Royalty”) and MRD Midstream LLC (“MRD Midstream”) were formed by Memorial Resource in 2014. MRD Royalty owns certain immaterial leasehold interests and overriding royalty interests in Texas and Montana. MRD Midstream owns an indirect interest in certain immaterial midstream assets in North Louisiana. Following the completion of the Offering, Memorial Resource will retain its ownership interest in MRD Royalty and MRD Midstream. | ||
Gas Processing Agreement | ||
On March 17, 2014, WildHorse entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream owns a noncontrolling interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by WildHorse in the state of Louisiana. The agreement has a 15-year primary term, subject to one year extensions at either party’s election. WildHorse will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, WildHorse will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015. |
Noncontrolling_Interests
Noncontrolling Interests | 12 Months Ended |
Dec. 31, 2013 | |
Noncontrolling Interest [Abstract] | ' |
Noncontrolling Interests | ' |
Note 9. Noncontrolling Interests | |
Noncontrolling interests is the portion of equity ownership in our majority-owned subsidiaries not attributable to us and primarily consists of the equity interests held by: (i) the limited partners of MEMP, excluding units held by MRD; (ii) a third party investor in the San Pedro Bay Pipeline Company; and (iii) certain current or former key employees of certain of our subsidiaries. | |
Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to Memorial Resource. | |
Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT. On October 8, 2013, MEMP sold 16,675,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering were used to repay a portion of outstanding borrowings under the MEMP revolving credit facility. In December 2012, MEMP sold 11,975,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $194.3 million. The net proceeds from this equity offering partially funded MEMP’s December 2012 acquisition. | |
On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to Memorial Resource and all incentive units held were forfeited. See Note 11 for further information. | |
In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a transition services agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity. | |
On November 1, 2013, Memorial Resource purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. See Note 11 for further information. | |
In connection with the purchase of the remaining noncontrolling interests in Black Diamond, all of Black Diamond’s employees resigned and certain of them became members of DBD Partners, LLC (“DBD”), a Delaware limited liability company controlled by the former management team of Black Diamond. Effective November 1, 2013, DBD entered into a transition services agreement with Black Diamond, whereby DBD would manager the operations of Black Diamond for up to a 12 month period of time. DBD is an unrelated entity. |
Defined_Contribution_Plans
Defined Contribution Plans | 12 Months Ended |
Dec. 31, 2013 | |
Postemployment Benefits [Abstract] | ' |
Defined Contribution Plans | ' |
Note 15. Defined Contribution Plans | |
Memorial Resource sponsors a defined contribution plan for the benefit of substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Memorial Resource makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. The plan received employer contributions of approximately $0.9 million and $0.4 million in for the years ended December 31, 2013 and 2012, respectively. | |
Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the Memorial Resource subsidiary (Beta Operating) that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. The plan received employer contributions of approximately $0.6 million and $0.5 million in 2013 and 2012, respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for both the years ended December 31, 2013 and 2012, respectively. | |
WildHorse, Tanos, BlueStone, Classic and Black Diamond also sponsor defined contribution plans for the benefit their eligible employees. Matching employer contributions of approximately $0.5 million and $0.6 million were made to these other plans in 2013 and 2012, respectively. | |
Crown and Stanolind also made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million were made to these plans in both 2013 and 2012. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations. |
Supplemental_Oil_and_Gas_Infor
Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Extractive Industries [Abstract] | ' | ||||||||||||||||
Supplemental Oil and Gas Information (Unaudited) | ' | ||||||||||||||||
Note 17. Supplemental Oil and Gas Information (Unaudited) | |||||||||||||||||
Capitalized Costs Relating to Oil and Natural Gas Producing Activities | |||||||||||||||||
The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
MRD Segment: | |||||||||||||||||
Evaluated oil and natural gas properties | $ | 1,226,417 | $ | 1,052,219 | |||||||||||||
Unevaluated oil and natural gas properties | 46,413 | 26,589 | |||||||||||||||
Accumulated depletion, depreciation, and amortization | (256,629 | ) | (202,581 | ) | |||||||||||||
Subtotal | $ | 1,016,201 | $ | 876,227 | |||||||||||||
MEMP Segment: | |||||||||||||||||
Evaluated oil and natural gas properties(1) | $ | 1,758,953 | $ | 1,545,402 | |||||||||||||
Unevaluated oil and natural gas properties | — | 5,004 | |||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | (416,617 | ) | (265,710 | ) | |||||||||||||
Subtotal | $ | 1,342,336 | $ | 1,284,696 | |||||||||||||
Eliminations: | |||||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | $ | 49,884 | $ | — | |||||||||||||
Consolidated: | |||||||||||||||||
Evaluated oil and natural gas properties(1) | $ | 2,985,370 | $ | 2,597,621 | |||||||||||||
Unevaluated oil and natural gas properties | 46,413 | 31,593 | |||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | (623,362 | ) | (468,291 | ) | |||||||||||||
Total | $ | 2,408,421 | $ | 2,160,923 | |||||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | ||||||||||||||||
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities | |||||||||||||||||
Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
MRD Segment: | |||||||||||||||||
Property acquisition costs, proved | $ | 56,108 | $ | 87,857 | |||||||||||||
Property acquisition costs, unproved | 19,975 | 5,293 | |||||||||||||||
Exploration and extension well costs | 13,313 | 212 | |||||||||||||||
Development | 210,440 | 135,951 | |||||||||||||||
Subtotal | $ | 299,836 | $ | 229,313 | |||||||||||||
MEMP Segment: | |||||||||||||||||
Property acquisition costs, proved | $ | 37,786 | $ | 278,246 | |||||||||||||
Property acquisition costs, unproved | — | — | |||||||||||||||
Exploration and extension well costs | — | 42,430 | |||||||||||||||
Development(1) | 145,830 | 62,472 | |||||||||||||||
Subtotal | $ | 183,616 | $ | 383,148 | |||||||||||||
Consolidated: | |||||||||||||||||
Property acquisition costs, proved | $ | 93,894 | $ | 366,103 | |||||||||||||
Property acquisition costs, unproved | 19,975 | 5,293 | |||||||||||||||
Exploration and extension well costs | 13,313 | 42,642 | |||||||||||||||
Development(1) | 356,270 | 198,423 | |||||||||||||||
Total | $ | 483,452 | $ | 612,461 | |||||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | ||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves | |||||||||||||||||
As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time, and therefore, may cause significant variability in cash flows from year to year as prices change. | |||||||||||||||||
Oil and Natural Gas Reserves | |||||||||||||||||
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. | |||||||||||||||||
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. | |||||||||||||||||
We engaged NSAI to prepare reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2013. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. | |||||||||||||||||
The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Oil ($/Bbl): | |||||||||||||||||
Spot(1) | $ | 93.42 | $ | 91.33 | |||||||||||||
NGL ($/Bbl): | |||||||||||||||||
Spot(1) | $ | 93.42 | $ | 91.75 | |||||||||||||
Natural Gas ($/MMbtu): | |||||||||||||||||
Spot(2) | $ | 3.67 | $ | 2.75 | |||||||||||||
-1 | The unweighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential. | ||||||||||||||||
-2 | The unweighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. | ||||||||||||||||
MRD Segment | |||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2013 and 2012, respectively: | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 11,953 | 739,378 | 41,466 | 1,059,895 | |||||||||||||
Extensions and discoveries | 1,794 | 149,974 | 8,319 | 210,652 | |||||||||||||
Purchase of minerals in place | 211 | 31,815 | 1,017 | 39,183 | |||||||||||||
Production | (665 | ) | (34,092 | ) | (1,457 | ) | (46,819 | ) | |||||||||
Sales of minerals in place | (599 | ) | (14,137 | ) | (1,573 | ) | (27,169 | ) | |||||||||
Revision of previous estimates | (1,383 | ) | (70,684 | ) | (5,196 | ) | (110,165 | ) | |||||||||
End of year(1) | 11,311 | 802,254 | 42,576 | 1,125,577 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 3,082 | 245,449 | 12,321 | 337,869 | |||||||||||||
End of year | 3,402 | 263,797 | 13,904 | 367,641 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 8,871 | 493,929 | 29,145 | 722,026 | |||||||||||||
End of year | 7,909 | 538,457 | 28,672 | 757,936 | |||||||||||||
-1 | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 10,834 | 929,335 | 53,031 | 1,312,533 | |||||||||||||
Extensions and discoveries | 689 | 42,019 | 2,778 | 62,819 | |||||||||||||
Purchase of minerals in place | 1,100 | 28,115 | 1,879 | 45,987 | |||||||||||||
Production | (369 | ) | (24,131 | ) | (898 | ) | (31,731 | ) | |||||||||
Sales of minerals in place | (4 | ) | (728 | ) | — | (752 | ) | ||||||||||
Revision of previous estimates | (297 | ) | (235,232 | ) | (15,324 | ) | (328,961 | ) | |||||||||
End of year(1) | 11,953 | 739,378 | 41,466 | 1,059,895 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,107 | 191,557 | 7,644 | 250,073 | |||||||||||||
End of year | 3,082 | 245,449 | 12,321 | 337,869 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 8,727 | 737,778 | 45,387 | 1,062,460 | |||||||||||||
End of year | 8,871 | 493,929 | 29,145 | 722,026 | |||||||||||||
-1 | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||||||||||||||
Noteworthy amounts included in the categories of proved reserve changes for the years ended December 31, 2013 and 2012 in the above tables include: | |||||||||||||||||
• | 148.6 Bcfe of the increase in reserves for the year end December 31, 2013, through the category extensions and discoveries, was due to the WildHorse’s horizontal redevelopment drilling program in the Terryville Complex in Lincoln Parish, Louisiana. | ||||||||||||||||
• | WildHorse acquired 43.5 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Undisclosed Seller Acquisition. Downward revisions of previous estimates for estimated natural gas proved reserves was primarily the result of a decrease in natural gas prices. | ||||||||||||||||
See Note 3 for additional information on acquisitions and divestitures. | |||||||||||||||||
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. | |||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Future cash inflows | $ | 5,722,848 | $ | 4,921,192 | |||||||||||||
Future production costs | (1,587,374 | ) | (1,255,289 | ) | |||||||||||||
Future development costs | (1,352,945 | ) | (1,060,777 | ) | |||||||||||||
Future net cash flows for estimated timing of cash flows(1) | 2,782,529 | 2,605,126 | |||||||||||||||
10% annual discount for estimated timing of cash flows | (1,313,577 | ) | (1,284,531 | ) | |||||||||||||
Standardized measure of discounted future net cash flows(2) | $ | 1,468,952 | $ | 1,320,595 | |||||||||||||
-1 | We are subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas to immateriality we have excluded the impact of this tax. However, had we not been a tax exempt entity future income tax for the years ended December 31, 2013 and 2012 would have been $760,433 and $647,464, respectively. | ||||||||||||||||
-2 | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | |||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2013: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Beginning of year | $ | 1,320,595 | $ | 1,386,071 | |||||||||||||
Sale of oil and natural gas produced, net of production costs | (196,444 | ) | (107,316 | ) | |||||||||||||
Purchase of minerals in place | 51,177 | 98,384 | |||||||||||||||
Sale of minerals in place | (54,091 | ) | — | ||||||||||||||
Extensions and discoveries | 301,004 | 127,994 | |||||||||||||||
Changes in prices and costs | (11,336 | ) | (402,202 | ) | |||||||||||||
Previously estimated development costs incurred | 87,297 | 64,390 | |||||||||||||||
Net changes in future development costs | 57,353 | (67,331 | ) | ||||||||||||||
Revisions of previous quantities | (186,804 | ) | (176,788 | ) | |||||||||||||
Accretion of discount | 128,544 | 138,607 | |||||||||||||||
Change in production rates and other | (28,343 | ) | 258,786 | ||||||||||||||
End of year | $ | 1,468,952 | $ | 1,320,595 | |||||||||||||
MEMP Segment | |||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2013 and 2012, respectively: | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 39,089 | 604,440 | 29,352 | 1,015,095 | |||||||||||||
Extensions and discoveries | 5,655 | 40,770 | 1,747 | 85,180 | |||||||||||||
Purchase of minerals in place | 119 | 16,294 | 258 | 18,554 | |||||||||||||
Production | (1,764 | ) | (35,924 | ) | (1,632 | ) | (56,303 | ) | |||||||||
Sales of minerals in place | — | — | — | — | |||||||||||||
Revision of previous estimates | (3,950 | ) | (18,441 | ) | (879 | ) | (47,421 | ) | |||||||||
End of year(1) | 39,149 | 607,139 | 28,846 | 1,015,105 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 24,515 | 376,932 | 15,947 | 619,704 | |||||||||||||
End of year | 22,265 | 387,548 | 15,959 | 616,893 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 14,574 | 227,508 | 13,405 | 395,391 | |||||||||||||
End of year | 16,884 | 219,591 | 12,887 | 398,212 | |||||||||||||
-1 | MRD Segment’s share of these reserves is 89,837 MMcfe. | ||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 27,150 | 579,751 | 15,045 | 832,913 | |||||||||||||
Extensions and discoveries | 7,501 | 19,869 | 1,053 | 71,192 | |||||||||||||
Purchase of minerals in place | 11,336 | 113,617 | 7,095 | 224,202 | |||||||||||||
Production | (1,519 | ) | (29,744 | ) | (745 | ) | (43,329 | ) | |||||||||
Sales of minerals in place | (4,214 | ) | (4,214 | ) | — | (29,499 | ) | ||||||||||
Revision of previous estimates | (1,165 | ) | (74,839 | ) | 6,904 | (40,384 | ) | ||||||||||
End of year(1)(2) | 39,089 | 604,440 | 29,352 | 1,015,095 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 19,332 | 413,431 | 10,015 | 589,504 | |||||||||||||
End of year | 24,515 | 376,932 | 15,947 | 619,704 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 7,818 | 166,320 | 5,030 | 243,409 | |||||||||||||
End of year | 14,574 | 227,508 | 13,405 | 395,391 | |||||||||||||
-1 | Includes reserves of 406,324 MMcfe attributable to common control acquisitions. | ||||||||||||||||
-2 | MRD Segment’s share of these reserves is 476,550 MMcfe. | ||||||||||||||||
Noteworthy amounts included in the categories of proved reserve changes for the years 2013 and 2012 in the above tables include: | |||||||||||||||||
• | MEMP acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity. | ||||||||||||||||
See Note 3 for additional information on acquisitions and divestitures. | |||||||||||||||||
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. | |||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Future cash inflows | $ | 6,892,150 | $ | 6,511,776 | |||||||||||||
Future production costs | (2,719,024 | ) | (2,258,554 | ) | |||||||||||||
Future development costs | (685,858 | ) | (620,944 | ) | |||||||||||||
Future net cash flows for estimated timing of cash flows(1) | 3,487,268 | 3,632,278 | |||||||||||||||
10% annual discount for estimated timing of cash flows | (1,879,156 | ) | (2,042,362 | ) | |||||||||||||
Standardized measure of discounted future net cash flows(2)(3) | $ | 1,608,112 | $ | 1,589,916 | |||||||||||||
-1 | MEMP is subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax. MEMP is organized as a pass-through entity for income tax purposes. Had we not been a tax exempt entity our share of future income tax related to our ownership of MEMP for the years ended December 31, 2013 and 2012 would have been $61,300 and $306,297, respectively. | ||||||||||||||||
-2 | Includes $503,021 attributable to the MEMP previous owners for the year ended December 31, 2012. | ||||||||||||||||
-3 | MRD Segment’s share of the standardized measure of discounted future net cash flows was $142,318 and $554,981 for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | |||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2013: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Beginning of year | $ | 1,589,916 | $ | 1,499,414 | |||||||||||||
Sale of oil and natural gas produced, net of production costs | (234,520 | ) | (160,023 | ) | |||||||||||||
Purchase of minerals in place | 23,160 | 375,953 | |||||||||||||||
Sale of minerals in place | — | (154,963 | ) | ||||||||||||||
Extensions and discoveries | 136,423 | 265,108 | |||||||||||||||
Changes in income taxes, net | — | 1,947 | |||||||||||||||
Changes in prices and costs | (74,395 | ) | (331,760 | ) | |||||||||||||
Previously estimated development costs incurred | 174,490 | 66,360 | |||||||||||||||
Net changes in future development costs | (74,867 | ) | (1,140 | ) | |||||||||||||
Revisions of previous quantities | (141,122 | ) | (90,587 | ) | |||||||||||||
Accretion of discount | 158,991 | 150,136 | |||||||||||||||
Change in production rates and other | 50,036 | (30,529 | ) | ||||||||||||||
End of year | $ | 1,608,112 | $ | 1,589,916 | |||||||||||||
MEMORIAL_RESOURCE_DEVELOPMENT_
MEMORIAL RESOURCE DEVELOPMENT LLC (PREDECESSOR) SCHEDULE 1-CONDENSED FINANCIAL INFORMATION | 9 Months Ended | ||||||||
Sep. 30, 2014 | |||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ' | ||||||||
MEMORIAL RESOURCE DEVELOPMENT LLC (PREDECESSOR) SCHEDULE 1-CONDENSED FINANCIAL INFORMATION | ' | ||||||||
MEMORIAL RESOURCE DEVELOPMENT LLC (PREDECESSOR) SCHEDULE 1—CONDENSED FINANCIAL INFORMATION | |||||||||
Condensed balance sheets | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 19,293 | $ | 8,019 | |||||
Restricted cash | 35,000 | — | |||||||
Accounts receivable: | |||||||||
Affiliates | 90,917 | 84,347 | |||||||
Other | — | 3 | |||||||
Prepaid expenses and other current assets | 2,802 | 707 | |||||||
Total current assets | 148,012 | 93,076 | |||||||
Property and equipment, at cost: | |||||||||
Furniture and fixtures | 1,679 | 1,217 | |||||||
Accumulated depreciation, depletion and impairment | (547 | ) | (199 | ) | |||||
Oil and natural gas properties, net | 1,132 | 1,018 | |||||||
Long-term derivative instruments | |||||||||
Investments in subsidiaries | 411,657 | 797,868 | |||||||
Investments in previous owners | 40,331 | 233,433 | |||||||
Restricted cash | 15,000 | — | |||||||
Other long-term assets | 6,596 | 259 | |||||||
Total assets | $ | 622,728 | $ | 1,125,654 | |||||
LIABILITIES AND EQUITY | |||||||||
Current liabilities: | |||||||||
Accounts payable | $ | 130 | $ | 161 | |||||
Accrued liabilities | 1,896 | 225 | |||||||
Total current liabilities | 2,026 | 386 | |||||||
Long-term debt | 343,050 | 80,000 | |||||||
Other long-term liabilities | 135 | 221 | |||||||
Total liabilities | 345,211 | 80,607 | |||||||
Commitments and contingencies | |||||||||
Equity: | |||||||||
Members | 237,186 | 811,614 | |||||||
Previous Owners | 40,331 | 233,433 | |||||||
Total liabilities and members’ equity | $ | 622,728 | $ | 1,125,654 | |||||
Condensed statements of income | |||||||||
For Year Ended | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Costs and expenses: | |||||||||
Depreciation, depletion, and amortization | 348 | 195 | |||||||
General and administrative | 20,111 | 10,176 | |||||||
(Gain) loss on commodity derivative instruments | 546 | — | |||||||
Total costs and expenses | 21,005 | 10,371 | |||||||
Operating income | (21,005 | ) | (10,371 | ) | |||||
Other income (expense): | |||||||||
Equity income (loss) from subsidiaries | 114,974 | 2,970 | |||||||
Equity income (loss) from previous owners | 10,790 | 37,318 | |||||||
Interest expense, net | (3,257 | ) | (219 | ) | |||||
Total other income (expense) | 122,507 | 40,069 | |||||||
Net income (loss) | $ | 101,502 | $ | 29,698 | |||||
Condensed statements of cash flows | |||||||||
For Year Ended | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Net cash provided by (used in) operating activities | $ | (3,556 | ) | $ | (75,088 | ) | |||
Cash flows from investing activities: | |||||||||
Investments in subsidiaries | (40,666 | ) | (718 | ) | |||||
Additions to furniture and fixtures | (461 | ) | (903 | ) | |||||
Proceeds from changes in ownership interests in MEMP | 135,012 | — | |||||||
Changes in restricted cash | (50,000 | ) | — | ||||||
Net cash (used in) provided by investing activities | 43,885 | (1,621 | ) | ||||||
Cash flows from financing activities: | |||||||||
Advances on revolving credit facility | — | 80,000 | |||||||
Payments on revolving credit facility | (80,000 | ) | — | ||||||
Proceeds from issuance of senior notes | 343,000 | — | |||||||
Distributions received from subsidiaries (see Note 3) | 448,349 | — | |||||||
Loan origination fees | (8,042 | ) | (802 | ) | |||||
Distributions to the Funds | (732,362 | ) | — | ||||||
Net cash (used in) provided by financing activities | (29,055 | ) | 79,198 | ||||||
Net change in cash and cash equivalents | 11,274 | 2,489 | |||||||
Cash and cash equivalents, beginning of year | 8,019 | 5,530 | |||||||
Cash and cash equivalents, end of year | $ | 19,293 | $ | 8,019 | |||||
Note 1. Basis of Presentation | |||||||||
Memorial Resource Development LLC (“Memorial Resource”) is a Delaware limited liability company (the “Company”) formed on April 27, 2011 to own, acquire, exploit and develop oil and natural gas properties. Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Company” are intended to mean the business and operations of Memorial Resource Development LLC and its consolidated subsidiaries. There are significant restrictions over the ability of Memorial Resource to obtain funds from certain of its consolidating subsidiaries through dividends, loans or advances. Accordingly, these condensed financial statements have been presented on a “parent-only” basis. Under a parent-only presentation, the investments of Memorial Resource in its consolidated subsidiaries are presented under the equity method of accounting. These parent-only financial statements should be read in conjunction with the consolidated financial statements of MRD LLC included elsewhere herein. These condensed financial statements have been prepared in anticipation of a proposed initial public offering of the common stock of Memorial Resource Development Corp. (“MRDC”). | |||||||||
Note 2. Long-Term Debt | |||||||||
Our debt obligations under revolving credit facilities consisted of the following at December 31: | |||||||||
2013 | 2012 | ||||||||
(in thousands) | |||||||||
Memorial Resource $1.0 billion revolving credit facility, variable-rate, terminated December 2013 | $ | — | $ | 80,000 | |||||
10.00%/10.75% senior PIK toggle notes due December 2018 | 350,000 | — | |||||||
10.00%/10.75% senior PIK toggle notes unamortized discounts | (6,950 | ) | — | ||||||
Total long-term debt | $ | 343,050 | $ | 80,000 | |||||
On July 13, 2012, Memorial Resource entered into a two-year $50.0 million senior secured revolving credit with an initial borrowing base of $35.0 million. Memorial Resource pledged 7,061,294 of Memorial Production Partners LP (“MEMP”) common units and 5,360,912 of MEMP subordinated units as security under the credit facility as well as its oil and gas properties and certain other assets of Memorial Resource. This credit facility was also guaranteed by certain of Memorial Resources wholly-owned subsidiaries. | |||||||||
On November 20, 2012, Memorial Resource entered into a first amendment to its credit agreement, which among other things: (i) increased the aggregate maximum credit to $1.0 billion (ii) increased the borrowing base to $120.0 million and (iii) extended the maturity date to November 20, 2016. On April 25, 2013, Memorial Resource entered into a second amendment to its credit agreement, which among other things: (i) increased the borrowing base to $170.0 million and (ii) designated Tanos together with its consolidating subsidiaries as additional guarantors. On October 1, 2013, Tanos Energy, LLC (“Tanos”) and its consolidating subsidiaries were removed as guarantors and the borrowing base was reduced to $120.0 million. On November 1, 2013, Memorial Resource entered into a third amendment to its credit agreement, which among other things: (i) designated Black Diamond Minerals, LLC (“Black Diamond”) together with its consolidating subsidiaries as additional guarantors, (ii) reduced the borrowing base to $100.0 million, and (iii) permitted second lien indebtedness. On November 22, 2013, the borrowing base was automatically reduced to $60.0 million upon Memorial Resource’s sale of 7,061,294 MEMP common units in a secondary offering. | |||||||||
On December 18, 2013, indebtedness then outstanding under the revolving credit facility of $59.7 million and all accrued interest was paid off in full and the revolving credit facility was terminated in connection with the issuance of senior notes discussed below. | |||||||||
On December 18, 2013, Memorial Resource and its wholly-owned subsidiary, Memorial Resource Finance Corp. (“MRD Finance Corp.” and collectively, the “MRD Issuers”), completed a private placement of $350.0 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”). The PIK notes were issued at 98% of par and will mature on December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under Memorial Resource’s revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $220.0 million distribution to the Funds, and (iv) for general company purposes. | |||||||||
Interest on the PIK notes will be payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. Subject to conditions in the indenture governing the PIK notes, Memorial Resource will be required to pay interest on the PIK notes in cash or through issuing additional notes (such an issuance, “PIK Interest”). The interest rate on the PIK notes is 10.00% per annum for interest paid in cash or 10.75% per annum for PIK Interest. PIK Interest will be paid by issuing additional notes having the same terms as the PIK notes. The PIK notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MRD Issuers may also be required to repurchase the PIK notes upon a change of control. | |||||||||
At the time the PIK notes were issued, all of Memorial Resource’s subsidiaries other than MEMP and BlueStone Holdings (and their respective subsidiaries) were designated as restricted subsidiaries. The indenture governing the PIK notes contains customary covenants and restrictive provisions that apply to both Memorial Resource and its restricted subsidiaries, many of which will terminate if at any time no default exists under the indenture and the PIK notes receive an investment grade rating from both of two specified ratings agencies. The PIK notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Memorial Resource’s restricted subsidiaries, except MEMP GP and WildHorse. | |||||||||
The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency, all outstanding PIK notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding PIK notes may declare all the PIK notes to be due and payable immediately. | |||||||||
Note 3. Distribution from subsidiaries | |||||||||
The table below shows the distributions received from our subsidiaries classified as inflows from operating activities for the periods indicated since they are represent return on investment: | |||||||||
For Year Ended | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
(in thousands) | |||||||||
Distributions received from subsidiaries | $ | 25,966 | $ | 19,228 | |||||
Distributions received from our subsidiaries that represent return of investment are classified as inflows from investing activities. |
Background_Organization_and_Ba1
Background, Organization and Basis of Presentation (Policies) | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Accounting Policies [Abstract] | ' | ' | ||||||||||||||||
Overview | ' | ' | ||||||||||||||||
Overview | ||||||||||||||||||
Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. | ||||||||||||||||||
The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to exploit, develop and acquire natural gas, NGL and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. | ||||||||||||||||||
Initial Public Offering and Restructuring Transactions | ' | ' | ||||||||||||||||
Initial Public Offering and Restructuring Transactions | ||||||||||||||||||
On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: | ||||||||||||||||||
• | The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; | |||||||||||||||||
• | WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company will provide transition services to WildHorse Resources; | |||||||||||||||||
• | Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; | |||||||||||||||||
• | MRD LLC contributed to us substantially all of its assets, comprised of: (i)100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; | |||||||||||||||||
• | We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; | |||||||||||||||||
• | We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |||||||||||||||||
• | Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; | |||||||||||||||||
• | We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; | |||||||||||||||||
• | We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |||||||||||||||||
• | Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; | |||||||||||||||||
• | MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; | |||||||||||||||||
• | MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; | |||||||||||||||||
• | We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and | |||||||||||||||||
• | MRD LLC merged into MRD Operating. | |||||||||||||||||
Previous Owners | ' | ' | ||||||||||||||||
Previous Owners | ||||||||||||||||||
References to “the previous owners” for accounting and financial reporting purposes refer collectively to: | ||||||||||||||||||
• | Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. | |||||||||||||||||
• | A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. | |||||||||||||||||
Our unaudited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions on October 1, 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. | ||||||||||||||||||
Basis of Presentation | ' | ' | ||||||||||||||||
Basis of Presentation | Basis of Presentation | |||||||||||||||||
The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. | Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of the previous owners for the periods that those entities were under common control. | |||||||||||||||||
All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the nine months ended September 30, 2014 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). | All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments necessary for a fair presentation of the financial statements have been made. Certain amounts in the prior year financial statements have been reclassified to conform to the presentation in the current year financial statements. | |||||||||||||||||
We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: | We have two reportable business segments, both of which are engaged in the acquisition, exploitation, development and production of oil and natural gas properties (See Note 13). Our reportable business segments are as follows: | |||||||||||||||||
• | MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | • | MRD—reflects the combined operations of Memorial Resource, WildHorse and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | |||||||||||||||
• | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | • | MEMP—reflects the combined operations of MEMP, its previous owners, and any dropdown transactions between MEMP and other Memorial Resource subsidiaries. | |||||||||||||||
Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: | Segment financial information has been retrospectively revised for the following common control transactions between MEMP and other Memorial Resource subsidiaries for comparability purposes: | |||||||||||||||||
• | acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; | • | acquisition by MEMP of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013; | |||||||||||||||
• | acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; | • | acquisition by MEMP of all the outstanding membership interests in Prospect Energy for a purchase price of approximately $16.3 million on October 1, 2013; | |||||||||||||||
• | acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and | • | acquisition by MEMP of all the outstanding membership interests in WHT for a purchase price of approximately $200.0 million on March 28, 2013; | |||||||||||||||
• | acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013. | • | acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and | |||||||||||||||
• | acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million. | |||||||||||||||||
Use of Estimates | ' | ' | ||||||||||||||||
Use of Estimates | Use of Estimates | |||||||||||||||||
The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. | Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. | |||||||||||||||||
Principles of Consolidation and Combination | ' | ' | ||||||||||||||||
Principles of Consolidation and Combination | Principles of Consolidation and Combination | |||||||||||||||||
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of our predecessor and the previous owners. | Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Likewise, the combined financial statements include those of the previous owners. All material intercompany balances and transactions have been eliminated. | |||||||||||||||||
Cash and Cash Equivalents | ' | ' | ||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||
Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | |||||||||||||||||
Concentrations of Credit Risk | ' | ' | ||||||||||||||||
Concentrations of Credit Risk | Concentrations of Credit Risk | |||||||||||||||||
Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments. | Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments. | |||||||||||||||||
Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both September 30, 2014 and December 31, 2013, respectively. | Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2013 and 2012, respectively. | |||||||||||||||||
If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | |||||||||||||||||
Oil and Natural Gas Properties | ' | ' | ||||||||||||||||
Oil and Natural Gas Properties | Oil and Natural Gas Properties | |||||||||||||||||
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | |||||||||||||||||
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | |||||||||||||||||
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | |||||||||||||||||
There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2013 and December 31, 2012. | ||||||||||||||||||
Impairments | ' | ' | ||||||||||||||||
Impairments | Impairments | |||||||||||||||||
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2013 and 2012 was approximately $6.6 million and $28.9 million, respectively. | |||||||||||||||||
Unproved oil and natural gas properties are assessed for impairment on a property-by-property basis. A loss is recognized by providing a valuation allowance if the assessment indicates an impairment. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. | Nonproducing oil and natural gas properties, which consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. | |||||||||||||||||
Asset Retirement Obligations | ' | ' | ||||||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations | |||||||||||||||||
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | |||||||||||||||||
Oil and Gas Reserves | ' | ' | ||||||||||||||||
Oil and Gas Reserves | Oil and Gas Reserves | |||||||||||||||||
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. | The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to prepare our reserves estimates at December 31, 2013. | |||||||||||||||||
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | |||||||||||||||||
Other Property & Equipment | ' | ' | ||||||||||||||||
Other Property & Equipment | Other Property & Equipment | |||||||||||||||||
Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years. | Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years. | |||||||||||||||||
Restricted Investments | ' | ' | ||||||||||||||||
Restricted Investments | Restricted Investments | |||||||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense—net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. At September 30, 2014, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense—net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. At December 31, 2013, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | |||||||||||||||||
Debt Issuance Costs | ' | ' | ||||||||||||||||
Debt Issuance Costs | Debt Issuance Costs | |||||||||||||||||
These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. | These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. Amortization expense, including write-offs of debt issuance costs, for the years ended December 31, 2013 and 2012 was approximately $8.3 million and $3.6 million, respectively. | |||||||||||||||||
Revenue Recognition | ' | ' | ||||||||||||||||
Revenue Recognition | Revenue Recognition | |||||||||||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. | Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2013 or 2012. | |||||||||||||||||
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | ||||||||||||||||||
Years Ending December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Consolidated & Combined: | ||||||||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 35 | % | 13 | % | ||||||||||||||
MRD Segment: | ||||||||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 77 | % | 39 | % | ||||||||||||||
Sunoco, Inc.(1) | n/a | 15 | % | |||||||||||||||
Dominion Gas Ventures LP | n/a | 15 | % | |||||||||||||||
MEMP Segment: | ||||||||||||||||||
Phillips 66(2) | 15 | % | 13 | % | ||||||||||||||
ConocoPhillips(2) | n/a | 14 | % | |||||||||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||||||||
-2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. | |||||||||||||||||
Derivative Instruments | ' | ' | ||||||||||||||||
Derivative Instruments | Derivative Instruments | |||||||||||||||||
Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | |||||||||||||||||
Income Tax | ' | ' | ||||||||||||||||
Income Tax | Income Tax | |||||||||||||||||
Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas. | We are organized as a pass-through entity for federal income tax purposes. As a result, our members are responsible for federal income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations and subject to federal income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas. Deferred taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Deferred tax liabilities as of December 31, 2013 were approximately $3.2 million and total tax expense for the year was approximately $1.6 million. Deferred tax liabilities as of December 31, 2012 were approximately $3.1 million and total tax expense for the year was approximately $0.1 million. | |||||||||||||||||
Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. There were no uncertain tax positions that required recognition in the financial statements at both September 30, 2014 and December 31, 2013, respectively. | We must recognize the tax effects of any uncertain tax positions we may adopt if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2013 or 2012. | |||||||||||||||||
In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. | Upon closing of the Offering, MRDC will be treated as a taxable C corporation and will be subject to federal and certain state income taxes. Accordingly, a pro forma income tax provision has been disclosed as if Memorial Resource was a taxable corporation for all periods presented. Pro forma tax expense was computed using a blended corporate level federal and state tax rate of 36.06% and 35.39% for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||||
Earnings Per Share | ' | ' | ||||||||||||||||
Earnings Per Share | Unaudited Pro Forma Earnings Per Share | |||||||||||||||||
Basic earnings per share (“EPS”) is computed based on the average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock awards if the inclusion of these awards is dilutive. See Note 10 for additional information. | Memorial Resource has presented pro forma earnings per share (“EPS”) for all periods presented. Pro forma net income (loss) per basic share is determined by dividing the pro forma net income (loss) available to common shareholders by the number of common shares expected to be outstanding immediately following the Offering. | |||||||||||||||||
The following sets forth the calculation of pro forma EPS for the periods indicated (in thousands, except per share amounts): | ||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Numerator: | ||||||||||||||||||
Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | ||||||||||||||
Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | |||||||||||||||
Previous owners interest in pro forma net (income) loss, net of tax | (6,899 | ) | (24,111 | ) | ||||||||||||||
Pro forma net income (loss) available to common shareholders | $ | 59,037 | $ | (4,854 | ) | |||||||||||||
Denominator: | ||||||||||||||||||
Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | ||||||||||||||||
Basic EPS | $ | 0.31 | $ | (0.03 | ) | |||||||||||||
Diluted EPS | $ | 0.3 | $ | (0.03 | ) | |||||||||||||
-1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||
The following sets forth the calculation of our supplemental pro forma EPS, for the periods indicated (in thousands, except per share amounts): | ||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Numerator: | ||||||||||||||||||
Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | ||||||||||||||
Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | |||||||||||||||
Pro forma net income (loss) available to common shareholders | $ | 65,936 | $ | 19,257 | ||||||||||||||
Denominator: | ||||||||||||||||||
Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | ||||||||||||||||
Basic and diluted EPS | $ | 0.34 | $ | 0.1 | ||||||||||||||
-1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||
Our supplemental basic and diluted EPU includes all the earnings generated by the previous owners for all periods presented due to common control considerations. | ||||||||||||||||||
Incentive-Based Compensation Arrangements | ' | ' | ||||||||||||||||
Incentive-Based Compensation Arrangements | Unit-Based Compensation Arrangements | |||||||||||||||||
The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | |||||||||||||||||
Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | The governing documents of Memorial Resource and certain of its subsidiaries, including WildHorse and BlueStone, provide for the issuance of incentive units. The incentive units are subject to performance conditions that affect their vesting. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. | |||||||||||||||||
In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco. | See Note 10 and 11 for further information. | |||||||||||||||||
See Notes 11 and 12 for further information. | ||||||||||||||||||
Current Accrued Liabilities | ' | ' | ||||||||||||||||
Current Liabilities—Accrued liabilities | Current Accrued Liabilities | |||||||||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | Current accrued liabilities consisted of the following at the dates indicated (in thousands): | |||||||||||||||||
September 30, | December 31, | December 31, | ||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||
Accrued capital expenditures | $ | 77,716 | $ | 48,579 | Accrued capital expenditures | $ | 48,579 | $ | 14,352 | |||||||||
Accrued lease operating expense | 18,142 | 13,240 | Accrued lease operating expense | 13,240 | 6,701 | |||||||||||||
Accrued general and administrative expenses | 11,986 | 14,485 | Accrued general and administrative expenses | 14,485 | 2,290 | |||||||||||||
Accrued ad valorem and production taxes | 26,466 | 3,541 | Accrued ad valorem and production taxes | 3,541 | 3,753 | |||||||||||||
Accrued interest payable | 41,857 | 11,934 | Accrued interest payable | 11,934 | 1,239 | |||||||||||||
Accrued environmental | 571 | 577 | Accrued environmental | 577 | 1,012 | |||||||||||||
Other miscellaneous, including operator advances | 2,643 | 5,774 | Other miscellaneous, including operator advances | 5,774 | 4,140 | |||||||||||||
$ | 179,381 | $ | 98,130 | $ | 98,130 | $ | 33,487 | |||||||||||
New Accounting Pronouncements | ' | ' | ||||||||||||||||
New Accounting Pronouncements | New Accounting Pronouncements | |||||||||||||||||
Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its financial consolidated financial statements and footnote disclosures. | Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The new disclosure requirements required the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures became effective for annual and interim periods beginning on or after January 1, 2013 and were applied retrospectively. The adoption of this new guidance did not have a significant impact on our financial statements. | |||||||||||||||||
Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015. | ||||||||||||||||||
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Accounting Policies [Abstract] | ' | ' | ||||||||||||||||
Schedule of Current Accrued Liabilities | ' | ' | ||||||||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | Current accrued liabilities consisted of the following at the dates indicated (in thousands): | |||||||||||||||||
September 30, | December 31, | December 31, | ||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||
Accrued capital expenditures | $ | 77,716 | $ | 48,579 | Accrued capital expenditures | $ | 48,579 | $ | 14,352 | |||||||||
Accrued lease operating expense | 18,142 | 13,240 | Accrued lease operating expense | 13,240 | 6,701 | |||||||||||||
Accrued general and administrative expenses | 11,986 | 14,485 | Accrued general and administrative expenses | 14,485 | 2,290 | |||||||||||||
Accrued ad valorem and production taxes | 26,466 | 3,541 | Accrued ad valorem and production taxes | 3,541 | 3,753 | |||||||||||||
Accrued interest payable | 41,857 | 11,934 | Accrued interest payable | 11,934 | 1,239 | |||||||||||||
Accrued environmental | 571 | 577 | Accrued environmental | 577 | 1,012 | |||||||||||||
Other miscellaneous, including operator advances | 2,643 | 5,774 | Other miscellaneous, including operator advances | 5,774 | 4,140 | |||||||||||||
$ | 179,381 | $ | 98,130 | $ | 98,130 | $ | 33,487 | |||||||||||
Individual Customers Each Accounted for 10% or More of Total Reported Revenues | ' | ' | ||||||||||||||||
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | ||||||||||||||||||
Years Ending December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Consolidated & Combined: | ||||||||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 35 | % | 13 | % | ||||||||||||||
MRD Segment: | ||||||||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 77 | % | 39 | % | ||||||||||||||
Sunoco, Inc.(1) | n/a | 15 | % | |||||||||||||||
Dominion Gas Ventures LP | n/a | 15 | % | |||||||||||||||
MEMP Segment: | ||||||||||||||||||
Phillips 66(2) | 15 | % | 13 | % | ||||||||||||||
ConocoPhillips(2) | n/a | 14 | % | |||||||||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||||||||
-2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. |
Acquisitions_and_Divestitures_
Acquisitions and Divestitures (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||
Acquisition-Related Costs | ' | ' | ||||||||||||||||||||||||
Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | |||||||||||||||||||||||||
For the Nine Months | For the Year Ended December 31, | |||||||||||||||||||||||||
Ended September 30, | 2013 | 2012 | ||||||||||||||||||||||||
2014 | 2013 | $8,313 | $4,538 | |||||||||||||||||||||||
$5,480 | $5,073 | |||||||||||||||||||||||||
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed | ' | ' | ||||||||||||||||||||||||
The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of the acquisition date (in thousands): | ||||||||||||||||||||||||||
Louisiana | ||||||||||||||||||||||||||
Acquisition | ||||||||||||||||||||||||||
Oil and gas properties | $ | 68,887 | ||||||||||||||||||||||||
Asset retirement obligations | (1,789 | ) | ||||||||||||||||||||||||
Total identifiable net assets | $ | 67,098 | ||||||||||||||||||||||||
The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands): | ||||||||||||||||||||||||||
East Texas | Rockies | |||||||||||||||||||||||||
Acquisition | Acquisition | |||||||||||||||||||||||||
Oil and gas properties | $ | 9,974 | $ | 20,744 | ||||||||||||||||||||||
Asset retirement obligations | (78 | ) | (1,163 | ) | ||||||||||||||||||||||
Accrued liabilities | — | (118 | ) | |||||||||||||||||||||||
Total identifiable net assets | $ | 9,896 | $ | 19,463 | ||||||||||||||||||||||
The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). | ||||||||||||||||||||||||||
Undisclosed | Goodrich | Menemsha | Other Previous | |||||||||||||||||||||||
Seller | Acquisition | Acquisition | Owner | |||||||||||||||||||||||
Acquisition | Acquisitions | |||||||||||||||||||||||||
Oil and gas properties | $ | 115,633 | $ | 91,187 | $ | 75,114 | $ | 77,764 | ||||||||||||||||||
Prepaid expenses and other current assets | — | 425 | — | — | ||||||||||||||||||||||
Revenues payable | (1,602 | ) | (875 | ) | — | — | ||||||||||||||||||||
Asset retirement obligations | (1,592 | ) | (161 | ) | (408 | ) | (4,558 | ) | ||||||||||||||||||
Accrued liabilities | (297 | ) | (153 | ) | — | — | ||||||||||||||||||||
Total identifiable net assets | $ | 112,142 | $ | 90,423 | $ | 74,706 | $ | 73,206 | ||||||||||||||||||
Pro Forma Results of Operations | ' | ' | ||||||||||||||||||||||||
The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) | ||||||||||||||||||||||||||
The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | ||||||||||||||||||||||||||
Revenues | 431,061 | |||||||||||||||||||||||||
Net income | 40,940 | |||||||||||||||||||||||||
For the Nine Months | ||||||||||||||||||||||||||
Ended September 30, | ||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||
(In thousands, except per | ||||||||||||||||||||||||||
unit amounts) | ||||||||||||||||||||||||||
Revenues | $ | 764,084 | $ | 561,359 | ||||||||||||||||||||||
Net income (loss) | (931,903 | ) | 218,870 | |||||||||||||||||||||||
Basic and diluted earnings per share | $ | (4.94 | ) | $ | — | |||||||||||||||||||||
Eagle Ford Acquisition [Member] | ' | ' | ||||||||||||||||||||||||
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed | ' | ' | ||||||||||||||||||||||||
The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): | ||||||||||||||||||||||||||
Eagle Ford | Wyoming | |||||||||||||||||||||||||
Acquisition | Acquisition | |||||||||||||||||||||||||
Oil and gas properties | $ | 168,606 | $ | 922,686 | ||||||||||||||||||||||
Asset retirement obligations | (285 | ) | (3,328 | ) | ||||||||||||||||||||||
Revenue payable | — | (444 | ) | |||||||||||||||||||||||
Accrued liabilities | (250 | ) | (7,237 | ) | ||||||||||||||||||||||
Total identifiable net assets | $ | 168,071 | $ | 911,677 | ||||||||||||||||||||||
Fair_Value_Measurements_of_Fin1
Fair Value Measurements of Financial Instruments (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on Recurring Basis | ' | ' | ||||||||||||||||||||||||||||||||
The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014 and December 31, 2013 for each of the fair value hierarchy levels: | within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013 and 2012 for each of the fair value hierarchy levels: | |||||||||||||||||||||||||||||||||
Fair Value Measurements at September 30, 2014 Using | Fair Value Measurements at December 31, 2013 Using | |||||||||||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Fair Value | Quoted Prices in | Significant Other | Significant | Fair Value | |||||||||||||||||||||||||||
Active Market | Observable Inputs | Unobservable Inputs | Active Market | Observable | Unobservable | |||||||||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | (Level 1) | Inputs (Level 2) | Inputs (Level 3) | |||||||||||||||||||||||||||||
(In thousands) | (in thousands) | |||||||||||||||||||||||||||||||||
Assets: | Assets: | |||||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 129,711 | $ | — | $ | 129,711 | Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | |||||||||||||||||
Interest rate derivatives | — | 95 | — | 95 | Interest rate derivatives | — | 884 | — | 884 | |||||||||||||||||||||||||
Total assets | $ | — | $ | 129,806 | $ | — | $ | 129,806 | Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | |||||||||||||||||
Liabilities: | Liabilities: | |||||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 74,542 | $ | — | $ | 74,542 | Commodity derivatives | — | $ | 58,234 | — | $ | 58,234 | |||||||||||||||||||
Interest rate derivatives | — | 3,712 | — | 3,712 | Interest rate derivatives | — | 5,590 | — | 5,590 | |||||||||||||||||||||||||
Total liabilities | $ | — | $ | 78,254 | $ | — | $ | 78,254 | Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | |||||||||||||||||
Fair Value Measurements at December 31, 2013 Using | Fair Value Measurements at December 31, 2012 Using | |||||||||||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Fair Value | Quoted Prices in | Significant Other | Significant | Fair | |||||||||||||||||||||||||||
Active Market | Observable Inputs | Unobservable Inputs | Active Market | Observable | Unobservable | Value | ||||||||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | (Level 1) | Inputs (Level 2) | Inputs (Level 3) | |||||||||||||||||||||||||||||
(In thousands) | (in thousands) | |||||||||||||||||||||||||||||||||
Assets: | Assets: | |||||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | Commodity derivatives | $ | — | $ | 95,586 | $ | — | $ | 95,586 | |||||||||||||||||
Interest rate derivatives | — | 884 | — | 884 | ||||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||
Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | Commodity derivatives | — | $ | 45,938 | — | $ | 45,938 | |||||||||||||||||||
Interest rate derivatives | — | 6,838 | — | 6,838 | ||||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 58,234 | $ | — | $ | 58,234 | Total liabilities | $ | — | $ | 52,776 | $ | — | $ | 52,776 | |||||||||||||||||
Interest rate derivatives | — | 5,590 | — | 5,590 | ||||||||||||||||||||||||||||||
Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | ||||||||||||||||||||||||||
Risk_Management_and_Derivative1
Risk Management and Derivative Instruments (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Open Commodity Positions | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
At December 31, 2013, the MRD Segment had the following open commodity positions: | ||||||||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014, the MRD Segment had the following open commodity positions: | ||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | 2018 | Natural Gas Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||||
2014 | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | Average Monthly Volume (MMBtu) | 1,190,000 | 880,000 | 670,000 | 520,000 | |||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | Weighted-average fixed price | $ | 4.1 | $ | 4.19 | $ | 4.32 | $ | 4.45 | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 4,540,000 | 2,250,000 | 1,670,000 | 1,270,000 | 1,500,000 | |||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 4.18 | $ | 4.08 | $ | 4.18 | $ | 4.3 | $ | 4.3 | Collar contracts: | |||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 330,000 | 130,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Collar contracts: | Weighted-average floor price | $ | 4.09 | $ | 4 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 730,000 | 1,580,000 | 1,100,000 | 1,050,000 | — | Weighted-average ceiling price | $ | 5.24 | $ | 4.64 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 4.11 | $ | 4.14 | $ | 4 | $ | 4 | $ | — | ||||||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 5.15 | $ | 4.61 | $ | 4.71 | $ | 5.06 | $ | — | Basis swaps: | |||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 270,000 | 180,000 | 220,000 | 200,000 | ||||||||||||||||||||||||||||||||||||||||||||||
TGT Z1 basis swaps: | Spread | $ | (0.07 | ) | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | |||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,270,000 | 1,730,000 | 220,000 | 200,000 | — | |||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.08 | ) | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | $ | — | Crude Oil Derivative Contracts: | |||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | Average Monthly Volume (Bbls) | 18,000 | 6,000 | — | — | |||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | Weighted-average fixed price | $ | 91.66 | $ | 88.5 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 56,000 | 33,500 | — | 9,500 | 7,625 | |||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 94.43 | $ | 93.86 | $ | — | $ | 87.62 | $ | 87 | Collar contracts: | |||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 8,000 | 2,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Collar contracts: | Weighted-average floor price | $ | 85 | $ | 85 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 12,000 | 2,000 | 27,000 | — | — | Weighted-average ceiling price | $ | 117.5 | $ | 101.35 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 86.67 | $ | 85 | $ | 80 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 112.33 | $ | 101.35 | $ | 99.7 | $ | — | $ | — | NGL Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Put option contracts: | Average Monthly Volume (Bbls) | 18,000 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | — | 26,000 | — | — | — | Weighted-average fixed price | $ | 64.27 | — | — | — | |||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | — | $ | 85 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||
Weighted-average deferred premium | $ | — | $ | (3.80 | ) | $ | — | $ | — | $ | — | At December 31, 2013, the MEMP Segment had the following open commodity positions: | ||||||||||||||||||||||||||||||||||||||
NGL Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 184,000 | 151,000 | 148,500 | — | — | Natural Gas Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 44.84 | $ | 41.61 | $ | 39.75 | $ | — | $ | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,575,458 | 2,145,278 | 2,342,442 | 2,230,067 | 2,060,000 | 1,814,583 | ||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014, the MEMP Segment had the following open commodity positions: | Weighted-average fixed price | $ | 4.34 | $ | 4.3 | $ | 4.42 | $ | 4.31 | $ | 4.52 | $ | 4.77 | |||||||||||||||||||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | 2018 | 2019 | Average Monthly Volume (MMBtu) | 340,000 | 350,000 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
2014 | Weighted-average floor price | $ | 4.93 | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | Weighted-average ceiling price | $ | 6.12 | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,580,200 | 2,605,278 | 2,692,442 | 2,450,067 | 2,160,000 | 1,914,583 | Call spreads(1): | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 4.34 | $ | 4.28 | $ | 4.4 | $ | 4.31 | $ | 4.51 | $ | 4.75 | Average Monthly Volume (MMBtu) | 120,000 | 80,000 | — | — | — | — | |||||||||||||||||||||||||||||||
Weighted-average sold strike price | $ | 5.08 | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Collar contracts: | Weighted-average bought strike price | $ | 6.31 | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 340,000 | 350,000 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 5 | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | Basis swaps: | |||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 6.31 | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (MMBtu) | 2,822,083 | — | — | — | — | — | |||||||||||||||||||||||||||||||
Spread | $ | (0.09 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Call spreads (1): | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 120,000 | 80,000 | — | — | — | — | Crude Oil Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average sold strike price | $ | 5.17 | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||
Weighted-average bought strike price | $ | 6.53 | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (Bbls) | 136,444 | 148,281 | 142,313 | 130,600 | 122,000 | 40,000 | |||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 95.82 | $ | 93.07 | $ | 86.85 | $ | 85.96 | $ | 85.62 | $ | 85 | ||||||||||||||||||||||||||||||||||||||
Basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,830,000 | 2,940,000 | 1,635,000 | 300,000 | — | — | Collar contracts: | |||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.09 | ) | $ | (0.12 | ) | $ | (0.06 | ) | $ | (0.05 | ) | $ | — | $ | — | Average Monthly Volume (Bbls) | 23,000 | 5,000 | — | — | — | — | |||||||||||||||||||||||||||
Weighted-average floor price | $ | 82.83 | $ | 80 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | Weighted-average ceiling price | $ | 105.31 | $ | 94 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 283,452 | 314,281 | 332,813 | 326,600 | 312,000 | 160,000 | Basis swaps: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 95.83 | $ | 90.96 | $ | 85.83 | $ | 84.38 | $ | 83.74 | $ | 85.52 | Average Monthly Volume (Bbls) | 57,292 | 57,500 | — | — | — | — | |||||||||||||||||||||||||||||||
Spread | $ | (9.21 | ) | $ | (9.73 | ) | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 23,000 | 5,000 | — | — | — | — | NGL Derivative Contracts: | |||||||||||||||||||||||||||||||||||||||||||
Weighted-average floor price | $ | 82.83 | $ | 80 | $ | — | $ | — | $ | — | $ | — | Fixed price swap contracts: | |||||||||||||||||||||||||||||||||||||
Weighted-average ceiling price | $ | 105.31 | $ | 94 | $ | — | $ | — | $ | — | $ | — | Average Monthly Volume (Bbls) | 118,500 | 112,800 | — | — | — | — | |||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 36.23 | $ | 35.04 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 134,000 | 97,500 | — | — | — | — | -1 | These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | ||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (4.32 | ) | $ | (7.07 | ) | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
NGL Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 167,500 | 149,200 | 55,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed price | $ | 43.13 | $ | 43.02 | $ | 39.28 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
-1 | These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | |||||||||||||||||||||||||||||||||||||||||||||||||
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Remaining | 2015 | 2016 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
NGPL TexOk basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,260,000 | 2,280,000 | 1,500,000 | 300,000 | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.09 | ) | $ | (0.11 | ) | $ | (0.07 | ) | $ | (0.05 | ) | ||||||||||||||||||||||||||||||||||||||
NGPL STX basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 380,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.11 | ) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
HSC basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | 190,000 | 150,000 | 135,000 | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | (0.07 | ) | $ | (0.08 | ) | $ | 0.07 | $ | — | ||||||||||||||||||||||||||||||||||||||||
CIG basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | — | 210,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | — | $ | (0.25 | ) | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
TETCO STX basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (MMBtu) | — | 300,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread | $ | — | $ | (0.09 | ) | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Midway-Sunset basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 60,000 | 57,500 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread—Brent | $ | (9.25 | ) | $ | (9.73 | ) | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||
Midland basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 40,000 | 40,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread—WTI | $ | (3.68 | ) | $ | (3.25 | ) | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||
LLS Crude basis swaps: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Volume (Bbls) | 34,000 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Spread—WTI | $ | 3.61 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||
Schedule of Entity's Interest Rate Swap Open Positions | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014, we had the following interest rate swap open positions: | At December 31, 2013, we had the following interest rate swap open positions: | |||||||||||||||||||||||||||||||||||||||||||||||||
Credit Facility | Remaining | 2015 | 2016 | Credit Facility (see Note 8) | 2014 | 2015 | 2016 | |||||||||||||||||||||||||||||||||||||||||||
2014 | MEMP Segment: | |||||||||||||||||||||||||||||||||||||||||||||||||
MEMP: | Average Monthly Notional (in thousands) | $ | 173,958 | $ | 280,833 | $ | 150,000 | |||||||||||||||||||||||||||||||||||||||||||
Average Monthly Notional (in thousands) | $ | 248,333 | $ | 280,833 | $ | 150,000 | Weighted-average fixed rate | 1.306 | % | 1.416 | % | 1.193 | % | |||||||||||||||||||||||||||||||||||||
Weighted-average fixed rate | 1.299 | % | 1.416 | % | 1.193 | % | Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | ||||||||||||||||||||||||||||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | |||||||||||||||||||||||||||||||||||||||||||||||
MRD Segment: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Average Monthly Notional (in thousands) | $ | 118,750 | $ | 100,000 | $ | — | ||||||||||||||||||||||||||||||||||||||||||||
Weighted-average fixed rate | 0.773 | % | 0.758 | % | — | |||||||||||||||||||||||||||||||||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | — | |||||||||||||||||||||||||||||||||||||||||||||||
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2014 and December 31, 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. | The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation on the balance sheet and the net recorded fair value as reflected on the balance sheet at December 31: | |||||||||||||||||||||||||||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||
September 30, | December 31, | September 30, | December 31, | Type | Balance Sheet Location | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||||||
Type | Balance Sheet Location | 2014 | 2013 | 2014 | 2013 | (in thousands) | ||||||||||||||||||||||||||||||||||||||||||||
(In thousands) | Commodity contracts | Short-term derivative instruments | $ | 21,759 | $ | 48,901 | $ | 19,739 | $ | 8,072 | ||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Short-term derivative instruments | $ | 48,405 | $ | 21,759 | $ | 12,458 | $ | 19,739 | Interest rate swaps | Short-term derivative instruments | 845 | — | 3,287 | 3,575 | |||||||||||||||||||||||||||||||||||
Interest rate swaps | Short-term derivative instruments | — | 845 | 3,635 | 3,287 | |||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 22,604 | 48,901 | 23,026 | 11,647 | ||||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 48,405 | 22,604 | 16,093 | 23,026 | Netting arrangements | Short-term derivative instruments | (13,315 | ) | (6,980 | ) | (13,315 | ) | (6,980 | ) | ||||||||||||||||||||||||||||||||||||
Netting arrangements | Short-term derivative instruments | (10,984 | ) | (13,315 | ) | (10,984 | ) | (13,315 | ) | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Short-term derivative instruments | $ | 9,289 | $ | 41,921 | $ | 9,711 | $ | 4,667 | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Short-term derivative instruments | $ | 37,421 | $ | 9,289 | $ | 5,109 | $ | 9,711 | |||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Long-term derivative instruments | $ | 83,295 | $ | 46,685 | $ | 38,495 | $ | 37,866 | |||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Long-term derivative instruments | $ | 81,306 | $ | 83,295 | $ | 62,084 | $ | 38,495 | Interest rate swaps | Long-term derivative instruments | 39 | — | 2,303 | 3,263 | |||||||||||||||||||||||||||||||||||
Interest rate swaps | Long-term derivative instruments | 95 | 39 | 77 | 2,303 | |||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 83,334 | 46,685 | 40,798 | 41,129 | ||||||||||||||||||||||||||||||||||||||||||||||
Gross fair value | 81,401 | 83,334 | 62,161 | 40,798 | Netting arrangements | Long-term derivative instruments | (34,718 | ) | (29,506 | ) | (34,718 | ) | (29,506 | ) | ||||||||||||||||||||||||||||||||||||
Netting arrangements | Long-term derivative instruments | (46,886 | ) | (34,718 | ) | (46,886 | ) | (34,718 | ) | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 48,616 | $ | 17,179 | $ | 6,080 | $ | 11,623 | |||||||||||||||||||||||||||||||||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 34,515 | $ | 48,616 | $ | 15,275 | $ | 6,080 | |||||||||||||||||||||||||||||||||||||||||
Schedule of Gains and Losses Related to Derivative Instruments | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||
The following table details the gains and losses related to derivative instruments for the years ending December 31, 2013 and 2012: | ||||||||||||||||||||||||||||||||||||||||||||||||||
The following table details the gains and losses related to derivative instruments for the nine months ended September 30, 2014 and 2013 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments | Statements of Operations Location | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||||||||||||
Statements of | For the Nine Months | (in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||
Operations Location | Ended September 30, | Commodity derivative contracts | (Gain) loss on commodity derivative instruments | $ | (29,294 | ) | $ | (34,905 | ) | |||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | Interest rate swaps | Interest expense, net | (239 | ) | 5,582 | ||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative contracts | (Gain) loss on commodity derivatives | $ | 11,580 | $ | (29,556 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Interest rate derivatives | Interest expense, net | 1,157 | 69 |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | ' | ||||||||||||
Summary of Changes in Asset Retirement Obligations | ' | ' | ||||||||||||
The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2014 (in thousands): | The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2013 and 2012: | |||||||||||||
Asset retirement obligations at beginning of period | $ | 111,769 | 2013 | 2012 | ||||||||||
Liabilities added from acquisitions or drilling | 5,053 | (in thousands) | ||||||||||||
Liabilities removed upon sale of wells to an affiliate | (1,636 | ) | Asset retirement obligations at beginning of year | $ | 102,380 | $ | 90,699 | |||||||
Liabilities removed upon plugging and abandoning | (344 | ) | Liabilities added from acquisitions or drilling | 4,227 | 7,962 | |||||||||
Revisions | 67 | Liabilities removed upon sale of wells | (1,765 | ) | (1,931 | ) | ||||||||
Accretion expense | 4,601 | Liabilities removed upon plugging and abandoning | (170 | ) | (119 | ) | ||||||||
Accretion expense | 5,581 | 5,009 | ||||||||||||
Asset retirement obligations at end of period | $ | 119,510 | Revision of estimates | 1,516 | 760 | |||||||||
Asset retirement obligations at end of year | 111,769 | 102,380 | ||||||||||||
Less: Current portion | 90 | 390 | ||||||||||||
Asset retirement obligations—long-term portion | 111,679 | 101,990 | ||||||||||||
Restricted_Investments_Tables
Restricted Investments (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Text Block [Abstract] | ' | ' | ||||||||||||||||
Restricted Investment Balance | ' | ' | ||||||||||||||||
The components of the restricted investment balance, which are all attributable to our MEMP Segment, are as follows at December 31: | ||||||||||||||||||
The components of the restricted investment balance consisted of the following at the dates indicated: | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
(in thousands) | ||||||||||||||||||
September 30, | December 31, | BOEM platform abandonment (See Note 14) | $ | 66,373 | $ | 61,389 | ||||||||||||
2014 | 2013 | BOEM lease bonds | 794 | 776 | ||||||||||||||
(In thousands) | ||||||||||||||||||
BOEM platform abandonment (See Note 15) | $ | 68,970 | $ | 66,373 | SPBPC Collateral: | |||||||||||||
BOEM lease bonds | 794 | 794 | Contractual pipeline and surface facilities abandonment (See Note 14) | 2,306 | 1,959 | |||||||||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,000 | ||||||||||||||||
SPBPC Collateral: | City of Long Beach pipeline facility permit | 500 | 500 | |||||||||||||||
Contractual pipeline and surface facilities abandonment | 2,592 | 2,306 | Federal pipeline right-of-way bond | 307 | 300 | |||||||||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,005 | Port of Long Beach pipeline license | 100 | 100 | |||||||||||||
City of Long Beach pipeline facility permit | 500 | 500 | ||||||||||||||||
Federal pipeline right-of-way bond | 307 | 307 | Restricted investments | $ | 73,385 | $ | 68,024 | |||||||||||
Port of Long Beach pipeline license | 100 | 100 | ||||||||||||||||
Restricted investments | $ | 76,268 | $ | 73,385 | ||||||||||||||
Long_Term_Debt_Tables
Long Term Debt (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Debt Disclosure [Abstract] | ' | ' | ||||||||||||||||
Consolidated and Combined Debt Obligations | ' | ' | ||||||||||||||||
The following table presents our consolidated and combined debt obligations at the dates indicated: | Our debt obligations under revolving credit facilities consisted of the following at December 31: | |||||||||||||||||
September 30, | December 31, | 2013 | 2012 | |||||||||||||||
2014 | 2013 | (in thousands) | ||||||||||||||||
(In thousands) | MRD Segment: | |||||||||||||||||
MRD Segment: | Memorial Resource $1.0 billion revolving credit facility, variable-rate, terminated December 2013 | $ | — | $ | 80,000 | |||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 28,000 | $ | — | 10.00%/10.75% senior PIK toggle notes due December 2018(1) | 350,000 | — | |||||||||||
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 | — | 203,100 | 10.00%/10.75% senior PIK toggle notes unamortized discounts | (6,950 | ) | — | ||||||||||||
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 | — | 325,000 | WildHorse $1.0 billion revolving credit facility, variable-rate, due April 2018 | 203,100 | 202,200 | |||||||||||||
10.00%/10.75% senior PIK toggle notes redeemed June 2014(1) | — | 350,000 | WildHorse $325.0 million second lien term facility, variable-rate, due December 2018 | 325,000 | — | |||||||||||||
5.875% senior unsecured notes, due July 2022(2) | 600,000 | — | Black Diamond $150.0 million revolving credit facility, variable-rate, terminated November 2013 | — | 27,000 | |||||||||||||
10.00%/10.75% senior PIK toggle notes unamortized discounts | — | (6,950 | ) | BlueStone $150.0 million revolving credit facility, variable-rate, terminated August 2013 | — | — | ||||||||||||
Subtotal | 628,000 | 871,150 | Subtotal | 871,150 | 309,200 | |||||||||||||
MEMP Segment: | MEMP Segment: | |||||||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 301,000 | 103,000 | MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 103,000 | 371,000 | |||||||||||||
7.625% senior notes, fixed-rate, due May 2021(3) | 700,000 | 700,000 | 7.625% senior notes, fixed-rate, due May 1, 2021(2) | 700,000 | — | |||||||||||||
6.875% senior unsecurred notes, due August 2022(4) | 500,000 | — | 7.625% senior notes unamortized discounts | (10,933 | ) | — | ||||||||||||
Unamortized discounts | (17,200 | ) | (10,933 | ) | WHT $400.0 million revolving credit facility, variable-rate, terminated March 2013 | — | 89,300 | |||||||||||
Tanos $250.0 million revolving credit facility, variable-rate, terminated April 2013 | — | 25,250 | ||||||||||||||||
Subtotal | 1,483,800 | 792,067 | Stanolind $250.0 million revolving credit facility, variable-rate, due July 2017 | — | 85,750 | |||||||||||||
Boaz $75.0 million revolving credit facility, variable-rate, terminated October 2013 | — | 29,500 | ||||||||||||||||
Total long-term debt | $ | 2,111,800 | $ | 1,663,217 | Crown $75.0 million revolving credit facility, variable-rate, terminated October 2013 | — | 13,882 | |||||||||||
Propel Energy $200.0 million revolving credit facility, variable-rate, due June 2015 | — | 15,500 | ||||||||||||||||
-1 | The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | Subtotal | 792,067 | 630,182 | ||||||||||||||
-2 | The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
-3 | The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | Total long-term debt | $ | 1,663,217 | $ | 939,382 | ||||||||||||
-4 | The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
-1 | The estimated fair value of this fixed-rate debt was $348.3 million. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
-2 | The estimated fair value of this fixed-rate debt was $721.0 million. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||||||||||||||||
Borrowing Base Credit Facility | ' | ' | ||||||||||||||||
The borrowing base for each credit facility was the following at December 31: | ||||||||||||||||||
The borrowing base for each credit facility was the following at the date indicated (in thousands): | ||||||||||||||||||
2013 | ||||||||||||||||||
September 30, | (in thousands) | |||||||||||||||||
2014 | MRD Segment: | |||||||||||||||||
MRD Segment: | WildHorse $1.0 billion revolving credit facility, variable-rate, due April 2018 | 300,000 | ||||||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 668,500 | MEMP Segment: | |||||||||||||||
MEMP Segment: | MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 845,000 | ||||||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 1,315,000 | |||||||||||||||||
Total borrowing base | 1,145,000 | |||||||||||||||||
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations | ' | ' | ||||||||||||||||
The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: | The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented: | |||||||||||||||||
For the Nine Months | For the Year Ended December 31, | |||||||||||||||||
Ended September 30, | Credit facility | 2013 | 2012 | |||||||||||||||
Credit Facility | 2014 | 2013 | MRD Segment: | |||||||||||||||
MRD Segment: | Memorial Resource | 3.17 | % | 4.11 | % | |||||||||||||
MRD revolving credit facility | 2.4 | % | n/a | Classic | n/a | 4.5 | % | |||||||||||
MRD LLC revolver terminated December 2013 | n/a | 3.2 | % | WildHorse revolver | 2.3 | % | 3 | % | ||||||||||
WildHorse Resources revolver terminated June 2014 | 4.04 | % | 3.44 | % | WildHorse second lien | 7.6 | % | n/a | ||||||||||
WildHorse Resources second lien terminated June 2014 | 6.44 | % | 6.5 | % | Black Diamond | 3.97 | % | 3.62 | % | |||||||||
Black Diamond terminated November 2013 | n/a | 3.34 | % | BlueStone | n/a | n/a | ||||||||||||
MEMP Segment: | MEMP Segment: | |||||||||||||||||
MEMP revolving credit facility | 2.08 | % | 2.55 | % | MEMP | 3.25 | % | 2.74 | % | |||||||||
WHT revolver terminated March 2013 | n/a | 2.29 | % | Tanos | 3.1 | % | 2.31 | % | ||||||||||
Tanos revolver terminated April 2013 | n/a | 2.12 | % | WHT | 2.29 | % | 2.6 | % | ||||||||||
Stanolind revolver paid off by MEMP October 2013 | n/a | 3.52 | % | REO | n/a | 3.4 | % | |||||||||||
Boaz revolver terminated October 2013 | n/a | 2.97 | % | Stanolind | 3.52 | % | 3.76 | % | ||||||||||
Crown revolver terminated October 2013 | n/a | 3.38 | % | Crown | 3.38 | % | 4.2 | % | ||||||||||
Propel Energy revolver paid off by MEMP October 2013 | n/a | 3.08 | % | Propel Energy | 3.08 | % | 3.28 | % | ||||||||||
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations | ' | ' | ||||||||||||||||
Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated: | Unamortized deferred financing costs associated with our combined debt obligations were as follows at December 31: | |||||||||||||||||
September 30, | December 31, | 2013 | 2012 | |||||||||||||||
2014 | 2013 | (in thousands) | ||||||||||||||||
(In thousands) | MRD Segment: | |||||||||||||||||
MRD Segment: | Memorial Resource revolving credit facility | $ | — | $ | 653 | |||||||||||||
MRD revolving credit facility | $ | 4,433 | $ | — | PIK notes | 8,261 | — | |||||||||||
MRD senior notes | 12,825 | — | Classic revolving credit facility | — | 160 | |||||||||||||
WildHorse Resources revolving credit facility | — | 2,436 | WildHorse revolving credit facility | 2,436 | 921 | |||||||||||||
WildHorse Resources second lien term loan | — | 9,030 | WildHorse second lien term loan | 9,030 | — | |||||||||||||
PIK notes | — | 8,261 | Black Diamond revolving credit facility | — | 233 | |||||||||||||
MEMP Segment: | MEMP Segment: | |||||||||||||||||
MEMP revolving credit facility | 6,882 | 5,413 | MEMP revolving credit facility | 5,413 | 3,359 | |||||||||||||
2021 Senior Notes | 13,836 | 15,053 | Senior Notes | 15,053 | — | |||||||||||||
2022 Senior Notes | 8,222 | — | Tanos revolving credit facility | — | 416 | |||||||||||||
WHT revolving credit facility | — | 1,419 | ||||||||||||||||
$ | 46,198 | $ | 40,193 | Stanolind revolving credit facility | — | 580 | ||||||||||||
Boaz revolving credit facility | — | 153 | ||||||||||||||||
Crown revolving credit facility | — | 96 | ||||||||||||||||
Propel Energy revolving credit facility | — | 236 | ||||||||||||||||
$ | 40,193 | $ | 8,226 | |||||||||||||||
Stockholders_Equity_and_Noncon1
Stockholders' Equity and Noncontrolling Interests (Tables) | 9 Months Ended | ||||
Sep. 30, 2014 | |||||
Equity [Abstract] | ' | ||||
Summary of Changes In Common Shares Issued | ' | ||||
The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2014: | |||||
Balance January 1, 2014 | — | ||||
Shares of common stock issued in connection with restructuring transactions (Note 1) | 171,000,000 | ||||
Shares of common stock issued sold in initial public offering (Note 1) | 21,500,000 | ||||
Restricted common shares issued (Note 11) | 1,068,422 | ||||
Restricted common shares forfeited | (9,211 | ) | |||
Balance September 30, 2014 | 193,559,211 | ||||
Earnings_per_Share_Tables
Earnings per Share (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||
Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | |||||||||||||||||||||||||
Supplemental EPS [Member] | Pro Forma [Member] | Supplemental Pro Forma [Member] | ||||||||||||||||||||||||||
Calculation of Pro Forma Earnings Per Share | ' | ' | ' | ' | ||||||||||||||||||||||||
The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): | The following sets forth the calculation of pro forma EPS for the periods indicated (in thousands, except per share amounts): | The following sets forth the calculation of our supplemental pro forma EPS, for the periods indicated (in thousands, except per share amounts): | ||||||||||||||||||||||||||
The following sets forth the calculation of our supplemental EPS, for the periods indicated (in thousands, except per share amounts): | ||||||||||||||||||||||||||||
For the Nine | For the Year Ended December 31, | For the Year Ended December 31, | ||||||||||||||||||||||||||
Months Ended | For the Nine | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||||
September 30, | Months Ended | Numerator: | Numerator: | |||||||||||||||||||||||||
2014 | September 30, | Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | Pro forma net income (loss) | $ | 97,797 | $ | 17,512 | |||||||||||||||||
Numerator: | 2014 | Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | Noncontrolling interest in pro forma net (income) loss, net of tax | (31,861 | ) | 1,745 | |||||||||||||||||||
Net income (loss) available to common stockholders | $ | (951,801 | ) | Numerator: | Previous owners interest in pro forma net (income) loss, net of tax | (6,899 | ) | (24,111 | ) | |||||||||||||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | $ | (930,071 | ) | Pro forma net income (loss) available to common shareholders | $ | 65,936 | $ | 19,257 | ||||||||||||||||||||
Denominator: | Pro forma net income (loss) available to common shareholders | $ | 59,037 | $ | (4,854 | ) | ||||||||||||||||||||||
Weighted average common shares outstanding | 192,500 | Denominator: | ||||||||||||||||||||||||||
Restricted common shares(1) | — | Weighted average common shares outstanding | 192,500 | Denominator: | ||||||||||||||||||||||||
Restricted common shares(1) | — | Denominator: | Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | |||||||||||||||||||||||
Weighted average common and common equivalent shares outstanding | 192,500 | Common shares outstanding immediately following the Offering(1) | 193,676 | 193,676 | ||||||||||||||||||||||||
Weighted average common and common equivalent shares outstanding | 192,500 | Basic and diluted EPS | $ | 0.34 | $ | 0.1 | ||||||||||||||||||||||
Basic EPS | $ | (4.94 | ) | Basic EPS | $ | 0.31 | $ | (0.03 | ) | |||||||||||||||||||
Basic EPS | $ | (4.83 | ) | |||||||||||||||||||||||||
Diluted EPS | $ | (4.94 | ) | Diluted EPS | $ | 0.3 | $ | (0.03 | ) | -1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||
Diluted EPS | $ | (4.83 | ) | |||||||||||||||||||||||||
-1 | The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014. | -1 | Includes dilutive effect of 1,176 restricted common shares. | |||||||||||||||||||||||||
-1 | The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014. |
LongTerm_Incentive_Plans_Table
Long-Term Incentive Plans (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | ' | ||||||||||||||||
Summary of Information Regarding Restricted Common Unit Awards | ' | ' | ||||||||||||||||
The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: | The following table summarizes information regarding restricted common unit awards for the periods presented: | |||||||||||||||||
Number | Weighted- | Number of | Weighted Average | |||||||||||||||
of Shares | Average Grant | Units | Grant Date Fair | |||||||||||||||
Date Fair Value | Value per Unit(1) | |||||||||||||||||
per Share(1) | Restricted common units outstanding at January 1, 2012 | — | $ | — | ||||||||||||||
Restricted common shares outstanding at December 31, 2013 | — | $ | — | Granted(2) | 287,943 | $ | 18.07 | |||||||||||
Granted(2) | 1,068,422 | $ | 19 | Forfeited | (2,334 | ) | $ | 17.14 | ||||||||||
Forfeited | (9,211 | ) | $ | 19 | ||||||||||||||
Restricted common units outstanding at December 31, 2012 | 285,609 | $ | 18.08 | |||||||||||||||
Restricted common units outstanding at September 30, 2014 | 1,059,211 | $ | 19 | Granted(3) | 524,718 | $ | 18.83 | |||||||||||
Forfeited | (11,734 | ) | $ | 17.24 | ||||||||||||||
Vested | (91,666 | ) | $ | 18.31 | ||||||||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | |||||||||||||||||
-2 | The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on a grant date market price of $19.00 per share. | Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | |||||||||||||
The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: | -1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | ||||||||||||||||
-2 | The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices of MEMP ranging from of $17.14 to $18.58 per unit. | |||||||||||||||||
-3 | The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices of MEMP ranging from of $18.33 to $20.35 per unit. | |||||||||||||||||
Number of Units | Weighted- | |||||||||||||||||
Average Grant | ||||||||||||||||||
Date Fair Value | ||||||||||||||||||
per Unit(1) | ||||||||||||||||||
Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | |||||||||||||||
Granted(2) | 684,957 | $ | 22.39 | |||||||||||||||
Forfeited | (36,112 | ) | $ | 20.43 | ||||||||||||||
Vested | (260,067 | ) | $ | 18.56 | ||||||||||||||
Restricted common units outstanding at September 30, 2014 | 1,095,705 | $ | 20.93 | |||||||||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | |||||||||||||||||
-2 | The aggregate grant date fair value of restricted common unit awards issued in 2014 was $18.4 million based on a grant date market price range of $21.99 – $23.40 per unit. | |||||||||||||||||
Summary of Amount of Compensation Expense Recognized | ' | ' | ||||||||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | ||||||||||||||||||
For the Nine Months | ||||||||||||||||||
Ended September 30, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
$1,487 | $— | |||||||||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | ||||||||||||||||||
For the Nine Months | ||||||||||||||||||
Ended September 30, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
$5,387 | $2,322 |
Incentive_Units_Tables
Incentive Units (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2014 | |||||||||
Compensation Related Costs [Abstract] | ' | ||||||||
Fair Value of Incentive Units Estimated | ' | ||||||||
The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: | |||||||||
Exchanged Incentive Units | Subsequent Incentive Units | ||||||||
Valuation date | 9/30/14 | 9/30/14 | |||||||
Dividend yield | 0 | % | 0 | % | |||||
Expected volatility | 21.47 | % | 21.47 | % | |||||
Risk-free rate | 0.9 | % | 0.9 | % | |||||
Expected life (years) | 2.67 | 2.67 | |||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 9 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||
Related Party Transactions [Abstract] | ' | ' | ||||||||
Schedule of Net Assets Recorded | ' | ' | ||||||||
WildHorse Resources recorded the following net assets (in thousands): | MEMP recorded the following net assets (in thousands): | |||||||||
Accounts receivable | $ | 2,274 | Cash and cash equivalents | $ | 6,021 | |||||
Oil and natural gas properties, net | 40,056 | Accounts receivable | 16,284 | |||||||
Accrued liabilities | (297 | ) | Short-term derivative instruments, net | 2,926 | ||||||
Asset retirement obligations | (277 | ) | Prepaid expenses and other current assets | 4,521 | ||||||
Oil and natural gas properties, net | 108,342 | |||||||||
Net assets | $ | 41,756 | Restricted investments | 68,009 | ||||||
Accounts payable | (9,092 | ) | ||||||||
Accrued liabilities | (9,140 | ) | ||||||||
Asset retirement obligations | (58,746 | ) | ||||||||
Credit facilities | (28,500 | ) | ||||||||
Deferred tax liability | (1,674 | ) | ||||||||
Noncontrolling interest | (5,255 | ) | ||||||||
Net assets | $ | 93,696 | ||||||||
Book Value of Assets Sold | ' | ' | ||||||||
The net book value of the assets sold was as follows (in thousands): | The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. | |||||||||
Cash and cash equivalents | $ | 33,001 | Cash and cash equivalents | $ | 2,820 | |||||
Restricted cash | 300 | Accounts receivable | 5,184 | |||||||
Accounts receivable | 5,256 | Prepaid expenses and other current assets | 1,454 | |||||||
Prepaid expenses and other current assets | 379 | Oil and natural gas properties, net | 342,759 | |||||||
Property, plant and equipment, net | 3,410 | Other long-term assets | 344 | |||||||
Other long-term assets | 4 | Accounts payable | (2,346 | ) | ||||||
Accounts payable | (19,959 | ) | Revenue payable | (2,910 | ) | |||||
Accounts payable—affiliates | (17,099 | ) | Accrued liabilities | (1,799 | ) | |||||
Accrued liabilities | (5,061 | ) | Short-term derivative instruments, net | (1,828 | ) | |||||
Long-term derivative instruments, net | (826 | ) | ||||||||
Net assets | $ | 231 | Asset retirement obligations | (9,606 | ) | |||||
Credit facilities | (151,690 | ) | ||||||||
Net assets | $ | 181,556 | ||||||||
Business_Segment_Data_Tables
Business Segment Data (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||
Summary of Selected Business Segment Information | ' | ' | ||||||||||||||||||||||||||||||||
The following table presents selected business segment information for the periods indicated (in thousands): | The following table presents selected business segment information for the periods indicated (in thousands): | |||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||
Adjustments & | Combined | Adjustments & | and | |||||||||||||||||||||||||||||||
Eliminations | Totals | Eliminations | Combined | |||||||||||||||||||||||||||||||
Total revenues: | Totals | |||||||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | $ | 301,492 | $ | 371,530 | $ | (137 | ) | $ | 672,885 | Total revenues: | ||||||||||||||||||||||||
Nine months ended September 30, 2013 | 171,361 | 251,516 | (136 | ) | 422,741 | Year ended December 31, 2013 | $ | 231,558 | $ | 343,616 | $ | (151 | ) | $ | 575,023 | |||||||||||||||||||
Adjusted EBITDA: (1) | Year ended December 31, 2012 | 138,814 | 258,423 | (369 | ) | 396,868 | ||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | 247,335 | 218,842 | (18,912 | ) | 447,265 | Adjusted EBITDA: | ||||||||||||||||||||||||||||
Nine months ended September 30, 2013 | 153,679 | 157,160 | (19,554 | ) | 291,285 | Year ended December 31, 2013(1) | 197,903 | 222,185 | (25,232 | ) | 394,856 | |||||||||||||||||||||||
Segment assets: (2) | Year ended December 31, 2012(1) | 131,702 | 179,334 | (23,447 | ) | 287,589 | ||||||||||||||||||||||||||||
As of September 30, 2014 | 1,232,146 | 2,749,452 | 40,069 | 4,021,667 | Segment assets:(2) | |||||||||||||||||||||||||||||
As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | |||||||||||||||||||||||
Total cash expenditures for additions to long-lived assets: | As of December 31, 2012 | 1,102,406 | 1,489,404 | (132,506 | ) | 2,459,304 | ||||||||||||||||||||||||||||
Nine months ended September 30, 2014 | (276,982 | ) | (1,273,157 | ) | — | (1,550,139 | ) | Total expenditures for additions to long-lived assets: | ||||||||||||||||||||||||||
Nine months ended September 30, 2013 | (198,220 | ) | (165,403 | ) | — | (363,623 | ) | Year ended December 31, 2013 | 267,870 | 200,577 | — | 468,447 | ||||||||||||||||||||||
Year ended December 31, 2012 | 249,526 | 387,160 | — | 636,686 | ||||||||||||||||||||||||||||||
-1 | Adjustments and eliminations for the nine months ended September 30, 2014 and 2013 include amounts related to the MRD’s Segment equity investments in the MEMP Segment as well as the elimination of $6.1 million of cash distributions that MEMP paid MRD for the nine months ended September 30, 2014, and $19.1 million of cash distributions that MEMP paid MRD LLC for the nine months ended September 30, 2013, related to MRD LLC’s partnership interests in MEMP. | |||||||||||||||||||||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD’s Segment equity investments in the MEMP Segment. The adjustment at September 30, 2014 and December 31, 2013 also includes $47.3 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | -1 | Adjustments and eliminations for the years ended December 31, 2013 and 2012 include amounts related to the MRD’s Segment equity investments in the MEMP Segment as well the elimination of $26.0 million and $19.3 million of cash distributions that MEMP paid Memorial Resource for the years ended December 31, 2013 and 2012, respectively, related to Memorial Resource’s partnership interests in MEMP. | |||||||||||||||||||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD’s Segment equity investments in the MEMP Segment. The adjustment at December 31, 2013 also includes $49.9 million related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | |||||||||||||||||||||||||||||||||
Schedule of Calculation of Reportable Segment's Adjusted EBITDA | ' | ' | ||||||||||||||||||||||||||||||||
Calculation of Reportable Segments’ Adjusted EBITDA | Calculation of Reportable Segments’ Adjusted EBITDA | |||||||||||||||||||||||||||||||||
For the Nine Months | For the Year Ended December 31, 2013 | |||||||||||||||||||||||||||||||||
Ended September 30, 2014 | MRD | MEMP | Combined | |||||||||||||||||||||||||||||||
MRD | MEMP | Combined | Totals | |||||||||||||||||||||||||||||||
Totals | (in thousands) | |||||||||||||||||||||||||||||||||
(In thousands) | Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 102,511 | |||||||||||||||||||||||||||
Net income (loss) | $ | (930,149 | ) | $ | (45,037 | ) | $ | (975,186 | ) | Interest expense, net | 27,349 | 41,901 | 69,250 | |||||||||||||||||||||
Interest expense, net | 44,355 | 60,573 | 104,928 | Income tax expense (benefit) | 1,311 | 308 | 1,619 | |||||||||||||||||||||||||||
Loss on extinguishment of debt | 37,248 | — | 37,248 | DD&A | 87,043 | 97,269 | 184,312 | |||||||||||||||||||||||||||
Income tax expense (benefit) | 14,323 | 75 | 14,398 | Impairment of proved oil and natural gas properties | 2,527 | 54,362 | 56,889 | |||||||||||||||||||||||||||
DD&A | 107,496 | 105,830 | 213,326 | Accretion of AROs | 728 | 4,853 | 5,581 | |||||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 67,181 | 67,181 | (Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | (29,294 | ) | ||||||||||||||||||||||||
Accretion of AROs | 495 | 4,106 | 4,601 | Cash settlements received on commodity derivative instruments | 12,240 | 19,879 | 32,119 | |||||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (17,130 | ) | 28,710 | 11,580 | Gain on sale of properties | (82,773 | ) | (2,848 | ) | (85,621 | ) | |||||||||||||||||||||||
Cash settlements received (paid) on commodity derivative instruments | (4,930 | ) | (14,999 | ) | (19,929 | ) | Acquisition related costs | 1,584 | 6,729 | 8,313 | ||||||||||||||||||||||||
(Gain) loss on sale of properties | 3,057 | — | 3,057 | Incentive unit compensation expense | 43,279 | 3,558 | 46,837 | |||||||||||||||||||||||||||
Acquisition related costs | 1,568 | 3,912 | 5,480 | Non-cash compensation expense | — | 1,057 | 1,057 | |||||||||||||||||||||||||||
Incentive-based compensation expense | 970,877 | 5,387 | 976,264 | Exploration costs | 1,226 | 1,130 | 2,356 | |||||||||||||||||||||||||||
Exploration costs | 1,213 | 252 | 1,465 | Equity (income) loss from MEMP | (1,847 | ) | — | (1,847 | ) | |||||||||||||||||||||||||
Provision for environmental remediation | — | 2,852 | 2,852 | Cash distributions from MEMP | 26,006 | — | 26,006 | |||||||||||||||||||||||||||
Non-cash equity (income) loss from MEMP | 12,844 | — | 12,844 | |||||||||||||||||||||||||||||||
Cash distributions from MEMP | 6,068 | — | 6,068 | Adjusted EBITDA | $ | 197,903 | $ | 222,185 | $ | 420,088 | ||||||||||||||||||||||||
Adjusted EBITDA | $ | 247,335 | $ | 218,842 | $ | 466,177 | ||||||||||||||||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||||||||||||||||||||
MRD | MEMP | Combined | ||||||||||||||||||||||||||||||||
For the Nine Months | Totals | |||||||||||||||||||||||||||||||||
Ended September 30, 2013 | (in thousands) | |||||||||||||||||||||||||||||||||
MRD | MEMP | Combined | Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | 31,877 | ||||||||||||||||||||||||
Totals | Interest expense, net | 12,802 | 20,436 | 33,238 | ||||||||||||||||||||||||||||||
(In thousands) | Income tax expense (benefit) | (178 | ) | 285 | 107 | |||||||||||||||||||||||||||||
Net income (loss) | $ | 114,628 | $ | 9,359 | $ | 123,987 | DD&A | 62,636 | 76,036 | 138,672 | ||||||||||||||||||||||||
Interest expense, net | 15,947 | 26,047 | 41,994 | Impairment of proved oil and natural gas properties | 18,339 | 10,532 | 28,871 | |||||||||||||||||||||||||||
Income tax expense (benefit) | 1,147 | 285 | 1,432 | Accretion of AROs | 632 | 4,377 | 5,009 | |||||||||||||||||||||||||||
DD&A | 62,605 | 69,723 | 132,328 | (Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | (34,905 | ) | ||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 50,310 | 50,310 | Cash settlements received on commodity derivative instruments | 30,188 | 44,111 | 74,299 | |||||||||||||||||||||||||||
Accretion of AROs | 547 | 3,469 | 4,016 | Gain on sale of properties | (2 | ) | (9,759 | ) | (9,761 | ) | ||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (8,361 | ) | (21,195 | ) | (29,556 | ) | Acquisition related costs | 403 | 4,135 | 4,538 | ||||||||||||||||||||||||
Cash settlements received (paid) on commodity derivative instruments | 9,125 | 14,081 | 23,206 | Incentive unit compensation expense | 9,510 | 1,423 | 10,933 | |||||||||||||||||||||||||||
(Gain) loss on sale of properties | (83,370 | ) | (2,848 | ) | (86,218 | ) | Exploration costs | 7,337 | 2,463 | 9,800 | ||||||||||||||||||||||||
Acquisition related costs | 1,651 | 3,422 | 5,073 | Amortization of investment premium | — | 194 | 194 | |||||||||||||||||||||||||||
Incentive-based compensation expense | 19,069 | 2,322 | 21,391 | Non-cash equity (income) loss from MEMP | (696 | ) | — | (696 | ) | |||||||||||||||||||||||||
Non-cash compensation expense | — | 1,057 | 1,057 | Cash distributions from MEMP | 19,263 | — | 19,263 | |||||||||||||||||||||||||||
Exploration costs | 1,137 | 1,128 | 2,265 | |||||||||||||||||||||||||||||||
Non-cash equity (income) loss from MEMP | 454 | — | 454 | Adjusted EBITDA | $ | 132,105 | $ | 179,334 | $ | 311,439 | ||||||||||||||||||||||||
Cash distributions from MEMP | 19,100 | — | 19,100 | |||||||||||||||||||||||||||||||
Adjusted EBITDA | $ | 153,679 | $ | 157,160 | $ | 310,839 | ||||||||||||||||||||||||||||
Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) | ' | ' | ||||||||||||||||||||||||||||||||
The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands). | The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated. | |||||||||||||||||||||||||||||||||
For the Nine Months | For the Years Ended December 31, | |||||||||||||||||||||||||||||||||
Ended September 30, | 2013 | 2012 | ||||||||||||||||||||||||||||||||
2014 | 2013 | (in thousands) | ||||||||||||||||||||||||||||||||
Total Reportable Segments’ Adjusted EBITDA | $ | 466,177 | $ | 310,839 | Total Reportable Segments’ Adjusted EBITDA | $ | 420,088 | $ | 311,439 | |||||||||||||||||||||||||
Adjustments to reconcile Adjusted EBITDA to net income (loss): | Adjustment to reconcile Adjusted EBITDA to net income (loss): | |||||||||||||||||||||||||||||||||
Interest expense, net | (104,928 | ) | (41,994 | ) | Interest expense, net | (69,250 | ) | (33,238 | ) | |||||||||||||||||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | Income tax benefit (expense) | (1,619 | ) | (107 | ) | ||||||||||||||||||||||||||
Income tax benefit (expense) | (14,398 | ) | (1,432 | ) | DD&A | (184,717 | ) | (138,672 | ) | |||||||||||||||||||||||||
DD&A | (215,906 | ) | (132,328 | ) | Impairment of proved oil and natural gas properties | (6,600 | ) | (28,871 | ) | |||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | (67,181 | ) | (21 | ) | Accretion of AROs | (5,581 | ) | (5,009 | ) | |||||||||||||||||||||||||
Accretion of AROs | (4,601 | ) | (4,016 | ) | Gains (losses) on commodity derivative instruments | 29,294 | 34,905 | |||||||||||||||||||||||||||
Gains (losses) on commodity derivative instruments | (11,580 | ) | 29,556 | Cash settlements received on commodity derivative instruments | (32,119 | ) | (74,299 | ) | ||||||||||||||||||||||||||
Cash settlements paid (received) on commodity derivative instruments | 19,929 | (23,206 | ) | Gain on sale of properties | 85,621 | 9,761 | ||||||||||||||||||||||||||||
Gain (loss) on sale of properties | (3,057 | ) | 86,218 | Acquisition related costs | (8,313 | ) | (4,538 | ) | ||||||||||||||||||||||||||
Acquisition related costs | (5,480 | ) | (5,073 | ) | Incentive unit compensation expense | (46,837 | ) | (10,933 | ) | |||||||||||||||||||||||||
Incentive-based compensation expense) | (976,264 | ) | (21,391 | ) | Non-cash compensation expense | (1,057 | ) | — | ||||||||||||||||||||||||||
Non-cash compensation expense | — | (1,057 | ) | Exploration costs | (2,356 | ) | (9,800 | ) | ||||||||||||||||||||||||||
Exploration costs | (1,465 | ) | (2,265 | ) | Amortization of investment premium | — | (194 | ) | ||||||||||||||||||||||||||
Provision for environmental remediation | (2,852 | ) | — | Cash distributions from MEMP | (26,006 | ) | (19,263 | ) | ||||||||||||||||||||||||||
Cash distributions from MEMP | (6,068 | ) | (19,100 | ) | Non-cash equity (income) loss from WHT & MRD Assets | 784 | (4,184 | ) | ||||||||||||||||||||||||||
Other non-cash equity (income) loss) | — | (430 | ) | |||||||||||||||||||||||||||||||
Net income (loss) | $ | 151,332 | $ | 26,997 | ||||||||||||||||||||||||||||||
Net income (loss) | $ | (964,922 | ) | $ | 174,300 | |||||||||||||||||||||||||||||
Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment | ' | ' | ||||||||||||||||||||||||||||||||
Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): | Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated: | |||||||||||||||||||||||||||||||||
For the Nine Months Ended September 30, 2014 | For the Year Ended December 31, 2013 | |||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||
Adjustments & | Combined | Adjustments & | and Combined | |||||||||||||||||||||||||||||||
Eliminations | Totals | Eliminations | Totals | |||||||||||||||||||||||||||||||
Revenues: | (in thousands) | |||||||||||||||||||||||||||||||||
Oil & natural gas sales | $ | 300,931 | $ | 368,370 | $ | — | $ | 669,301 | Revenues: | |||||||||||||||||||||||||
Other revenues | 561 | 3,160 | (137 | ) | 3,584 | Oil & natural gas sales | $ | 230,751 | $ | 341,197 | $ | — | $ | 571,948 | ||||||||||||||||||||
Other revenues | 807 | 2,419 | (151 | ) | 3,075 | |||||||||||||||||||||||||||||
Total revenues | 301,492 | 371,530 | (137 | ) | 672,885 | |||||||||||||||||||||||||||||
Total revenues | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||
Lease operating | 18,657 | 93,367 | (137 | ) | 111,887 | Costs and expenses: | ||||||||||||||||||||||||||||
Pipeline operating | — | 1,596 | — | 1,596 | Lease operating | 25,006 | 88,893 | (259 | ) | 113,640 | ||||||||||||||||||||||||
Exploration | 1,213 | 252 | — | 1,465 | Pipeline operating | — | 1,835 | — | 1,835 | |||||||||||||||||||||||||
Production and ad valorem taxes | 10,494 | 23,129 | — | 33,623 | Exploration | 1,226 | 1,130 | — | 2,356 | |||||||||||||||||||||||||
Depreciation, depletion, and amortization | 107,496 | 105,830 | 2,580 | 215,906 | Production and ad valorem taxes | 9,362 | 17,784 | — | 27,146 | |||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 67,181 | — | 67,181 | Depreciation, depletion, and amortization | 87,043 | 97,269 | 405 | 184,717 | |||||||||||||||||||||||||
Incentive unit compensation expense | 969,390 | — | — | 969,390 | Impairment of proved oil and natural gas properties | 2,527 | 54,362 | (50,289 | ) | 6,600 | ||||||||||||||||||||||||
General and administrative | 29,301 | 31,760 | — | 61,061 | General and administrative | 81,758 | 43,495 | 105 | 125,358 | |||||||||||||||||||||||||
Accretion of asset retirement obligations | 495 | 4,106 | — | 4,601 | Accretion of asset retirement obligations | 728 | 4,853 | — | 5,581 | |||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (17,130 | ) | 28,710 | — | 11,580 | (Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | — | (29,294 | ) | |||||||||||||||||||||
(Gain) loss on sale of properties | 3,057 | — | — | 3,057 | (Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | — | (85,621 | ) | ||||||||||||||||||||||
Other, net | — | (12 | ) | — | (12 | ) | Other, net | 2 | 647 | — | 649 | |||||||||||||||||||||||
Total costs and expenses | 1,122,973 | 355,919 | 2,443 | 1,481,335 | Total costs and expenses | 121,866 | 281,139 | (50,038 | ) | 352,967 | ||||||||||||||||||||||||
Operating income (loss) | (821,481 | ) | 15,611 | (2,580 | ) | (808,450 | ) | Operating income | 109,692 | 62,477 | 49,887 | 222,056 | ||||||||||||||||||||||
Other income (expense): | Other income (expense): | |||||||||||||||||||||||||||||||||
Interest expense, net | (44,355 | ) | (60,573 | ) | — | (104,928 | ) | Interest expense, net | (27,349 | ) | (41,901 | ) | — | (69,250 | ) | |||||||||||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | (37,248 | ) | Earnings from equity investments | 1,066 | — | (1,066 | ) | — | ||||||||||||||||||||||
Earnings from equity investments | (12,844 | ) | — | 12,844 | — | Other, net | 145 | — | — | 145 | ||||||||||||||||||||||||
Other, net | 102 | — | — | 102 | ||||||||||||||||||||||||||||||
Total other income (expense) | (26,138 | ) | (41,901 | ) | (1,066 | ) | (69,105 | ) | ||||||||||||||||||||||||||
Total other income (expense) | (94,345 | ) | (60,573 | ) | 12,844 | (142,074 | ) | |||||||||||||||||||||||||||
Income before income taxes | 83,554 | 20,576 | 48,821 | 152,951 | ||||||||||||||||||||||||||||||
Income (loss) before income taxes | (915,826 | ) | (44,962 | ) | 10,264 | (950,524 | ) | Income tax benefit (expense) | (1,311 | ) | (308 | ) | — | (1,619 | ) | |||||||||||||||||||
Income tax benefit (expense) | (14,323 | ) | (75 | ) | — | (14,398 | ) | |||||||||||||||||||||||||||
Net income | $ | 82,243 | $ | 20,268 | $ | 48,821 | $ | 151,332 | ||||||||||||||||||||||||||
Net income (loss) | $ | (930,149 | ) | $ | (45,037 | ) | $ | 10,264 | $ | (964,922 | ) | |||||||||||||||||||||||
-1 | During the year ended December 31, 2013 the MEMP Segment recorded impairments of $50.3 million related to certain properties in East Texas. Both the MRD and MEMP Segments own properties in the same field and on a consolidated basis the expected future cash flows exceeded the carrying value, and therefore, did not result in an impairment on a consolidated basis. | |||||||||||||||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||||||||||||||||
MRD | MEMP | Other, | Consolidated & | For the Year Ended December 31, 2012 | ||||||||||||||||||||||||||||||
Adjustments & | Combined | MRD | MEMP | Other | Consolidated | |||||||||||||||||||||||||||||
Eliminations | Totals | Adjustments & | and Combined | |||||||||||||||||||||||||||||||
Revenues: | Eliminations | Totals | ||||||||||||||||||||||||||||||||
Oil & natural gas sales | $ | 171,013 | $ | 249,844 | $ | — | $ | 420,857 | (in thousands) | |||||||||||||||||||||||||
Other revenues | 348 | 1,672 | (136 | ) | 1,884 | Revenues: | ||||||||||||||||||||||||||||
Oil & natural gas sales | $ | 138,032 | $ | 255,608 | $ | (9 | ) | $ | 393,631 | |||||||||||||||||||||||||
Total revenues | 171,361 | 251,516 | (136 | ) | 422,741 | Other revenues | 782 | 2,815 | (360 | ) | 3,237 | |||||||||||||||||||||||
Costs and expenses: | Total revenues | 138,814 | 258,423 | (369 | ) | 396,868 | ||||||||||||||||||||||||||||
Lease operating | 17,065 | 64,922 | (241 | ) | 81,746 | |||||||||||||||||||||||||||||
Pipeline operating | — | 1,343 | — | 1,343 | Costs and expenses: | |||||||||||||||||||||||||||||
Exploration | 1,137 | 1,128 | — | 2,265 | Lease operating | 24,438 | 80,116 | (800 | ) | 103,754 | ||||||||||||||||||||||||
Production and ad valorem taxes | 8,563 | 14,915 | — | 23,478 | Pipeline operating | — | 2,114 | — | 2,114 | |||||||||||||||||||||||||
Depreciation, depletion, and amortization | 62,605 | 69,723 | — | 132,328 | Exploration | 7,337 | 2,463 | — | 9,800 | |||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | — | 50,310 | (50,289 | ) | 21 | Production and ad valorem taxes | 7,576 | 16,048 | — | 23,624 | ||||||||||||||||||||||||
Incentive unit compensation expense | 19,069 | — | — | 19,069 | Depreciation, depletion, and amortization | 62,636 | 76,036 | — | 138,672 | |||||||||||||||||||||||||
General and administrative | 22,466 | 33,411 | 105 | 55,982 | Impairment of proved oil and natural gas properties | 18,339 | 10,532 | — | 28,871 | |||||||||||||||||||||||||
Accretion of asset retirement obligations | 547 | 3,469 | — | 4,016 | General and administrative | 38,414 | 30,342 | 431 | 69,187 | |||||||||||||||||||||||||
(Gain) loss on commodity derivative instruments | (8,361 | ) | (21,195 | ) | — | (29,556 | ) | Accretion of asset retirement obligations | 632 | 4,377 | — | 5,009 | ||||||||||||||||||||||
(Gain) loss on sale of properties | (83,370 | ) | (2,848 | ) | — | (86,218 | ) | (Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | — | (34,905 | ) | |||||||||||||||||||
Other, net | (25 | ) | 647 | — | 622 | (Gain) loss on sale of properties | (2 | ) | (9,759 | ) | — | (9,761 | ) | |||||||||||||||||||||
Other, net | 364 | 138 | — | 502 | ||||||||||||||||||||||||||||||
Total costs and expenses | 39,696 | 215,825 | (50,425 | ) | 205,096 | |||||||||||||||||||||||||||||
Total costs and expenses | 146,246 | 190,990 | (369 | ) | 336,867 | |||||||||||||||||||||||||||||
Operating income (loss) | 131,665 | 35,691 | 50,289 | 217,645 | ||||||||||||||||||||||||||||||
Other income (expense): | Operating income | (7,432 | ) | 67,433 | — | 60,001 | ||||||||||||||||||||||||||||
Interest expense, net | (15,947 | ) | (26,047 | ) | — | (41,994 | ) | Other income (expense): | ||||||||||||||||||||||||||
Earnings from equity investments | (24 | ) | — | 24 | — | Interest expense, net | (12,802 | ) | (20,436 | ) | — | (33,238 | ) | |||||||||||||||||||||
Other, net | 81 | — | — | 81 | Amortization of investment premium | — | (194 | ) | — | (194 | ) | |||||||||||||||||||||||
Earnings from equity investments | 4,880 | — | (4,880 | ) | — | |||||||||||||||||||||||||||||
Total other income (expense) | (15,890 | ) | (26,047 | ) | 24 | (41,913 | ) | Other, net | 535 | — | — | 535 | ||||||||||||||||||||||
Income before income taxes | 115,775 | 9,644 | 50,313 | 175,732 | Total other income (expense) | (7,387 | ) | (20,630 | ) | (4,880 | ) | (32,897 | ) | |||||||||||||||||||||
Income tax benefit (expense) | (1,147 | ) | (285 | ) | — | (1,432 | ) | |||||||||||||||||||||||||||
Income before income taxes | (14,819 | ) | 46,803 | (4,880 | ) | 27,104 | ||||||||||||||||||||||||||||
Net income (loss) | $ | 114,628 | $ | 9,359 | $ | 50,313 | $ | 174,300 | Income tax benefit (expense) | 178 | (285 | ) | — | (107 | ) | |||||||||||||||||||
Net income | $ | (14,641 | ) | $ | 46,518 | $ | (4,880 | ) | $ | 26,997 | ||||||||||||||||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 9 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Held-to-Maturity Investments | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2013 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2014 (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment | Amortized | Unrealized | Fair | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment | Amortized | Cost | Gain | Market | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost | (Loss) | Value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Bank Money Market Cash Equivalent | $ | 133,275 | U.S. Bank Money Market Cash Equivalent | $ | 105,184 | $ | — | $ | 105,184 | |||||||||||||||||||||||||||||||||||||||||||||||||
Less: Outside working interest owners share | (64,305 | ) | U.S. Government Treasury Note, maturity of June 30, 2014, and 1.75% coupon | 23,073 | 93 | 23,166 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Less: Outside working interest owners share | (61,884 | ) | (45 | ) | (61,929 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
$ | 68,970 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
$ | 66,373 | $ | 48 | $ | 66,421 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Balances Attributable to Net Working Interest | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2015 | $ | 72,450 | June 30, 2014 | $ | 68,310 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
June 30, 2016 | $ | 76,590 | June 30, 2015 | $ | 72,450 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | $ | 78,660 | June 30, 2016 | $ | 76,590 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | $ | 78,660 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CO2 Minimum Purchase Commitment | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
terms. Amounts shown in the following table represent our minimum commitments as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Service Agreements | Total | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Drilling services | 20,323 | 20,323 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
Compression services | 7,090 | 7,079 | 11 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Commitments to Gatherer before Other Owner Contributions | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of September 30, 2014 were as follows (in thousands): | WildHorse’s minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2013 were as follows (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dubach | Dubberly | Dubach | Dubberly | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | $ | 3,446 | $ | 1,436 | Facility Costs | |||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 13,671 | 11,393 | 2014 | $ | 12,925 | $ | 6,421 | $ | 19,346 | |||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 13,709 | 11,424 | 2015 | 12,925 | 12,842 | 25,767 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | 2016 | 12,961 | 12,878 | 25,839 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | 2017 | 12,925 | 12,842 | 25,767 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 10,766 | 10,697 | 21,463 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 60,715 | $ | 47,725 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 62,502 | $ | 55,680 | $ | 118,182 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
WildHorse’s minimum commitments to the Gatherer, before other owner contributions, as of February 1, 2014 were as follows (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dubach | Dubberly | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Facility Costs | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | $ | 12,510 | $ | 5,212 | $ | 17,722 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 13,671 | 11,393 | 25,064 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 13,709 | 11,424 | 25,133 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | 25,064 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | 23,415 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | $ | 66,333 | $ | 50,065 | $ | 116,398 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Reserves Activity | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following table presents the activity of our environmental reserves for the periods presented: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at beginning of period | $ | 1,469 | $ | 1,747 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Charged to costs and expenses | — | 193 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payments | (892 | ) | (471 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at end of period | $ | 577 | $ | 1,469 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Lease Payment Obligations Under Non-Cancelable Operating Leases | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lease Obligations | Total | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating leases | 20,325 | 2,389 | 2,546 | 2,583 | 2,718 | 2,783 | 7,306 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Wyoming Acquisition [Member] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CO2 Minimum Purchase Commitment | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At September 30, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase commitment | Total | Remainder | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CO2 minimum purchase commitment: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated payment obligation | $ | 62,103 | $ | 3,203 | $ | 12,222 | $ | 12,101 | $ | 11,624 | $ | 7,872 | $ | 15,081 |
Supplemental_Oil_and_Gas_Infor1
Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Capitaized Costs Relating to Oil and Natural Gas Producing Activities | ' | ||||||||||||||||
The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
MRD Segment: | |||||||||||||||||
Evaluated oil and natural gas properties | $ | 1,226,417 | $ | 1,052,219 | |||||||||||||
Unevaluated oil and natural gas properties | 46,413 | 26,589 | |||||||||||||||
Accumulated depletion, depreciation, and amortization | (256,629 | ) | (202,581 | ) | |||||||||||||
Subtotal | $ | 1,016,201 | $ | 876,227 | |||||||||||||
MEMP Segment: | |||||||||||||||||
Evaluated oil and natural gas properties(1) | $ | 1,758,953 | $ | 1,545,402 | |||||||||||||
Unevaluated oil and natural gas properties | — | 5,004 | |||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | (416,617 | ) | (265,710 | ) | |||||||||||||
Subtotal | $ | 1,342,336 | $ | 1,284,696 | |||||||||||||
Eliminations: | |||||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | $ | 49,884 | $ | — | |||||||||||||
Consolidated: | |||||||||||||||||
Evaluated oil and natural gas properties(1) | $ | 2,985,370 | $ | 2,597,621 | |||||||||||||
Unevaluated oil and natural gas properties | 46,413 | 31,593 | |||||||||||||||
Accumulated depletion, depreciation, and amortization(1) | (623,362 | ) | (468,291 | ) | |||||||||||||
Total | $ | 2,408,421 | $ | 2,160,923 | |||||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | ||||||||||||||||
Costs Incurred for Property Acquisitions, Exploration and Development | ' | ||||||||||||||||
Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
MRD Segment: | |||||||||||||||||
Property acquisition costs, proved | $ | 56,108 | $ | 87,857 | |||||||||||||
Property acquisition costs, unproved | 19,975 | 5,293 | |||||||||||||||
Exploration and extension well costs | 13,313 | 212 | |||||||||||||||
Development | 210,440 | 135,951 | |||||||||||||||
Subtotal | $ | 299,836 | $ | 229,313 | |||||||||||||
MEMP Segment: | |||||||||||||||||
Property acquisition costs, proved | $ | 37,786 | $ | 278,246 | |||||||||||||
Property acquisition costs, unproved | — | — | |||||||||||||||
Exploration and extension well costs | — | 42,430 | |||||||||||||||
Development(1) | 145,830 | 62,472 | |||||||||||||||
Subtotal | $ | 183,616 | $ | 383,148 | |||||||||||||
Consolidated: | |||||||||||||||||
Property acquisition costs, proved | $ | 93,894 | $ | 366,103 | |||||||||||||
Property acquisition costs, unproved | 19,975 | 5,293 | |||||||||||||||
Exploration and extension well costs | 13,313 | 42,642 | |||||||||||||||
Development(1) | 356,270 | 198,423 | |||||||||||||||
Total | $ | 483,452 | $ | 612,461 | |||||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | ||||||||||||||||
Weighted Average Benchmark Product Prices | ' | ||||||||||||||||
The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Oil ($/Bbl): | |||||||||||||||||
Spot(1) | $ | 93.42 | $ | 91.33 | |||||||||||||
NGL ($/Bbl): | |||||||||||||||||
Spot(1) | $ | 93.42 | $ | 91.75 | |||||||||||||
Natural Gas ($/MMbtu): | |||||||||||||||||
Spot(2) | $ | 3.67 | $ | 2.75 | |||||||||||||
-1 | The unweighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential. | ||||||||||||||||
-2 | The unweighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. | ||||||||||||||||
MRD [Member] | ' | ||||||||||||||||
Reserve Quantity Information | ' | ||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2013 and 2012, respectively: | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 11,953 | 739,378 | 41,466 | 1,059,895 | |||||||||||||
Extensions and discoveries | 1,794 | 149,974 | 8,319 | 210,652 | |||||||||||||
Purchase of minerals in place | 211 | 31,815 | 1,017 | 39,183 | |||||||||||||
Production | (665 | ) | (34,092 | ) | (1,457 | ) | (46,819 | ) | |||||||||
Sales of minerals in place | (599 | ) | (14,137 | ) | (1,573 | ) | (27,169 | ) | |||||||||
Revision of previous estimates | (1,383 | ) | (70,684 | ) | (5,196 | ) | (110,165 | ) | |||||||||
End of year(1) | 11,311 | 802,254 | 42,576 | 1,125,577 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 3,082 | 245,449 | 12,321 | 337,869 | |||||||||||||
End of year | 3,402 | 263,797 | 13,904 | 367,641 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 8,871 | 493,929 | 29,145 | 722,026 | |||||||||||||
End of year | 7,909 | 538,457 | 28,672 | 757,936 | |||||||||||||
-1 | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 10,834 | 929,335 | 53,031 | 1,312,533 | |||||||||||||
Extensions and discoveries | 689 | 42,019 | 2,778 | 62,819 | |||||||||||||
Purchase of minerals in place | 1,100 | 28,115 | 1,879 | 45,987 | |||||||||||||
Production | (369 | ) | (24,131 | ) | (898 | ) | (31,731 | ) | |||||||||
Sales of minerals in place | (4 | ) | (728 | ) | — | (752 | ) | ||||||||||
Revision of previous estimates | (297 | ) | (235,232 | ) | (15,324 | ) | (328,961 | ) | |||||||||
End of year(1) | 11,953 | 739,378 | 41,466 | 1,059,895 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,107 | 191,557 | 7,644 | 250,073 | |||||||||||||
End of year | 3,082 | 245,449 | 12,321 | 337,869 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 8,727 | 737,778 | 45,387 | 1,062,460 | |||||||||||||
End of year | 8,871 | 493,929 | 29,145 | 722,026 | |||||||||||||
-1 | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||||||||||||||
Estimated Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves | ' | ||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Future cash inflows | $ | 5,722,848 | $ | 4,921,192 | |||||||||||||
Future production costs | (1,587,374 | ) | (1,255,289 | ) | |||||||||||||
Future development costs | (1,352,945 | ) | (1,060,777 | ) | |||||||||||||
Future net cash flows for estimated timing of cash flows(1) | 2,782,529 | 2,605,126 | |||||||||||||||
10% annual discount for estimated timing of cash flows | (1,313,577 | ) | (1,284,531 | ) | |||||||||||||
Standardized measure of discounted future net cash flows(2) | $ | 1,468,952 | $ | 1,320,595 | |||||||||||||
-1 | We are subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas to immateriality we have excluded the impact of this tax. However, had we not been a tax exempt entity future income tax for the years ended December 31, 2013 and 2012 would have been $760,433 and $647,464, respectively. | ||||||||||||||||
-2 | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||
Sources of Changes in Standardized Measure of Discounted Future Net Cash Flows | ' | ||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2013: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Beginning of year | $ | 1,320,595 | $ | 1,386,071 | |||||||||||||
Sale of oil and natural gas produced, net of production costs | (196,444 | ) | (107,316 | ) | |||||||||||||
Purchase of minerals in place | 51,177 | 98,384 | |||||||||||||||
Sale of minerals in place | (54,091 | ) | — | ||||||||||||||
Extensions and discoveries | 301,004 | 127,994 | |||||||||||||||
Changes in prices and costs | (11,336 | ) | (402,202 | ) | |||||||||||||
Previously estimated development costs incurred | 87,297 | 64,390 | |||||||||||||||
Net changes in future development costs | 57,353 | (67,331 | ) | ||||||||||||||
Revisions of previous quantities | (186,804 | ) | (176,788 | ) | |||||||||||||
Accretion of discount | 128,544 | 138,607 | |||||||||||||||
Change in production rates and other | (28,343 | ) | 258,786 | ||||||||||||||
End of year | $ | 1,468,952 | $ | 1,320,595 | |||||||||||||
MEMP [Member] | ' | ||||||||||||||||
Reserve Quantity Information | ' | ||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2013 and 2012, respectively: | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 39,089 | 604,440 | 29,352 | 1,015,095 | |||||||||||||
Extensions and discoveries | 5,655 | 40,770 | 1,747 | 85,180 | |||||||||||||
Purchase of minerals in place | 119 | 16,294 | 258 | 18,554 | |||||||||||||
Production | (1,764 | ) | (35,924 | ) | (1,632 | ) | (56,303 | ) | |||||||||
Sales of minerals in place | — | — | — | — | |||||||||||||
Revision of previous estimates | (3,950 | ) | (18,441 | ) | (879 | ) | (47,421 | ) | |||||||||
End of year(1) | 39,149 | 607,139 | 28,846 | 1,015,105 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 24,515 | 376,932 | 15,947 | 619,704 | |||||||||||||
End of year | 22,265 | 387,548 | 15,959 | 616,893 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 14,574 | 227,508 | 13,405 | 395,391 | |||||||||||||
End of year | 16,884 | 219,591 | 12,887 | 398,212 | |||||||||||||
-1 | MRD Segment’s share of these reserves is 89,837 MMcfe. | ||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Oil | Gas | NGLs | Equivalent | ||||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | ||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 27,150 | 579,751 | 15,045 | 832,913 | |||||||||||||
Extensions and discoveries | 7,501 | 19,869 | 1,053 | 71,192 | |||||||||||||
Purchase of minerals in place | 11,336 | 113,617 | 7,095 | 224,202 | |||||||||||||
Production | (1,519 | ) | (29,744 | ) | (745 | ) | (43,329 | ) | |||||||||
Sales of minerals in place | (4,214 | ) | (4,214 | ) | — | (29,499 | ) | ||||||||||
Revision of previous estimates | (1,165 | ) | (74,839 | ) | 6,904 | (40,384 | ) | ||||||||||
End of year(1)(2) | 39,089 | 604,440 | 29,352 | 1,015,095 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 19,332 | 413,431 | 10,015 | 589,504 | |||||||||||||
End of year | 24,515 | 376,932 | 15,947 | 619,704 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 7,818 | 166,320 | 5,030 | 243,409 | |||||||||||||
End of year | 14,574 | 227,508 | 13,405 | 395,391 | |||||||||||||
-1 | Includes reserves of 406,324 MMcfe attributable to common control acquisitions. | ||||||||||||||||
-2 | MRD Segment’s share of these reserves is 476,550 MMcfe. | ||||||||||||||||
Estimated Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves | ' | ||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Future cash inflows | $ | 6,892,150 | $ | 6,511,776 | |||||||||||||
Future production costs | (2,719,024 | ) | (2,258,554 | ) | |||||||||||||
Future development costs | (685,858 | ) | (620,944 | ) | |||||||||||||
Future net cash flows for estimated timing of cash flows(1) | 3,487,268 | 3,632,278 | |||||||||||||||
10% annual discount for estimated timing of cash flows | (1,879,156 | ) | (2,042,362 | ) | |||||||||||||
Standardized measure of discounted future net cash flows(2)(3) | $ | 1,608,112 | $ | 1,589,916 | |||||||||||||
-1 | MEMP is subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax. MEMP is organized as a pass-through entity for income tax purposes. Had we not been a tax exempt entity our share of future income tax related to our ownership of MEMP for the years ended December 31, 2013 and 2012 would have been $61,300 and $306,297, respectively. | ||||||||||||||||
-2 | Includes $503,021 attributable to the MEMP previous owners for the year ended December 31, 2012. | ||||||||||||||||
-3 | MRD Segment’s share of the standardized measure of discounted future net cash flows was $142,318 and $554,981 for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||
Sources of Changes in Standardized Measure of Discounted Future Net Cash Flows | ' | ||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2013: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Beginning of year | $ | 1,589,916 | $ | 1,499,414 | |||||||||||||
Sale of oil and natural gas produced, net of production costs | (234,520 | ) | (160,023 | ) | |||||||||||||
Purchase of minerals in place | 23,160 | 375,953 | |||||||||||||||
Sale of minerals in place | — | (154,963 | ) | ||||||||||||||
Extensions and discoveries | 136,423 | 265,108 | |||||||||||||||
Changes in income taxes, net | — | 1,947 | |||||||||||||||
Changes in prices and costs | (74,395 | ) | (331,760 | ) | |||||||||||||
Previously estimated development costs incurred | 174,490 | 66,360 | |||||||||||||||
Net changes in future development costs | (74,867 | ) | (1,140 | ) | |||||||||||||
Revisions of previous quantities | (141,122 | ) | (90,587 | ) | |||||||||||||
Accretion of discount | 158,991 | 150,136 | |||||||||||||||
Change in production rates and other | 50,036 | (30,529 | ) | ||||||||||||||
End of year | $ | 1,608,112 | $ | 1,589,916 | |||||||||||||
Background_Organization_and_Ba2
Background, Organization and Basis of Presentation - Additional Information (Detail) (USD $) | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | ||||||||||||||||||||||||||||
Jun. 18, 2014 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Jun. 18, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Jun. 18, 2014 | Jun. 18, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 18, 2014 | Dec. 31, 2013 | Jun. 18, 2014 | Jun. 18, 2014 | Jun. 18, 2014 | Jun. 18, 2014 | Jun. 18, 2014 | Dec. 31, 2013 | Jun. 18, 2014 | Jun. 18, 2014 | Jun. 18, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 01, 2013 | Apr. 30, 2012 | Oct. 01, 2013 | Oct. 01, 2013 | Mar. 28, 2013 | 31-May-12 | Dec. 18, 2013 | Sep. 30, 2014 | Jun. 27, 2014 | Jun. 27, 2014 | Jun. 18, 2014 | Sep. 30, 2014 | Jul. 31, 2013 | Sep. 30, 2014 | 31-May-14 | |
Segment | Segment | Limited Partner [Member] | General Partner [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | Classic [Member] | Classic [Member] | Classic GP[Member] | Classic GP[Member] | Black Diamond [Member] | Beta Operating [Member] | Memorial Resource Finance Corp [Member] | MRD Operating [Member] | Memorial Production Partners GP LLC [Member] | Memorial Production Partners GP LLC [Member] | MEMP GP & MEMP IDRs [Member] | MRD Holdco LLC [Member] | Memorial Production Partners Lp [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | Tanos Energy LLC [Member] | MRD Segment [Member] | MRD Segment [Member] | MRD Segment [Member] | Tanos Energy LLC [Member] | Tanos Energy LLC [Member] | Prospect Energy LLC [Member] | Jackson County [Member] | WHT Energy Partners LLC [Member] | Classic [Member] | PIK notes [Member] | PIK notes [Member] | PIK notes [Member] | PIK notes trustee [Member] | MRD LLC [Member] | MRD [Member] | BlueStone Natural Resources Holdings, LLC [Member] | Limited Partners Subordinated Units [Member] | Golden Energy [Member] | ||||||
Assets [Member] | Sales Revenue, Net [Member] | Production Volume [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | East Texas Acquisition [Member] | East Texas Acquisition [Member] | MRD Holdco [Member] | ||||||||||||||||||||||||||||||||||||||||
Maximum [Member] | Assets [Member] | Sales Revenue, Net [Member] | Production Volume [Member] | |||||||||||||||||||||||||||||||||||||||||||||
Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Initial public offering | 21,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common unit price per share | ' | ' | ' | ' | ' | ' | $19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from initial public offering | $380,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Initial public offering completion date | 18-Jun-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ownership percentage in MRD LLC after contribution from Funds and prior to redemption of PIK notes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' |
Proceeds for sale of subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ownership interest percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 99.90% | 99.89% | ' | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | ' | 100.00% | 50.00% | ' | ' | 89.45% | ' | ' | ' | 98.94% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock, shares issued | ' | 193,559,211 | ' | 0 | ' | ' | ' | ' | ' | ' | 42,334,323 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 128,665,677 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate principal amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | 350,000,000 | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, maturity date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Dec-18 | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate, minimum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 10.00% | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate, maximum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.75% | 10.75% | ' | ' | ' | ' | ' | ' | ' |
Membership interest percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash consideration paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000,000 | ' | ' | ' |
Credit facility used | ' | 2,464,800,000 | 478,055,000 | 1,132,755,000 | 619,450,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 614,500,000 | ' | ' | ' |
Senior PIK Toggle Notes, Redemption price percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 102.00% | ' | ' | ' | ' | ' | ' | ' |
Senior PIK Toggle Notes, Redemption date | ' | 16-Jul-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Sale of assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 117,900,000 | ' | 6,700,000 |
Subordinated units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,360,912 | ' |
Irrevocable deposits | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 360,000,000 | 360,000,000 | ' | ' | ' | ' | ' |
Partnership ownership percentage | ' | ' | ' | ' | ' | ' | ' | 99.90% | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of reportable business segments | ' | 2 | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business acquisition purchase price | ' | ' | ' | ' | ' | $19,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $77,400,000 | $18,500,000 | $16,300,000 | $2,600,000 | $200,000,000 | $27,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incentive distribution rights | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
BlueStone as a percentage of consolidated and MRD segment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | 3.00% | 2.00% | ' | 1.00% | 7.00% | 4.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
General partner interest percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.41% | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
General partner interest units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 61,300 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Acquired number of outstanding units | ' | ' | ' | 5,360,912 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Limited partner interest percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 99.59% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 30, 2014 | |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Minimum percentage tax benefit to be realized upon final settlement | 50.00% | ' | ' | ' | ' |
Uncertain tax benefits | $0 | ' | $0 | $0 | ' |
Deferred tax liabilities | ' | ' | 3,200,000 | 3,100,000 | 43,300,000 |
Capitalized exploratory drilling costs | ' | ' | 0 | 0 | ' |
Impairment of proved oil and natural gas properties | 67,181,000 | 21,000 | 6,600,000 | 28,871,000 | ' |
Amortization expense, including write-offs of debt issuance costs | 5,492,000 | 6,193,000 | 8,343,000 | 3,584,000 | ' |
Income tax benefit (expense) | -14,398,000 | -1,432,000 | -1,619,000 | -107,000 | ' |
Pro Forma [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Income tax benefit (expense) | ' | ' | ($55,154,000) | ($9,592,000) | ' |
Federal and state tax rate | ' | ' | 36.06% | 35.39% | ' |
TEXAS [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Taxable margin rate | 1.00% | ' | 1.00% | ' | ' |
Minimum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Estimated useful lives | '3 years | ' | '3 years | ' | ' |
Maximum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Estimated useful lives | '5 years | ' | '5 years | ' | ' |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Schedule of Current Accrued Liabilities (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Accounting Policies [Abstract] | ' | ' | ' |
Accrued capital expenditures | $77,716 | $48,579 | $14,352 |
Accrued lease operating expense | 18,142 | 13,240 | 6,701 |
Accrued general and administrative expenses | 11,986 | 14,485 | 2,290 |
Accrued ad valorem and production taxes | 26,466 | 3,541 | 3,753 |
Accrued interest payable | 41,857 | 11,934 | 1,239 |
Accrued environmental | 571 | 577 | 1,012 |
Other miscellaneous, including operator advances | 2,643 | 5,774 | 4,140 |
Accrued liabilities | $179,381 | $98,130 | $33,487 |
Acquisitions_and_Divestitures_1
Acquisitions and Divestitures - Acquisition Related Costs (Detail) (General and administrative expense [Member], USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
General and administrative expense [Member] | ' | ' | ' | ' |
Business Acquisition [Line Items] | ' | ' | ' | ' |
Acquisition-related costs | $5,480 | $5,073 | $8,313 | $4,538 |
Acquisitions_and_Divestitures_2
Acquisitions and Divestitures - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 9 Months Ended | 0 Months Ended | ||||||
In Millions, unless otherwise specified | Apr. 30, 2013 | Jul. 11, 2012 | Sep. 18, 2012 | Dec. 31, 2012 | Oct. 11, 2012 | Dec. 31, 2012 | Oct. 11, 2012 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | 9-May-14 | Sep. 30, 2013 | Dec. 31, 2013 | Jan. 01, 2013 | Jan. 01, 2013 | Jan. 01, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | 10-May-13 | Sep. 30, 2013 | Dec. 31, 2013 | 1-May-12 | Dec. 31, 2012 | Sep. 28, 2012 | Dec. 31, 2012 | Jul. 31, 2012 | Jul. 31, 2012 | Dec. 31, 2012 | Jul. 31, 2013 | Sep. 30, 2013 | Jul. 01, 2014 |
WildHorse Resources, LLC [Member] | Garza County, Texas [Member] | Ector County, Texas [Member] | Subsidiaries [Member] | NGP Controlled Entity [Member] | NGP Controlled Entity [Member] | Received upon closing [Member] | Series of Individually Immaterial Business Acquisitions [Member] | Eagle Ford Acquisition [Member] | Eagle Ford Acquisition [Member] | Golden Energy [Member] | Propel Energy [Member] | Propel Energy [Member] | Tanos [Member] | Tanos [Member] | Tanos [Member] | Tanos [Member] | Tanos [Member] | Tanos [Member] | Tanos [Member] | Black Diamond [Member] | East Texas Acquisition and Rockies Acquisition [Member] | East Texas Acquisition and Rockies Acquisition [Member] | Undisclosed Seller Acquisition [Member] | Undisclosed Seller Acquisition [Member] | Goodrich Acquisition [Member] | Goodrich Acquisition [Member] | Texas And New Mexico [Member] | Menemsha Acquisition [Member] | Menemsha Acquisition [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | Wyoming Acquisition [Member] | |
NGP Controlled Entity [Member] | Leasehold Improvements [Member] | Natural Gas Pipe Lines [Member] | Natural Gas Pipe Lines [Member] | Natural Gas Pipe Lines [Member] | Oil And Natural Gas Properties [Member] | Oil And Natural Gas Properties [Member] | Non Operated Oil And Natural Gas Properties [Member] | Non Operated Oil And Natural Gas Properties [Member] | |||||||||||||||||||||||||
Minimum [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payments to acquire oil and gas properties and leases | $67.10 | ' | ' | ' | ' | ' | ' | $10.20 | $168.10 | ' | ' | $8.50 | $9.30 | ' | ' | ' | ' | ' | ' | ' | ' | $29.40 | $29.40 | $112.10 | ' | $90.40 | ' | $147.90 | $74.70 | ' | ' | ' | $911.70 |
Business acquisition, revenues | ' | ' | ' | ' | ' | ' | ' | ' | 25.9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22.1 | ' | 4.6 | ' | ' | 4.9 | ' | ' | 41.6 |
Business acquisition, earnings | ' | ' | ' | ' | ' | ' | ' | ' | 13.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.2 | ' | 2 | ' | ' | 0.9 | ' | ' | 16.5 |
Percentage of leasehold interest acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from divestitures | ' | 26.1 | 4.7 | 3.3 | 40.1 | ' | 38.1 | ' | ' | ' | 7.6 | ' | ' | ' | 1.5 | 2 | 2.9 | 2.9 | ' | ' | 33 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 117.9 | 117.9 | ' |
Gain (loss) on sale of oil and gas properties | ' | 7.6 | 2.2 | -0.1 | ' | ' | ' | ' | ' | ' | -3.2 | ' | ' | 1.4 | ' | ' | ' | ' | 1.4 | 1.4 | -6.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 89.5 | 90.2 | ' |
Period for drilling any new wells | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contingent consideration related to sale of natural gas pipeline | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net book value of oil and gas properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity gain on sale of oil and gas properties to affiliates | ' | ' | ' | ' | ' | $6.30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Acquisitions_and_Divestitures_3
Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) (USD $) | Mar. 31, 2014 | Apr. 30, 2013 | Sep. 06, 2013 | Aug. 30, 2013 | 1-May-12 | Sep. 28, 2012 | Jul. 31, 2012 | Dec. 31, 2012 | Jul. 01, 2014 |
In Thousands, unless otherwise specified | Eagle Ford Acquisition [Member] | Louisiana [Member] | East Texas Acquisition [Member] | Rockies Acquisition [Member] | Undisclosed Seller Acquisition [Member] | Goodrich Acquisition [Member] | Menemsha Acquisition [Member] | Previous Owners [Member] | Wyoming Acquisition [Member] |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Oil and gas properties | $168,606 | $68,887 | $9,974 | $20,744 | $115,633 | $91,187 | $75,114 | $77,764 | $922,686 |
Prepaid expenses and other current assets | ' | ' | ' | ' | ' | 425 | ' | ' | ' |
Revenue payable | ' | ' | ' | ' | -1,602 | -875 | ' | ' | -444 |
Asset retirement obligations | -285 | -1,789 | -78 | -1,163 | -1,592 | -161 | -408 | -4,558 | -3,328 |
Accrued liabilities | -250 | ' | ' | -118 | -297 | -153 | ' | ' | -7,237 |
Total identifiable net assets | $168,071 | $67,098 | $9,896 | $19,463 | $112,142 | $90,423 | $74,706 | $73,206 | $911,677 |
Acquisitions_and_Divestitures_4
Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2012 |
Business Combinations [Abstract] | ' | ' | ' |
Revenues | $764,084 | $561,359 | $431,061 |
Net income (loss) | ($931,903) | $218,870 | $40,940 |
Basic and diluted earnings per share | ($4.94) | ' | ' |
Fair_Value_Measurements_of_Fin2
Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements [Member], USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Assets: | ' | ' | ' |
Fair value of derivative asset | $129,806 | $105,938 | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 78,254 | 63,824 | 52,776 |
Interest rate derivatives [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 95 | 884 | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 3,712 | 5,590 | 6,838 |
Significant Unobservable Inputs (Level 1) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 0 | ' | ' |
Significant Unobservable Inputs (Level 1) [Member] | Interest rate derivatives [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 0 | ' | ' |
Significant Unobservable Inputs (Level 2) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 129,806 | 105,938 | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 78,254 | 63,824 | 52,776 |
Significant Unobservable Inputs (Level 2) [Member] | Interest rate derivatives [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 95 | 884 | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 3,712 | 5,590 | 6,838 |
Significant Unobservable Inputs (Level 3) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 0 | ' | ' |
Significant Unobservable Inputs (Level 3) [Member] | Interest rate derivatives [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 0 | ' | ' |
Commodity derivatives [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 129,711 | 105,054 | 95,586 |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 74,542 | 58,234 | 45,938 |
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 1) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 0 | ' | ' |
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 2) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 129,711 | 105,054 | 95,586 |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | 74,542 | 58,234 | 45,938 |
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member] | ' | ' | ' |
Assets: | ' | ' | ' |
Fair value of derivative asset | 0 | ' | ' |
Liabilities: | ' | ' | ' |
Fair value of derivative liability | $0 | ' | ' |
Fair_Value_Measurements_of_Fin3
Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | ||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2013 |
Elkhorn and Canyon Fields (Member) | East Texas Properties [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | |||||
Maximum [Member] | Maximum [Member] | |||||||||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment of proved oil and natural gas properties | $67,181 | $21 | $6,600 | $28,871 | $8,000 | $20,900 | $67,200 | $67,200 | $100 | $100 |
Risk_Management_and_Derivative2
Risk Management and Derivative Instruments - Additional Information (Detail) (USD $) | 9 Months Ended | 0 Months Ended | 9 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2014 | Jul. 02, 2014 | Sep. 30, 2014 |
Interest rate swaps [Member] | MEMP [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' |
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk | $29 | ' | $37.50 |
Aggregate termination amount paid to counterparties | ' | $0.70 | ' |
Risk_Management_and_Derivative3
Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2014 | Dec. 31, 2013 | |
MMBTU | MMBTU | |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 4,540,000 | ' |
Weighted-average fixed price | 4.18 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 730,000 | ' |
Weighted-average floor price | 4.11 | ' |
Weighted-average ceiling price | 5.15 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,270,000 | ' |
Spread | -0.08 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,580,200 | ' |
Weighted-average fixed price | 4.34 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 340,000 | ' |
Weighted-average floor price | 5 | ' |
Weighted-average ceiling price | 6.31 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,830,000 | ' |
Spread | -0.09 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 120,000 | ' |
Weighted-average sold strike price | 5.17 | ' |
Weighted-average bought strike price | 6.53 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,260,000 | ' |
Spread | -0.09 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 380,000 | ' |
Spread | -0.11 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 190,000 | ' |
Spread | -0.07 | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 94.43 | ' |
Average Monthly Volume (Bbls) | 56,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | 86.67 | ' |
Weighted-average ceiling price | 112.33 | ' |
Average Monthly Volume (Bbls) | 12,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 95.83 | ' |
Average Monthly Volume (Bbls) | 283,452 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | 82.83 | ' |
Weighted-average ceiling price | 105.31 | ' |
Average Monthly Volume (Bbls) | 23,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -4.32 | ' |
Average Monthly Volume (Bbls) | 134,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | 60,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -9.25 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | 40,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -3.68 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | 34,000 | ' |
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | 3.61 | ' |
Remaining 2014 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 44.84 | ' |
Average Monthly Volume (Bbls) | 184,000 | ' |
Remaining 2014 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 43.13 | ' |
Average Monthly Volume (Bbls) | 167,500 | ' |
2015 [Member] | Put Option [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 85 | ' |
Average Monthly Volume (Bbls) | 26,000 | ' |
Weighted-average deferred premium | -3.8 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,250,000 | 880,000 |
Weighted-average fixed price | 4.08 | 4.19 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,580,000 | 130,000 |
Weighted-average floor price | 4.14 | 4 |
Weighted-average ceiling price | 4.61 | 4.64 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 180,000 |
Spread | ' | -0.09 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,730,000 | ' |
Spread | -0.09 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,605,278 | 2,145,278 |
Weighted-average fixed price | 4.28 | 4.3 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 350,000 | 350,000 |
Weighted-average floor price | 4.62 | 4.62 |
Weighted-average ceiling price | 5.8 | 5.8 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,940,000 | ' |
Spread | -0.12 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 80,000 | 80,000 |
Weighted-average sold strike price | 5.25 | 5.25 |
Weighted-average bought strike price | 6.75 | 6.75 |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,280,000 | ' |
Spread | -0.11 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 150,000 | ' |
Spread | -0.08 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 210,000 | ' |
Spread | -0.25 | ' |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 300,000 | ' |
Spread | -0.09 | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 93.86 | 88.5 |
Average Monthly Volume (Bbls) | 33,500 | 6,000 |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | 85 | 85 |
Weighted-average ceiling price | 101.35 | 101.35 |
Average Monthly Volume (Bbls) | 2,000 | 2,000 |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 90.96 | 93.07 |
Average Monthly Volume (Bbls) | 314,281 | 148,281 |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | 80 | 80 |
Weighted-average ceiling price | 94 | 94 |
Average Monthly Volume (Bbls) | 5,000 | 5,000 |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -7.07 | -9.73 |
Average Monthly Volume (Bbls) | 97,500 | 57,500 |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | 57,500 | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -9.73 | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | 40,000 | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | -3.25 | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2015 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 41.61 | ' |
Average Monthly Volume (Bbls) | 151,000 | ' |
2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 43.02 | 35.04 |
Average Monthly Volume (Bbls) | 149,200 | 112,800 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,670,000 | 670,000 |
Weighted-average fixed price | 4.18 | 4.32 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,100,000 | ' |
Weighted-average floor price | 4 | ' |
Weighted-average ceiling price | 4.71 | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 220,000 |
Spread | ' | -0.08 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 220,000 | ' |
Spread | -0.08 | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,692,442 | 2,342,442 |
Weighted-average fixed price | 4.4 | 4.42 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,635,000 | ' |
Spread | -0.06 | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average sold strike price | ' | ' |
Weighted-average bought strike price | ' | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,500,000 | ' |
Spread | 0.07 | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 135,000 | ' |
Spread | 0.07 | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | 80 | ' |
Weighted-average ceiling price | 99.7 | ' |
Average Monthly Volume (Bbls) | 27,000 | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 85.83 | 86.85 |
Average Monthly Volume (Bbls) | 332,813 | 142,313 |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2016 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 39.75 | ' |
Average Monthly Volume (Bbls) | 148,500 | ' |
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 39.28 | ' |
Average Monthly Volume (Bbls) | 55,000 | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,270,000 | 520,000 |
Weighted-average fixed price | 4.3 | 4.45 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,050,000 | ' |
Weighted-average floor price | 4 | ' |
Weighted-average ceiling price | 5.06 | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 200,000 |
Spread | ' | -0.08 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 200,000 | ' |
Spread | -0.08 | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,450,067 | 2,230,067 |
Weighted-average fixed price | 4.31 | 4.31 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 300,000 | ' |
Spread | -0.05 | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average sold strike price | ' | ' |
Weighted-average bought strike price | ' | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 300,000 | ' |
Spread | -0.05 | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 87.62 | ' |
Average Monthly Volume (Bbls) | 9,500 | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 84.38 | 85.96 |
Average Monthly Volume (Bbls) | 326,600 | 130,600 |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | LLS Crude basis swaps [Member] | W T I | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
2017 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2017 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,500,000 | ' |
Weighted-average fixed price | 4.3 | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 2,160,000 | 2,060,000 |
Weighted-average fixed price | 4.51 | 4.52 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average sold strike price | ' | ' |
Weighted-average bought strike price | ' | ' |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 87 | ' |
Average Monthly Volume (Bbls) | 7,625 | ' |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 83.74 | 85.62 |
Average Monthly Volume (Bbls) | 312,000 | 122,000 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2018 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2018 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | 1,914,583 | 1,814,583 |
Weighted-average fixed price | 4.75 | 4.77 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Spread | ' | ' |
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | ' |
Weighted-average sold strike price | ' | ' |
Weighted-average bought strike price | ' | ' |
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | 85.52 | 85 |
Average Monthly Volume (Bbls) | 160,000 | 40,000 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | ' |
Weighted-average ceiling price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2019 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | ' |
Average Monthly Volume (Bbls) | ' | ' |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 1,190,000 |
Weighted-average fixed price | ' | 4.1 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 330,000 |
Weighted-average floor price | ' | 4.09 |
Weighted-average ceiling price | ' | 5.24 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 270,000 |
Spread | ' | -0.07 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 2,575,458 |
Weighted-average fixed price | ' | 4.34 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 340,000 |
Weighted-average floor price | ' | 4.93 |
Weighted-average ceiling price | ' | 6.12 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 2,822,083 |
Spread | ' | -0.09 |
2014 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Volume (MMBtu) | ' | 120,000 |
Weighted-average sold strike price | ' | 5.08 |
Weighted-average bought strike price | ' | 6.31 |
2014 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | 91.66 |
Average Monthly Volume (Bbls) | ' | 18,000 |
2014 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | 85 |
Weighted-average ceiling price | ' | 117.5 |
Average Monthly Volume (Bbls) | ' | 8,000 |
2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | 95.82 |
Average Monthly Volume (Bbls) | ' | 136,444 |
2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average floor price | ' | 82.83 |
Weighted-average ceiling price | ' | 105.31 |
Average Monthly Volume (Bbls) | ' | 23,000 |
2014 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Spread | ' | -9.21 |
Average Monthly Volume (Bbls) | ' | 57,292 |
2014 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | 64.27 |
Average Monthly Volume (Bbls) | ' | 18,000 |
2014 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed price | ' | 36.23 |
Average Monthly Volume (Bbls) | ' | 118,500 |
Risk_Management_and_Derivative4
Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) (Interest rate swaps [Member], USD $) | 9 Months Ended | 12 Months Ended |
In Thousands, unless otherwise specified | Sep. 30, 2014 | Dec. 31, 2013 |
Remaining 2014 [Member] | MEMP [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | $248,333 | ' |
Weighted-average fixed rate | 1.30% | ' |
Floating rate | '1 Month LIBOR | ' |
2015 [Member] | MEMP [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | 280,833 | 280,833 |
Weighted-average fixed rate | 1.42% | 1.42% |
Floating rate | '1 Month LIBOR | '1 Month LIBOR |
2015 [Member] | MRD [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | ' | 100,000 |
Weighted-average fixed rate | ' | 0.76% |
Floating rate | ' | '1 Month LIBOR |
2016 [Member] | MEMP [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | 150,000 | 150,000 |
Weighted-average fixed rate | 1.19% | 1.19% |
Floating rate | '1 Month LIBOR | '1 Month LIBOR |
2016 [Member] | MRD [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Weighted-average fixed rate | ' | ' |
Floating rate | ' | '- |
2014 [Member] | MEMP [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | ' | 173,958 |
Weighted-average fixed rate | ' | 1.31% |
Floating rate | ' | '1 Month LIBOR |
2014 [Member] | MRD [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Average Monthly Notional | ' | $118,750 |
Weighted-average fixed rate | ' | 0.77% |
Floating rate | ' | '1 Month LIBOR |
Risk_Management_and_Derivative5
Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Net recorded fair value | $37,421 | $9,289 | $41,921 |
Asset Derivatives, Net recorded fair value | 34,515 | 48,616 | 17,179 |
Liability Derivatives, Net recorded fair value | 5,109 | 9,711 | 4,667 |
Liability Derivatives, Net recorded fair value | 15,275 | 6,080 | 11,623 |
Short-term derivative instruments [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | 48,405 | 22,604 | 48,901 |
Asset Derivatives, Netting arrangements | -10,984 | -13,315 | -6,980 |
Asset Derivatives, Net recorded fair value | 37,421 | 9,289 | 41,921 |
Liability Derivatives, Gross fair value | 16,093 | 23,026 | 11,647 |
Liability Derivatives, Netting arrangements | -10,984 | -13,315 | -6,980 |
Liability Derivatives, Net recorded fair value | 5,109 | 9,711 | 4,667 |
Short-term derivative instruments [Member] | Commodity contracts [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | 48,405 | 21,759 | 48,901 |
Liability Derivatives, Gross fair value | 12,458 | 19,739 | 8,072 |
Short-term derivative instruments [Member] | Interest rate swaps [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | ' | 845 | ' |
Liability Derivatives, Gross fair value | 3,635 | 3,287 | 3,575 |
Long-term derivative instruments [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | 81,401 | 83,334 | 46,685 |
Asset Derivatives, Netting arrangements | -46,886 | -34,718 | -29,506 |
Asset Derivatives, Net recorded fair value | 34,515 | 48,616 | 17,179 |
Liability Derivatives, Gross fair value | 62,161 | 40,798 | 41,129 |
Liability Derivatives, Netting arrangements | -46,886 | -34,718 | -29,506 |
Liability Derivatives, Net recorded fair value | 15,275 | 6,080 | 11,623 |
Long-term derivative instruments [Member] | Commodity contracts [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | 81,306 | 83,295 | 46,685 |
Liability Derivatives, Gross fair value | 62,084 | 38,495 | 37,866 |
Long-term derivative instruments [Member] | Interest rate swaps [Member] | ' | ' | ' |
Derivative Instruments and Hedges, Assets [Abstract] | ' | ' | ' |
Asset Derivatives, Gross fair value | 95 | 39 | ' |
Liability Derivatives, Gross fair value | $77 | $2,303 | $3,263 |
Risk_Management_and_Derivative6
Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | ' | ' | ' | ' |
(Gain) loss on commodity derivative instruments | $11,580 | ($29,556) | ($29,294) | ($34,905) |
Interest expense, net | 104,928 | 41,994 | 69,250 | 33,238 |
Commodity contracts [Member] | ' | ' | ' | ' |
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | ' | ' | ' | ' |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
Interest rate derivatives [Member] | ' | ' | ' | ' |
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | ' | ' | ' | ' |
Interest expense, net | $1,157 | $69 | ($239) | $5,582 |
Asset_Retirement_Obligations_S
Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | ' | ' | ' | ' |
Asset retirement obligations at beginning of period | $111,769 | $102,380 | $102,380 | $90,699 |
Liabilities added from acquisitions or drilling | 5,053 | ' | 4,227 | 7,962 |
Liabilities removed upon sale of wells | -1,636 | ' | -1,765 | -1,931 |
Liabilities removed upon plugging and abandoning | -344 | ' | -170 | -119 |
Revision of estimates | 67 | ' | 1,516 | 760 |
Accretion expense | 4,601 | 4,016 | 5,581 | 5,009 |
Asset retirement obligations at end of period | 119,510 | ' | 111,769 | 102,380 |
Less: Current portion | ' | ' | 90 | 390 |
Asset retirement obligations-long-term portion | $119,510 | ' | $111,679 | $101,990 |
Restricted_Investments_Restric
Restricted Investments - Restricted Investment Balance (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | $76,268 | $73,385 | $68,024 |
BOEM platform abandonment [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 68,970 | 66,373 | 61,389 |
BOEM lease bonds [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 794 | 794 | 776 |
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 2,592 | 2,306 | 1,959 |
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 3,005 | 3,005 | 3,000 |
SPBPC Collateral City of Long Beach pipeline facility permit [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 500 | 500 | 500 |
SPBPC Collateral Federal pipeline right-of-way bond [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | 307 | 307 | 300 |
SPBPC Collateral Port of Long Beach pipeline license [Member] | ' | ' | ' |
Schedule of Investments [Line Items] | ' | ' | ' |
Restricted investments | $100 | $100 | $100 |
Long_Term_Debt_Consolidated_an
Long Term Debt - Consolidated and Combined Debt Obligations (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | |||||
Debt Instrument [Line Items] | ' | ' | ' | ||
Total long-term debt | $2,111,800 | $1,663,217 | $939,382 | ||
MRD [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Long-term debt | 628,000 | 871,150 | 309,200 | ||
MRD [Member] | PIK notes [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Senior Notes | ' | 350,000 | [1] | ' | |
MRD [Member] | 1.0 billion revolving credit facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 80,000 | ||
MRD [Member] | Senior Pik Toggle Notes Unamortized Discounts [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Unamortized discounts | ' | -6,950 | ' | ||
MRD [Member] | 2.0 billion revolving credit facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | 28,000 | ' | ' | ||
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Senior Notes | 600,000 | [2] | ' | ' | |
MRD [Member] | WildHorse Resources, LLC [Member] | 1.0 billion revolving credit facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | 203,100 | 202,200 | ||
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | 325,000 | ' | ||
MRD [Member] | Black Diamond [Member] | 150.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 27,000 | ||
MEMP [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Long-term debt | 1,483,800 | 792,067 | 630,182 | ||
MEMP [Member] | 2.0 billion revolving credit facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | 301,000 | 103,000 | 371,000 | ||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Senior Notes | 700,000 | [2] | 700,000 | [2] | ' |
MEMP [Member] | Unamortized Discounts [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Unamortized discounts | -17,200 | -10,933 | ' | ||
MEMP [Member] | 6.875% Senior Unsecurred Notes Due August 2022 [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Senior Notes | 500,000 | [3] | ' | ' | |
MEMP [Member] | WHT Energy Partners LLC [Member] | 400.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 89,300 | ||
MEMP [Member] | Tanos Energy LLC [Member] | 250.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 25,250 | ||
MEMP [Member] | Stanolind [Member] | 250.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 85,750 | ||
MEMP [Member] | Boaz [Member] | 75.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 29,500 | ||
MEMP [Member] | Crown [Member] | 75.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | 13,882 | ||
MEMP [Member] | Propel Energy [Member] | 200.0 Million Revolving Credit Facility [Member] | ' | ' | ' | ||
Debt Instrument [Line Items] | ' | ' | ' | ||
Credit facility | ' | ' | $15,500 | ||
[1] | The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||
[2] | The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||
[3] | The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. |
Long_Term_Debt_Consolidated_an1
Long Term Debt - Consolidated and Combined Debt Obligations (Parenthetical) (Detail) (USD $) | 0 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | ||||||||||||||||
In Millions, unless otherwise specified | Dec. 18, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 |
PIK notes [Member] | PIK notes [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | |
PIK notes [Member] | 1.0 billion revolving credit facility [Member] | 1.0 billion revolving credit facility [Member] | 1.0 billion revolving credit facility [Member] | 1.0 billion revolving credit facility [Member] | 325.0 Million Lien Term Facility [Member] | 150.0 Million Revolving Credit Facility [Member] | 150.0 Million Revolving Credit Facility [Member] | 150.0 Million Revolving Credit Facility [Member] | 2.0 billion revolving credit facility [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | 2.0 billion revolving credit facility [Member] | 2.0 billion revolving credit facility [Member] | 2.0 billion revolving credit facility [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 400.0 Million Revolving Credit Facility [Member] | 250.0 Million Revolving Credit Facility [Member] | 250.0 Million Revolving Credit Facility [Member] | 75.0 Million Revolving Credit Facility [Member] | 75.0 Million Revolving Credit Facility [Member] | 200.0 Million Revolving Credit Facility [Member] | 6.875% Senior Unsecurred Notes Due August 2022 [Member] | 6.875% Senior Unsecurred Notes Due August 2022 [Member] | |||
WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | Black Diamond [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | WHT Energy Partners LLC [Member] | Tanos Energy LLC [Member] | Stanolind [Member] | Boaz [Member] | Crown [Member] | Propel Energy [Member] | |||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit facilities | ' | ' | ' | $1,000 | ' | $1,000 | $1,000 | $325 | $150 | $150 | $150 | $2,000 | ' | ' | $2,000 | $2,000 | $2,000 | ' | ' | $400 | $250 | $250 | $75 | $75 | $200 | ' | ' |
Debt Instrument, maturity date | ' | 15-Dec-18 | 15-Dec-18 | 31-Dec-13 | ' | 30-Apr-18 | 30-Apr-18 | 31-Dec-18 | ' | ' | ' | 30-Jun-19 | 31-Jul-22 | ' | 31-Mar-18 | 31-Mar-18 | 31-Mar-18 | 31-May-21 | 1-May-21 | ' | ' | 31-Jul-17 | ' | ' | 30-Jun-15 | 31-Aug-22 | ' |
Termination date of revolving credit facility | ' | ' | ' | ' | 30-Jun-14 | ' | ' | 30-Jun-14 | 30-Nov-13 | 31-Aug-13 | 31-Aug-13 | ' | ' | ' | ' | ' | ' | ' | ' | 31-Mar-13 | 30-Apr-13 | ' | 31-Oct-13 | 31-Oct-13 | ' | ' | ' |
Debt interest rate, minimum | 10.00% | 10.00% | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior notes redemption date | ' | ' | 30-Jun-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate, maximum | 10.75% | 10.75% | 10.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.88% | 5.88% | ' | ' | ' | 7.63% | 7.63% | ' | ' | ' | ' | ' | ' | 6.88% | 6.88% |
Estimated fair value of fixed rate debt | ' | ' | $348.30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $582 | ' | ' | ' | ' | $700 | $721 | ' | ' | ' | ' | ' | ' | $475 | ' |
Long_Term_Debt_Borrowing_Base_
Long Term Debt - Borrowing Base Credit Facility (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Credit Facilities [Line Items] | ' | ' |
Borrowing base | ' | $1,145,000 |
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | ' | ' |
Credit Facilities [Line Items] | ' | ' |
Borrowing base | 668,500 | ' |
MRD [Member] | 1.0 billion revolving credit facility [Member] | WildHorse Resources, LLC [Member] | ' | ' |
Credit Facilities [Line Items] | ' | ' |
Borrowing base | ' | 300,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | ' | ' |
Credit Facilities [Line Items] | ' | ' |
Borrowing base | $1,315,000 | $845,000 |
Long_Term_Debt_Borrowing_Base_1
Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MEMP [Member] | MEMP [Member] |
2.0 Billion Revolving Credit Facility Due June 2019 [Member] | 1.0 billion revolving credit facility [Member] | 1.0 billion revolving credit facility [Member] | 1.0 billion revolving credit facility [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |
WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | |||||
Credit Facilities [Line Items] | ' | ' | ' | ' | ' | ' |
Revolving credit facility | $2,000 | $1,000 | $1,000 | $1,000 | $2,000 | $2,000 |
Long_Term_Debt_Borrowing_Base_2
Long Term Debt - Borrowing Base - Additional Information (Detail) (USD $) | Dec. 31, 2013 | Jun. 18, 2014 | Nov. 22, 2013 | Nov. 01, 2013 | Oct. 01, 2013 | Apr. 25, 2013 | Nov. 20, 2012 | Jul. 13, 2012 | Oct. 03, 2014 | Oct. 03, 2014 |
In Thousands, unless otherwise specified | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Subsequent Event [Member] | Subsequent Event [Member] | |
MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | Revolving Credit Facility [Member] | M E M P | ||
MRD [Member] | Revolving Credit Facility [Member] | |||||||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Borrowing base | $1,145,000 | $725,000 | $60,000 | $100,000 | $120,000 | $170,000 | $120,000 | $35,000 | $725,000 | $1,440,000 |
Long_Term_Debt_MRD_Revolving_C
Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 18, 2014 | Dec. 18, 2013 | Nov. 22, 2013 | Jul. 13, 2012 | Jun. 18, 2014 | Nov. 22, 2013 | Nov. 01, 2013 | Oct. 01, 2013 | Apr. 25, 2013 | Nov. 20, 2012 | Jul. 13, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 |
Minimum [Member] | Maximum [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | ||
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | ||||
Federal Funds Effective Rate [member] | Adjusted London Interbank Offered Rate [member] | Minimum [Member] | Maximum [Member] | Range 1 [Member] | Range 1 [Member] | Range 2 [Member] | Range 2 [Member] | |||||||||||||||
Optional Base Rate [member] | Optional Base Rate [member] | Alternative Base Rate [member] | London Interbank Offered Rate (LIBOR) [Member] | Alternative Base Rate [member] | London Interbank Offered Rate (LIBOR) [Member] | |||||||||||||||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility expiration term | ' | ' | ' | '5 years | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, aggregate maximum borrowing amount | ' | ' | ' | ' | ' | ' | ' | $2,000,000,000 | ' | ' | ' | ' | $1,000,000,000 | $50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, initial borrowing base | 1,145,000,000 | ' | ' | ' | ' | ' | ' | 725,000,000 | 60,000,000 | 100,000,000 | 120,000,000 | 170,000,000 | 120,000,000 | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate elected capacity of revolving credit | ' | ' | ' | ' | ' | ' | ' | 725,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Lien percentage of assets for credit facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' |
Line of credit, additional margin rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.50% | 1.00% | ' | ' | 0.50% | 1.50% | 1.50% | 2.50% |
Line of credit, adjusted description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%) | ' | ' | ' | ' | ' | ' | ' |
Percentage of revolving unused commitment fee | ' | 0.38% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.38% | 0.50% | ' | ' | ' | ' |
Debt instrument interest coverage ratio | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.5 | ' | ' | ' | ' | ' |
Debt instrument, current asset to current liabilities ratio | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' |
Pledged subordinated units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,360,912 | ' | ' | ' | ' | ' | ' | ' | ' |
Pledged common units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,061,294 | ' | ' | ' | ' | ' | ' | ' | ' |
Pledged equity securities sold | ' | ' | ' | ' | ' | 7,061,294 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Indebtedness then outstanding under revolving credit facility paid off in full | ' | ' | ' | ' | $59,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long_Term_Debt_MRD_5875_Senior
Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) (5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member], USD $) | 0 Months Ended |
In Millions, unless otherwise specified | Jul. 10, 2014 |
Debt Obligations [Line Items] | ' |
Senior unsecured notes maturity date | 1-Jul-22 |
Other event of default minimum note holder percentage to accelerate | 25.00% |
Private Placement of Debt [Member] | ' |
Debt Obligations [Line Items] | ' |
Aggregate principal amount | 600 |
Senior unsecured notes interest rate | 5.88% |
Long_Term_Debt_PIK_notes_Addit
Long Term Debt - PIK notes - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 18, 2013 | Sep. 30, 2014 | Jun. 27, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | |
PIK notes [Member] | PIK notes [Member] | PIK notes [Member] | PIK notes [Member] | PIK notes [Member] | ||||
Minimum [Member] | MRD [Member] | |||||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate principal amount | ' | ' | ' | $350,000,000 | $350,000,000 | ' | ' | ' |
Percentage of PIK toggle notes issued at par | ' | ' | ' | 98.00% | ' | ' | ' | ' |
Cash reserve for payment of interest on notes | ' | ' | ' | 50,000,000 | ' | ' | ' | ' |
Payment of distribution to funds | ' | 363,437,000 | 732,362,000 | 210,000,000 | ' | ' | ' | ' |
Debt redemption price percentage | ' | ' | ' | ' | 102.00% | ' | ' | ' |
Irrevocable deposits | ' | ' | ' | ' | ' | 360,000,000 | ' | ' |
Extinguishment loss | ($37,248,000) | ' | ' | ' | ($23,600,000) | ' | ' | ' |
Debt interest rate, minimum | ' | ' | ' | 10.00% | 10.00% | ' | ' | 10.00% |
Debt interest rate, maximum | ' | ' | ' | 10.75% | 10.75% | ' | ' | 10.75% |
Paid in cash interest rate | ' | ' | ' | ' | ' | ' | ' | 10.00% |
Paid in kind Interest rate | ' | ' | ' | ' | ' | ' | ' | 10.75% |
Other event of default minimum note holder percentage to accelerate | ' | ' | ' | ' | ' | ' | 25.00% | ' |
Long_Term_Debt_WildHorse_Resou
Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | |||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Apr. 03, 2013 | Jun. 13, 2013 | Sep. 30, 2014 | Jun. 13, 2013 | Jun. 13, 2013 | |
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | ||||
WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | ||||
Second Lien Term Loan [Member] | Second Lien Term Loan [Member] | Second Lien Term Loan [Member] | Second Lien Term Loan [Member] | |||||
Alternative Base Rate [member] | London Interbank Offered Rate (LIBOR) [Member] | |||||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Initial borrowing base of second lien term facility | ' | ' | ' | $1,000,000,000 | $325,000,000 | ' | ' | ' |
Line of credit facility, initial borrowing base | ' | ' | 1,145,000,000 | 300,000,000 | ' | ' | ' | ' |
Line of credit, minimum collateral percentage | ' | ' | ' | 80.00% | 80.00% | ' | ' | ' |
Debt instrument interest rate | ' | ' | ' | ' | ' | ' | 5.25% | 6.25% |
Cash distribution paid | ' | 363,437,000 | 732,362,000 | ' | 225,000,000 | ' | ' | ' |
Loss on extinguishment of debt | ($37,248,000) | ' | ' | ' | ' | ($13,700,000) | ' | ' |
Long_Term_Debt_MEMP_Revolving_
Long Term Debt - MEMP Revolving Credit Facility and Senior Notes - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 1 Months Ended | 9 Months Ended | 0 Months Ended | 2 Months Ended | 12 Months Ended | 9 Months Ended | |||||||||||||||||||||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jul. 17, 2014 | Sep. 30, 2014 | Oct. 10, 2013 | 23-May-13 | Apr. 17, 2013 | Dec. 31, 2013 | Sep. 30, 2014 | Oct. 10, 2013 | 23-May-13 | Apr. 17, 2013 | Jul. 17, 2014 | Oct. 10, 2013 | 31-May-13 | Dec. 31, 2013 | Sep. 30, 2014 | Oct. 01, 2013 | Sep. 23, 2013 | Sep. 23, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Oct. 10, 2013 | 23-May-13 | Apr. 17, 2013 | |
Minimum [Member] | Maximum [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Private Placement of Debt [Member] | Private Placement of Debt [Member] | Private Placement of Debt [Member] | ||||
6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | Private Placement of Debt [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | ||||||
6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | Sixth Amendment [Member] | Federal Funds Effective Rate [member] | Adjusted London Interbank Offered Rate [member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | 7.625 % Senior Notes Due May 2021 [Member] | ||||||||||||||||||||||
Optional Base Rate [member] | Optional Base Rate [member] | Alternative Base Rate [member] | London Interbank Offered Rate (LIBOR) [Member] | LIBOR Market Index Plus [Member] | Alternative Base Rate [member] | London Interbank Offered Rate (LIBOR) [Member] | LIBOR Market Index Plus [Member] | |||||||||||||||||||||||||||||
Range 1 [Member] | Range 2 [Member] | Range 3 [Member] | Range 1 [Member] | Range 2 [Member] | Range 3 [Member] | |||||||||||||||||||||||||||||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Initial borrowing base of second lien term facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,000,000,000 | $2,000,000,000 | ' | $1,000,000,000 | $2,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Lien percentage of assets for credit facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit, additional margin rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.50% | 1.00% | ' | 0.50% | 1.50% | 1.75% | ' | 1.50% | 2.50% | 2.75% | ' | ' | ' |
Line of credit, adjusted description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of revolving unused commitment fee | ' | ' | ' | 0.38% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.38% | ' | ' | ' | 0.50% | ' | ' | ' | ' | ' | ' |
Senior unsecured notes maturity date | ' | ' | ' | ' | ' | 1-Aug-22 | ' | ' | ' | ' | 21-May-21 | 1-May-21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate principal amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | 100,000,000 | 300,000,000 | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | 100,000,000 | 300,000,000 |
Other event of default minimum note holder percentage to accelerate | ' | ' | ' | ' | ' | 25.00% | ' | ' | ' | ' | 25.00% | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior unsecured notes interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.63% | 7.63% | ' | ' | ' | 6.88% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Note issued at percentage of par | ' | ' | ' | ' | ' | 98.49% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net proceeds from notes offering | 1,092,425,000 | 397,563,000 | 1,031,563,000 | ' | ' | ' | 484,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, initial borrowing base | ' | ' | 1,145,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 480,000,000 | 920,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business acquisition common control purchase price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 603,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, borrowing base | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ($75,000,000) | ($100,000,000) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance percentage of par value | ' | ' | ' | ' | ' | ' | ' | 97.00% | 102.00% | 98.52% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year, commencing November 1, 2013. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long_Term_Debt_Summary_of_Weig
Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | |
MRD [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | 2.40% | ' | 3.17% | 4.11% |
MRD [Member] | MRD LLC [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 3.20% | ' | ' |
MRD [Member] | WildHorse Resources, LLC [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | 4.04% | 3.44% | 2.30% | 3.00% |
MRD [Member] | WildHorse Resources second lien [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | 6.44% | 6.50% | 7.60% | ' |
MRD [Member] | Black Diamond [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 3.34% | 3.97% | 3.62% |
MRD [Member] | Classic [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | ' | ' | 4.50% |
MRD [Member] | BlueStone Natural Resources Holdings, LLC [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | ' | ' | ' |
MEMP [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | 2.08% | 2.55% | 3.25% | 2.74% |
MEMP [Member] | Wht [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 2.29% | 2.29% | 2.60% |
MEMP [Member] | Tanos Energy LLC [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 2.12% | 3.10% | 2.31% |
MEMP [Member] | Stanolind [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 3.52% | 3.52% | 3.76% |
MEMP [Member] | Boaz [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 2.97% | ' | ' |
MEMP [Member] | Crown [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 3.38% | 3.38% | 4.20% |
MEMP [Member] | Propel Energy [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | 3.08% | 3.08% | 3.28% |
MEMP [Member] | REO Sponsorship [Member] | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' |
Revolving credit facility, weighted-average interest rates | ' | ' | ' | 3.40% |
Long_Term_Debt_Summary_of_Unam
Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | $46,198 | $40,193 | $8,226 |
MRD [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 4,433 | ' | 653 |
MRD [Member] | PIK notes [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 0 | 8,261 | ' |
MRD [Member] | Classic GP[Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 160 |
MRD [Member] | Black Diamond [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 233 |
MRD [Member] | Senior Notes [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 12,825 | ' | ' |
MRD [Member] | WildHorse Resources, LLC [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 0 | 2,436 | 921 |
MRD [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | 9,030 | ' |
MRD [Member] | WildHorse Resources, LLC [Member] | Second Lien Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 0 | 9,030 | ' |
MEMP [Member] | 2.0 billion revolving credit facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 6,882 | 5,413 | 3,359 |
MEMP [Member] | Senior Notes [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | 15,053 | ' |
MEMP [Member] | Tanos Energy LLC [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 416 |
MEMP [Member] | WHT Energy Partners LLC [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 1,419 |
MEMP [Member] | Stanolind [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 580 |
MEMP [Member] | Boaz [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 153 |
MEMP [Member] | Crown [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 96 |
MEMP [Member] | Propel Energy [Member] | Revolving Credit Facility [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | ' | ' | 236 |
MEMP [Member] | 2021 Senior Notes [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | 13,836 | 15,053 | ' |
MEMP [Member] | 2022 Senior Notes [Member] | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' |
Unamortized deferred financing costs | $8,222 | ' | ' |
Stockholders_Equity_and_Noncon2
Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 1 Months Ended | |||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Jun. 18, 2014 | Dec. 31, 2012 | Apr. 01, 2013 | Sep. 30, 2014 | Jun. 18, 2014 | Sep. 09, 2014 | Jul. 15, 2014 | Oct. 08, 2013 | Mar. 25, 2013 | Dec. 31, 2012 | |
Tanos Energy LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | ||||||
MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | |||||||||
Stockholders Equity Note Disclosure [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock, shares authorized | 600,000,000 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock, par value | $0.01 | ' | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, par value | $0.01 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, shares authorized | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, shares issued | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock, shares outstanding | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of common units sold by subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | 14,950,000 | 9,890,000 | 16,675,000 | 9,775,000 | 11,975,000 |
Net proceeds from sale of common units by subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | $321,600,000 | $220,000,000 | $318,300,000 | $171,800,000 | $194,300,000 |
Number of over-allotment common units issued by Partnership | ' | ' | ' | ' | ' | ' | ' | ' | 1,950,000 | 1,290,000 | ' | ' | ' |
Public offering price per common unit | ' | ' | ' | $19 | ' | ' | ' | ' | $22.29 | $22.25 | ' | ' | ' |
Percentage of ownership interest sold to company | ' | ' | ' | ' | ' | 1.07% | ' | ' | ' | ' | ' | ' | ' |
Percentage of interest contributed former management members | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' |
Cash consideration paid to certain former management members | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' |
Noncontrolling interests | 1,022,721,000 | ' | 580,615,000 | ' | 231,662,000 | ' | ' | 400,000 | ' | ' | ' | ' | ' |
Fair value consideration paid | $3,292,000 | $1,270,000 | $15,135,000 | ' | ' | ' | $3,300,000 | ' | ' | ' | ' | ' | ' |
Stockholders_Equity_and_Noncon3
Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) | 0 Months Ended | 9 Months Ended |
Jun. 18, 2014 | Sep. 30, 2014 | |
Class of Stock [Line Items] | ' | ' |
Balance January 1, 2014 | ' | 0 |
Shares of common stock issued sold in initial public offering (Note 1) | 21,500,000 | ' |
Restricted common shares forfeited | ' | -9,211 |
Balance September 30, 2014 | ' | 193,559,211 |
Common Stock [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Shares of common stock issued in connection with restructuring transactions (Note 1) | ' | 171,000,000 |
Shares of common stock issued sold in initial public offering (Note 1) | ' | 21,500,000 |
Restricted common shares issued (Note 11) | ' | 1,068,422 |
Earnings_per_Share_Summary_of_
Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) (USD $) | 9 Months Ended |
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 |
Numerator: | ' |
Net income (loss) available to common stockholders | ($951,801) |
Denominator: | ' |
Weighted average common shares outstanding | 192,500 |
Restricted common shares | ' |
Weighted average common and common equivalent shares outstanding | 192,500 |
Basic EPS | ($4.94) |
Diluted EPS | ($4.94) |
Earnings_per_Share_Summary_of_1
Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail) | 9 Months Ended |
In Thousands, unless otherwise specified | Sep. 30, 2014 |
Earnings Per Share [Abstract] | ' |
Shares excluded from computation of EPS | 206,956 |
Earnings_per_Share_Summary_of_2
Earnings per Share - Summary of Calculation of Supplemental EPS (Detail) (USD $) | 9 Months Ended |
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 |
Numerator: | ' |
Net income (loss) available to common stockholders | ($951,801) |
Denominator: | ' |
Weighted average common shares outstanding | 192,500 |
Restricted common shares | ' |
Weighted average common and common equivalent shares outstanding | 192,500 |
Basic EPS | ($4.94) |
Diluted EPS | ($4.94) |
Supplemental EPS [Member] | ' |
Numerator: | ' |
Net income (loss) available to common stockholders | ($930,071) |
Denominator: | ' |
Weighted average common shares outstanding | 192,500 |
Restricted common shares | ' |
Weighted average common and common equivalent shares outstanding | 192,500 |
Basic EPS | ($4.83) |
Diluted EPS | ($4.83) |
Earnings_per_Share_Summary_of_3
Earnings per Share - Summary of Calculation of Supplemental EPS (Parenthetical) (Detail) | 9 Months Ended |
In Thousands, unless otherwise specified | Sep. 30, 2014 |
Earnings Per Share [Line Items] | ' |
Shares excluded from computation of EPS | 206,956 |
Supplemental EPS [Member] | ' |
Earnings Per Share [Line Items] | ' |
Shares excluded from computation of EPS | 206,956 |
LongTerm_Incentive_Plans_Addit
Long-Term Incentive Plans - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MEMP [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | |||||
Director [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of common shares that may be delivered | 19,250,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate award of restricted stock issued to employees and each independent director | ' | ' | ' | ' | ' | 1,052,633 | 5,263 | ' | ' | ' |
Vesting period of award | ' | ' | ' | ' | ' | '4 years | '1 year | ' | ' | ' |
Unrecognized compensation cost | ' | ' | ' | ' | ' | $18,600,000 | ' | $19,100,000 | $9,900,000 | ' |
Unrecognized compensation cost weighted-average period | ' | ' | ' | ' | ' | '3 years 8 months 5 days | ' | '2 years 3 months 18 days | '2 years 2 months 12 days | ' |
Number of common units that may be delivered | ' | ' | ' | ' | 2,142,221 | ' | ' | ' | ' | ' |
Aggregate fair value of restricted common units awarded | ' | ' | ' | ' | ' | ' | ' | ' | 9,700,000 | 5,000,000 |
Distributions to noncontrolling interest | $101,327,000 | $51,319,000 | $78,083,000 | $15,208,000 | ' | ' | ' | ' | $1,000,000 | $200,000 |
LongTerm_Incentive_Plans_Summa
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Restricted common shares outstanding, Number of Units, Beginning Balance | ' | ' | ' |
Granted, Number of Units | 1,068,422 | ' | ' |
Forfeited, Number of Units | -9,211 | ' | ' |
Restricted common shares outstanding, Number of Units, Ending Balance | 1,059,211 | ' | ' |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance | ' | ' | ' |
Granted, Weighted-Average Grant Date Fair Value Per Unit | $19 | ' | ' |
Forfeited, Weighted-Average Grant Date Fair Value Per Unit | $19 | ' | ' |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance | $19 | ' | ' |
MEMP [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Restricted common shares outstanding, Number of Units, Beginning Balance | 706,927 | 285,609 | ' |
Granted, Number of Units | 684,954 | 524,718 | 287,943 |
Forfeited, Number of Units | -36,112 | -11,734 | -2,334 |
Vested, Number of Units | -260,067 | -91,666 | ' |
Restricted common shares outstanding, Number of Units, Ending Balance | 1,095,702 | 706,927 | 285,609 |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance | $18.62 | $18.08 | ' |
Granted, Weighted-Average Grant Date Fair Value Per Unit | $22.39 | $18.83 | $18.07 |
Forfeited, Weighted-Average Grant Date Fair Value Per Unit | $20.43 | $17.24 | $17.14 |
Vested, Weighted-Average Grant Date Fair Value Per Unit | $18.56 | $18.31 | ' |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance | $20.93 | $18.62 | $18.08 |
LongTerm_Incentive_Plans_Summa1
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
MEMP [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | |
MEMP [Member] | MEMP [Member] | MEMP [Member] | Restricted Stock [Member] | Restricted Stock [Member] | MEMP [Member] | Restricted Stock [Member] | Restricted Stock [Member] | |||
MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate grant date fair value | $15.30 | $20.30 | $9.90 | $5.20 | ' | ' | ' | ' | ' | ' |
Aggregate grant date fair value, market price | ' | $19 | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate grant date fair value, market price range | ' | ' | ' | ' | $21.99 | $18.33 | $17.14 | $23.40 | $20.35 | $18.58 |
LongTerm_Incentive_Plans_Summa2
Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) (USD $) | 12 Months Ended | 9 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
MRD [Member] | MRD [Member] | MEMP [Member] | MEMP [Member] | |||
Restricted Stock [Member] | Restricted Stock [Member] | |||||
Compensation Related Costs Disclosure [Line Items] | ' | ' | ' | ' | ' | ' |
Amortization of MEMP equity awards | $3,557 | $1,423 | $1,487 | ' | $5,387 | $2,322 |
Incentive_Units_Additional_Inf
Incentive Units - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 01, 2013 | Nov. 30, 2013 | Nov. 01, 2013 | Jul. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2012 | Jun. 18, 2014 | Apr. 01, 2013 | Apr. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | |
Incentive Units [Member] | Incentive Units [Member] | Black Diamond, Classic GP and Classic [Member] | Black Diamond, Classic GP and Classic [Member] | Black Diamond, Classic GP and Classic [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | MRD Holdco LLC [Member] | MRD Holdco LLC [Member] | MRD Holdco LLC [Member] | MRD Holdco LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | Tanos Energy LLC [Member] | Tanos Energy LLC [Member] | Tanos Energy LLC [Member] | Tanos Energy LLC [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | |||||
Special Tier and Tier I Unit Holders [Member] | Special Tier and Tier I Unit Holders [Member] | Subsequent Incentive Units [Member] | Exchanged Incentive Units [Member] | Exchanged Incentive Units [Member] | ||||||||||||||||||||||||||
Subsequent Incentive Units [Member] | ||||||||||||||||||||||||||||||
Equity Incentive Plan [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ranging of distributions for incentive units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 10.00% | 31.50% | 31.50% |
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16.50% | 16.50% | ' | 0.70% | 9.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of ownership interest sold to company | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.07% | ' | ' | ' | ' | ' | ' | ' |
Compensation expense as component of general and administrative expense | ' | ' | ' | ' | ' | ' | ' | $12,600,000 | ' | $19,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | $10,000,000 | ' | $9,500,000 | ' | ' | $5,800,000 | $5,800,000 | $5,800,000 | ' | ' | ' | ' |
Compensation expense | ' | ' | 3,557,000 | 1,423,000 | 0 | 0 | ' | ' | ' | ' | 1,000,000 | 19,100,000 | ' | ' | ' | 600,000 | 136,700,000 | ' | ' | 831,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of interest contributed former management members | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' |
Exchange of incentive units | 193,559,211 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,334,323 | ' | ' | ' | ' | ' | ' | ' | ' |
Cash consideration paid to certain former management members | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Carrying amount of the noncontrolling interest | 1,022,721,000 | ' | 580,615,000 | 231,662,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Fair value of consideration paid for noncontrolling interests | 3,292,000 | 1,270,000 | 15,135,000 | ' | ' | ' | 28,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash component of incentive unit compensation expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incentive units exchanges for shares of our common stock | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 804,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
The number of incentive units authorized by governing documents | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incentive units granted in an exchange for cancelled predecessor awards | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 930 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,300,000 | 158,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Subsequent incentive units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remaining expected life | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair value of consideration paid for noncontrolling interests, amount payable in quarterly installments | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrued liability | $179,381,000 | ' | $98,130,000 | $33,487,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Membership interest that will be contributed by certain former management members | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incentive_Units_Fair_Value_of_
Incentive Units - Fair Value of Incentive Units Estimated (Detail) | 9 Months Ended |
Sep. 30, 2014 | |
Exchanged Incentive Units [Member] | ' |
Schedule Of Share Based Compensation Valuation Assumptions [Line Items] | ' |
Valuation date | 30-Sep-14 |
Dividend yield | 0.00% |
Expected volatility | 21.47% |
Risk-free rate | 0.90% |
Expected life (years) | '2 years 8 months 1 day |
Subsequent Incentive Units [Member] | ' |
Schedule Of Share Based Compensation Valuation Assumptions [Line Items] | ' |
Valuation date | 30-Sep-14 |
Dividend yield | 0.00% |
Expected volatility | 21.47% |
Risk-free rate | 0.90% |
Expected life (years) | '2 years 8 months 1 day |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Detail) (USD $) | 0 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | ||||||||||||||||||||||||
1-May-14 | Nov. 01, 2011 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2010 | Feb. 28, 2014 | Oct. 01, 2013 | Oct. 01, 2013 | Oct. 01, 2013 | Dec. 31, 2013 | Dec. 12, 2012 | Dec. 12, 2012 | Dec. 31, 2012 | Dec. 12, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 01, 2013 | Mar. 01, 2012 | Mar. 01, 2012 | Dec. 31, 2010 | Dec. 31, 2010 | 1-May-14 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 17, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Feb. 28, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 28, 2013 | Sep. 30, 2014 | Apr. 01, 2014 | Mar. 10, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Oct. 01, 2013 | Dec. 31, 2010 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 28, 2014 | |
MMBTU_day | NGPCIF [Member] | NGPCIF [Member] | NGPCIF [Member] | NGPCIF [Member] | Tanos Energy LLC [Member] | Prospect Energy LLC [Member] | Jackson County [Member] | MEMP [Member] | MEMP [Member] | REO Sponsorship [Member] | REO Sponsorship [Member] | REO Sponsorship [Member] | Cinco Group [Member] | Cinco Group [Member] | Cinco Group [Member] | Bluestone Energy Partners [Member] | Bluestone Energy Partners [Member] | Adjustments [Member] | Adjustments [Member] | Classic [Member] | Advisory Fees [Member] | Advisory Fees [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | WildHorse Resources, LLC [Member] | BlueStone Natural Resources Holdings, LLC [Member] | WHR Management Company [Member] | WHR Management Company [Member] | Natural Gas Partners [Member] | Oil And Gas Production [Member] | Oil And Gas Production [Member] | Employee [Member] | Boaz [Member] | Propel Energy [Member] | |||||||
NGPCIF [Member] | Cinco Group [Member] | Cinco Group [Member] | NGPCIF [Member] | NGPCIF [Member] | NGPCIF [Member] | NGPCIF [Member] | NGPCIF [Member] | Estimated Customary Post Closing Adjustments [Member] | Estimated Customary Post Closing Adjustments [Member] | Cinco Group [Member] | NGPCIF [Member] | |||||||||||||||||||||||||||||||||||||
NGPCIF [Member] | NGPCIF [Member] | |||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business acquisition common control purchase price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $63,400,000 | ' | ' | ' | ' | ' | ' | ' | $270,600,000 | ' | ' | $603,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $200,000,000 | ' | $33,300,000 | ' | ' | ' | $507,100,000 | ' | ' | ' | ' | ' |
Date of acquisition common control | ' | ' | ' | ' | ' | ' | ' | 28-Feb-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28-Mar-13 | ' | ' | ' | 1-Apr-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash received | ' | ' | ' | ' | ' | ' | 19,800,000 | ' | ' | 19,500,000 | ' | 77,400,000 | 16,300,000 | 2,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,900,000 | 19,100,000 | ' | ' | ' | ' | ' | ' | 63,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,300,000 |
Total cash consideration | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of gain over the book value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Gain recognized as contribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Common stock lock-up agreement period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '180 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount receivable under management agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Management fee per month | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' |
Service agreement termination period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '90 days | ' | ' | ' | ' | ' | ' | ' |
Primary term of gas processing agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum annual processing fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fee per MMBTU | 0.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Natural gas produced per day | ' | 50,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual inflationary escalation | 3.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Price per unit | 0.07 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Water disposal fee per barrel | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Water disposal agreement period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Working capital and other customary adjustments to Beta acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Working interests percentage Beta properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 51.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
General and administrative | ' | ' | 61,061,000 | 55,982,000 | 125,358,000 | 69,187,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Profits Interest Sold to NGP | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | 3.13% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23.50% | 6.25% | ' | ' | ' |
Fixed overhead cost per month | ' | ' | ' | ' | ' | ' | ' | ' | 20,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payment to related party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,600,000 | 2,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payable to related party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | 400,000 | ' | ' | ' | ' | ' | 2,400,000 | ' | ' | ' | ' | ' | ' |
Cash received from related party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Undivided interest sold to affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expenses incurred with related parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000 | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 300,000 | ' |
Financing fees equal to a percentage of capital contributions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Received an equity contribution of oil and gas properties | ' | ' | ' | ' | ' | $6,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related_Party_Transactions_Sch
Related Party Transactions - Schedule of Net Assets Recorded (Detail) (USD $) | Feb. 28, 2014 | Sep. 01, 2012 | Oct. 01, 2013 |
In Thousands, unless otherwise specified | NGPCIF [Member] | REO Sponsorship [Member] | Cinco Group Acquisition [Member] |
Related Party Transaction [Line Items] | ' | ' | ' |
Cash and cash equivalents | ' | $6,021 | $2,820 |
Accounts receivable | 2,274 | 16,284 | 5,184 |
Short-term derivative instruments, net | ' | 2,926 | ' |
Prepaid expenses and other current assets | ' | 4,521 | 1,454 |
Oil and natural gas properties, net | 40,056 | 108,342 | 342,759 |
Restricted investments | ' | 68,009 | ' |
Other long-term assets | ' | ' | 344 |
Accounts payable | ' | -9,092 | -2,346 |
Revenue payable | ' | ' | -2,910 |
Accrued liabilities | -297 | -9,140 | -1,799 |
Asset retirement obligations | -277 | -58,746 | ' |
Short-term derivative instruments, net | ' | ' | -1,828 |
Long-term derivative instruments, net | ' | ' | -826 |
Asset retirement obligations | ' | ' | -9,606 |
Credit facilities | ' | -28,500 | -151,690 |
Deferred tax liability | ' | -1,674 | ' |
Noncontrolling interest | ' | -5,255 | ' |
Net assets | $41,756 | $93,696 | $181,556 |
Related_Party_Transactions_Boo
Related Party Transactions - Book Value of Assets Sold (Detail) (WHR Management Company [Member], USD $) | Jun. 18, 2014 |
In Thousands, unless otherwise specified | |
WHR Management Company [Member] | ' |
Schedule of Other Related Party Transactions [Line Items] | ' |
Cash and cash equivalents | $33,001 |
Restricted cash | 300 |
Accounts receivable | 5,256 |
Prepaid expenses and other current assets | 379 |
Property, plant and equipment, net | 3,410 |
Other long-term assets | 4 |
Accounts payable | -19,959 |
Accounts payable - affiliates | -17,099 |
Accrued liabilities | -5,061 |
Net assets | $231 |
Business_Segment_Data_Addition
Business Segment Data - Additional Information (Detail) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2014 | Dec. 31, 2013 | |
Segment | Segment | |
Segment Reporting [Abstract] | ' | ' |
Number of reportable business segments | 2 | 2 |
Business_Segment_Data_Summary_
Business Segment Data - Summary of Selected Business Segment Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Total revenues | $672,885 | $422,741 | $575,023 | $396,868 |
Segment assets | 4,021,667 | ' | 2,829,161 | 2,459,304 |
Total cash expenditures for additions to long-lived assets | -1,550,139 | -363,623 | 468,447 | 636,686 |
Adjusted EBITDA | 447,265 | 291,285 | 394,856 | 287,589 |
Operating Segments [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Adjusted EBITDA | 466,177 | 310,839 | 420,088 | 311,439 |
Other, Adjustments & Eliminations [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Total revenues | -137 | -136 | -151 | -369 |
Segment assets | 40,069 | ' | -4,280 | -132,506 |
Total cash expenditures for additions to long-lived assets | 0 | 0 | ' | ' |
Adjusted EBITDA | -18,912 | -19,554 | -25,232 | -23,447 |
MRD [Member] | Operating Segments [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Total revenues | 301,492 | 171,361 | 231,558 | 138,814 |
Segment assets | 1,232,146 | ' | 1,281,134 | 1,102,406 |
Total cash expenditures for additions to long-lived assets | -276,982 | -198,220 | 267,870 | 249,526 |
Adjusted EBITDA | ' | ' | ' | 131,702 |
Adjusted EBITDA | 247,335 | 153,679 | 197,903 | 132,105 |
MEMP [Member] | Operating Segments [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Total revenues | 371,530 | 251,516 | 343,616 | 258,423 |
Segment assets | 2,749,452 | ' | 1,552,307 | 1,489,404 |
Total cash expenditures for additions to long-lived assets | -1,273,157 | -165,403 | 200,577 | 387,160 |
Adjusted EBITDA | $218,842 | $157,160 | $222,185 | $179,334 |
Business_Segment_Data_Summary_1
Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) (Other, Adjustments & Eliminations [Member], USD $) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Impairment charges | $47,300,000 | ' | $49,900,000 | ' |
MEMP [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Cash distributions paid | $6,100,000 | $19,100,000 | $26,000,000 | $19,300,000 |
Business_Segment_Data_Schedule
Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | ($964,922) | $174,300 | $151,332 | $26,997 |
Interest expense, net | 104,928 | 41,994 | 69,250 | 33,238 |
Loss on extinguishment of debt | 37,248 | ' | ' | ' |
Income tax expense (benefit) | 14,398 | 1,432 | 1,619 | 107 |
DD&A | 215,906 | 132,328 | 184,717 | 138,672 |
Impairment of proved oil and natural gas properties | 67,181 | 21 | 6,600 | 28,871 |
Accretion of AROs | 4,601 | 4,016 | 5,581 | 5,009 |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 |
Incentive unit compensation expense | ' | ' | 3,557 | 1,423 |
Exploration costs | 1,465 | 2,265 | 2,356 | 9,800 |
Amortization of investment premium | ' | ' | ' | 194 |
Adjusted EBITDA | 447,265 | 291,285 | 394,856 | 287,589 |
Operating Segments [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | -975,186 | 123,987 | 102,511 | 31,877 |
Interest expense, net | 104,928 | 41,994 | 69,250 | 33,238 |
Loss on extinguishment of debt | 37,248 | ' | ' | ' |
Income tax expense (benefit) | 14,398 | 1,432 | 1,619 | 107 |
DD&A | 213,326 | 132,328 | 184,312 | 138,672 |
Impairment of proved oil and natural gas properties | 67,181 | 50,310 | 56,889 | 28,871 |
Accretion of AROs | 4,601 | 4,016 | 5,581 | 5,009 |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
Cash settlements received (paid) on commodity derivative instruments | -19,929 | 23,206 | 32,119 | 74,299 |
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 |
Acquisition related costs | 5,480 | 5,073 | 8,313 | 4,538 |
Incentive unit compensation expense | 976,264 | 21,391 | 46,837 | 10,933 |
Non-cash compensation expense | ' | 1,057 | 1,057 | ' |
Exploration costs | 1,465 | 2,265 | 2,356 | 9,800 |
Provision for environmental remediation | 2,852 | ' | ' | ' |
Amortization of investment premium | ' | ' | ' | 194 |
Non-cash equity (income) loss from MEMP | 12,844 | 454 | -1,847 | -696 |
Cash distributions from MEMP | 6,068 | 19,100 | 26,006 | 19,263 |
Adjusted EBITDA | 466,177 | 310,839 | 420,088 | 311,439 |
Operating Segments [Member] | MRD [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | -930,149 | 114,628 | 82,243 | -14,641 |
Interest expense, net | 44,355 | 15,947 | 27,349 | 12,802 |
Loss on extinguishment of debt | 37,248 | ' | ' | ' |
Income tax expense (benefit) | 14,323 | 1,147 | 1,311 | -178 |
DD&A | 107,496 | 62,605 | 87,043 | 62,636 |
Impairment of proved oil and natural gas properties | ' | ' | 2,527 | 18,339 |
Accretion of AROs | 495 | 547 | 728 | 632 |
(Gain) loss on commodity derivative instruments | -17,130 | -8,361 | -3,013 | -13,488 |
Cash settlements received (paid) on commodity derivative instruments | -4,930 | 9,125 | 12,240 | 30,188 |
(Gain) loss on sale of properties | 3,057 | -83,370 | -82,773 | -2 |
Acquisition related costs | 1,568 | 1,651 | 1,584 | 403 |
Incentive unit compensation expense | 970,877 | 19,069 | 43,279 | 9,510 |
Non-cash compensation expense | ' | ' | ' | ' |
Exploration costs | 1,213 | 1,137 | 1,226 | 7,337 |
Provision for environmental remediation | ' | ' | ' | ' |
Non-cash equity (income) loss from MEMP | 12,844 | 454 | -1,847 | -696 |
Cash distributions from MEMP | 6,068 | 19,100 | 26,006 | 19,263 |
Adjusted EBITDA | 247,335 | 153,679 | 197,903 | 132,105 |
Operating Segments [Member] | MEMP [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | -45,037 | 9,359 | 20,268 | 46,518 |
Interest expense, net | 60,573 | 26,047 | 41,901 | 20,436 |
Loss on extinguishment of debt | ' | ' | ' | ' |
Income tax expense (benefit) | 75 | 285 | 308 | 285 |
DD&A | 105,830 | 69,723 | 97,269 | 76,036 |
Impairment of proved oil and natural gas properties | 67,181 | 50,310 | 54,362 | 10,532 |
Accretion of AROs | 4,106 | 3,469 | 4,853 | 4,377 |
(Gain) loss on commodity derivative instruments | 28,710 | -21,195 | -26,281 | -21,417 |
Cash settlements received (paid) on commodity derivative instruments | -14,999 | 14,081 | 19,879 | 44,111 |
(Gain) loss on sale of properties | ' | -2,848 | -2,848 | -9,759 |
Acquisition related costs | 3,912 | 3,422 | 6,729 | 4,135 |
Incentive unit compensation expense | 5,387 | 2,322 | 3,558 | 1,423 |
Non-cash compensation expense | ' | 1,057 | 1,057 | ' |
Exploration costs | 252 | 1,128 | 1,130 | 2,463 |
Provision for environmental remediation | 2,852 | ' | ' | ' |
Amortization of investment premium | ' | ' | ' | 194 |
Non-cash equity (income) loss from MEMP | ' | ' | ' | ' |
Cash distributions from MEMP | ' | ' | ' | ' |
Adjusted EBITDA | $218,842 | $157,160 | $222,185 | $179,334 |
Business_Segment_Data_Reconcil
Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting, Revenue Reconciling Item [Line Items] | ' | ' | ' | ' |
Total Reportable Segments' Adjusted EBITDA | $447,265 | $291,285 | $394,856 | $287,589 |
Adjustment to reconcile Adjusted EBITDA to net income (loss): | ' | ' | ' | ' |
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 |
Loss on extinguishment of debt | -37,248 | ' | ' | ' |
Income tax benefit (expense) | -14,398 | -1,432 | -1,619 | -107 |
DD&A | -215,906 | -132,328 | -184,717 | -138,672 |
Impairment of proved oil and natural gas properties | -67,181 | -21 | -6,600 | -28,871 |
Accretion of AROs | -4,601 | -4,016 | -5,581 | -5,009 |
Gains (losses) on commodity derivative instruments | -11,580 | 29,556 | 29,294 | 34,905 |
Gain (loss) on sale of properties | -3,057 | 86,218 | 85,621 | 9,761 |
Incentive unit compensation expense | ' | ' | -3,557 | -1,423 |
Exploration costs | -1,465 | -2,265 | -2,356 | -9,800 |
Amortization of investment premium | ' | ' | ' | -194 |
Net income (loss) | -964,922 | 174,300 | 151,332 | 26,997 |
Reportable Segments [Member] | ' | ' | ' | ' |
Segment Reporting, Revenue Reconciling Item [Line Items] | ' | ' | ' | ' |
Total Reportable Segments' Adjusted EBITDA | 466,177 | 310,839 | 420,088 | 311,439 |
Adjustment to reconcile Adjusted EBITDA to net income (loss): | ' | ' | ' | ' |
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 |
Loss on extinguishment of debt | -37,248 | ' | ' | ' |
Income tax benefit (expense) | -14,398 | -1,432 | -1,619 | -107 |
DD&A | -215,906 | -132,328 | -184,717 | -138,672 |
Impairment of proved oil and natural gas properties | -67,181 | -21 | -6,600 | -28,871 |
Accretion of AROs | -4,601 | -4,016 | -5,581 | -5,009 |
Gains (losses) on commodity derivative instruments | -11,580 | 29,556 | 29,294 | 34,905 |
Cash settlements paid (received) on commodity derivative instruments | 19,929 | -23,206 | -32,119 | -74,299 |
Gain (loss) on sale of properties | -3,057 | 86,218 | 85,621 | 9,761 |
Acquisition related costs | -5,480 | -5,073 | -8,313 | -4,538 |
Incentive unit compensation expense | -976,264 | -21,391 | -46,837 | -10,933 |
Non-cash compensation expense | ' | -1,057 | -1,057 | ' |
Exploration costs | -1,465 | -2,265 | -2,356 | -9,800 |
Provision for environmental remediation | -2,852 | ' | ' | ' |
Amortization of investment premium | ' | ' | ' | -194 |
Cash distributions from MEMP | -6,068 | -19,100 | -26,006 | -19,263 |
Non-cash equity (income) loss from WHT & MRD Assets | ' | -430 | 784 | -4,184 |
Net income (loss) | ($964,922) | $174,300 | $151,332 | $26,997 |
Business_Segment_Data_Schedule1
Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | ' | ' | ' | ' |
Oil & natural gas sales | $669,301 | $420,857 | $571,948 | $393,631 |
Other revenues | 3,584 | 1,884 | 3,075 | 3,237 |
Total revenues | 672,885 | 422,741 | 575,023 | 396,868 |
Costs and expenses: | ' | ' | ' | ' |
Lease operating | 111,887 | 81,746 | 113,640 | 103,754 |
Pipeline operating | 1,596 | 1,343 | 1,835 | 2,114 |
Exploration | 1,465 | 2,265 | 2,356 | 9,800 |
Production and ad valorem taxes | 33,623 | 23,478 | 27,146 | 23,624 |
Depreciation, depletion, and amortization | 215,906 | 132,328 | 184,717 | 138,672 |
Impairment of proved oil and natural gas properties | 67,181 | 21 | 6,600 | 28,871 |
Incentive unit compensation expense | 969,390 | 19,069 | ' | ' |
General and administrative | 61,061 | 55,982 | 125,358 | 69,187 |
Accretion of asset retirement obligations | 4,601 | 4,016 | 5,581 | 5,009 |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 |
Other, net | -12 | 622 | 649 | 502 |
Total costs and expenses | 1,481,335 | 205,096 | 352,967 | 336,867 |
Operating income (loss) | -808,450 | 217,645 | 222,056 | 60,001 |
Other income (expense): | ' | ' | ' | ' |
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 |
Loss on extinguishment of debt | -37,248 | ' | ' | ' |
Other, net | 102 | 81 | 145 | 535 |
Total other income (expense) | -142,074 | -41,913 | -69,105 | -32,897 |
Amortization of investment premium | ' | ' | ' | -194 |
Income (loss) before income taxes | -950,524 | 175,732 | 152,951 | 27,104 |
Income tax benefit (expense) | -14,398 | -1,432 | -1,619 | -107 |
Net income (loss) | -964,922 | 174,300 | 151,332 | 26,997 |
Operating Segments [Member] | ' | ' | ' | ' |
Costs and expenses: | ' | ' | ' | ' |
Exploration | 1,465 | 2,265 | 2,356 | 9,800 |
Depreciation, depletion, and amortization | 213,326 | 132,328 | 184,312 | 138,672 |
Impairment of proved oil and natural gas properties | 67,181 | 50,310 | 56,889 | 28,871 |
Accretion of asset retirement obligations | 4,601 | 4,016 | 5,581 | 5,009 |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
(Gain) loss on sale of properties | 3,057 | -86,218 | -85,621 | -9,761 |
Other income (expense): | ' | ' | ' | ' |
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 |
Loss on extinguishment of debt | -37,248 | ' | ' | ' |
Amortization of investment premium | ' | ' | ' | -194 |
Income tax benefit (expense) | -14,398 | -1,432 | -1,619 | -107 |
Net income (loss) | -975,186 | 123,987 | 102,511 | 31,877 |
Operating Segments [Member] | MRD [Member] | ' | ' | ' | ' |
Revenues: | ' | ' | ' | ' |
Oil & natural gas sales | 300,931 | 171,013 | 230,751 | 138,032 |
Other revenues | 561 | 348 | 807 | 782 |
Total revenues | 301,492 | 171,361 | 231,558 | 138,814 |
Costs and expenses: | ' | ' | ' | ' |
Lease operating | 18,657 | 17,065 | 25,006 | 24,438 |
Exploration | 1,213 | 1,137 | 1,226 | 7,337 |
Production and ad valorem taxes | 10,494 | 8,563 | 9,362 | 7,576 |
Depreciation, depletion, and amortization | 107,496 | 62,605 | 87,043 | 62,636 |
Impairment of proved oil and natural gas properties | ' | ' | 2,527 | 18,339 |
Incentive unit compensation expense | 969,390 | ' | ' | ' |
General and administrative | 29,301 | 22,466 | 81,758 | 38,414 |
Accretion of asset retirement obligations | 495 | 547 | 728 | 632 |
(Gain) loss on commodity derivative instruments | -17,130 | -8,361 | -3,013 | -13,488 |
(Gain) loss on sale of properties | 3,057 | -83,370 | -82,773 | -2 |
Other, net | ' | -25 | 2 | 364 |
Total costs and expenses | 1,122,973 | 39,696 | 121,866 | 146,246 |
Operating income (loss) | -821,481 | 131,665 | 109,692 | -7,432 |
Other income (expense): | ' | ' | ' | ' |
Interest expense, net | -44,355 | -15,947 | -27,349 | -12,802 |
Loss on extinguishment of debt | -37,248 | ' | ' | ' |
Earnings from equity investments | -12,844 | -24 | 1,066 | 4,880 |
Other, net | 102 | 81 | 145 | 535 |
Total other income (expense) | -94,354 | -15,890 | -26,138 | -7,387 |
Income (loss) before income taxes | -915,826 | 115,775 | 83,554 | -14,819 |
Income tax benefit (expense) | -14,323 | -1,147 | -1,311 | 178 |
Net income (loss) | -930,149 | 114,628 | 82,243 | -14,641 |
Operating Segments [Member] | MEMP [Member] | ' | ' | ' | ' |
Revenues: | ' | ' | ' | ' |
Oil & natural gas sales | 368,370 | 249,844 | 341,197 | 255,608 |
Other revenues | 3,160 | 1,672 | 2,419 | 2,815 |
Total revenues | 371,530 | 251,516 | 343,616 | 258,423 |
Costs and expenses: | ' | ' | ' | ' |
Lease operating | 93,367 | 64,922 | 88,893 | 80,116 |
Pipeline operating | 1,596 | 1,343 | 1,835 | 2,114 |
Exploration | 252 | 1,128 | 1,130 | 2,463 |
Production and ad valorem taxes | 23,129 | 14,915 | 17,784 | 16,048 |
Depreciation, depletion, and amortization | 105,830 | 69,723 | 97,269 | 76,036 |
Impairment of proved oil and natural gas properties | 67,181 | 50,310 | 54,362 | 10,532 |
General and administrative | 31,760 | 33,411 | 43,495 | 30,342 |
Accretion of asset retirement obligations | 4,106 | 3,469 | 4,853 | 4,377 |
(Gain) loss on commodity derivative instruments | 28,710 | -21,195 | -26,281 | -21,417 |
(Gain) loss on sale of properties | ' | -2,848 | -2,848 | -9,759 |
Other, net | -12 | 647 | 647 | 138 |
Total costs and expenses | 355,919 | 215,825 | 281,139 | 190,990 |
Operating income (loss) | 15,611 | 35,691 | 62,477 | 67,433 |
Other income (expense): | ' | ' | ' | ' |
Interest expense, net | -60,573 | -26,047 | -41,901 | -20,436 |
Loss on extinguishment of debt | ' | ' | ' | ' |
Total other income (expense) | -60,573 | -26,047 | -41,901 | -20,630 |
Amortization of investment premium | ' | ' | ' | -194 |
Income (loss) before income taxes | -44,962 | 9,644 | 20,576 | 46,803 |
Income tax benefit (expense) | -75 | -285 | -308 | -285 |
Net income (loss) | -45,037 | 9,359 | 20,268 | 46,518 |
Other, Adjustments & Eliminations [Member] | ' | ' | ' | ' |
Revenues: | ' | ' | ' | ' |
Oil & natural gas sales | ' | ' | ' | -9 |
Other revenues | -137 | -136 | -151 | -360 |
Total revenues | -137 | -136 | -151 | -369 |
Costs and expenses: | ' | ' | ' | ' |
Lease operating | -137 | -241 | -259 | -800 |
Depreciation, depletion, and amortization | 2,580 | ' | 405 | ' |
Impairment of proved oil and natural gas properties | ' | -50,289 | -50,289 | ' |
General and administrative | ' | 105 | 105 | 431 |
Total costs and expenses | 2,443 | -50,425 | -50,038 | -369 |
Operating income (loss) | -2,580 | 50,289 | 49,887 | ' |
Other income (expense): | ' | ' | ' | ' |
Earnings from equity investments | 12,844 | 24 | -1,066 | -4,880 |
Total other income (expense) | 12,844 | 24 | -1,066 | -4,880 |
Income (loss) before income taxes | 10,264 | 50,313 | 48,821 | -4,880 |
Net income (loss) | $10,264 | $50,313 | $48,821 | ($4,880) |
Commitments_and_Contingencies_1
Commitments and Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 9 Months Ended | |||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Dec. 31, 2011 | Jun. 30, 2010 | Dec. 31, 2013 | Mar. 01, 2007 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Feb. 01, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 01, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Feb. 01, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2014 | |
Certificates_of_Deposits | Maximum [Member] | REO Sponsorship [Member] | December 31, 2016 [Member] | December 31, 2016 [Member] | WildHorse Resources, LLC [Member] | Dubach [Member] | Dubach [Member] | Dubach [Member] | Dubach [Member] | Dubberly [Member] | Dubberly [Member] | Dubberly [Member] | Dubberly [Member] | Dubberly [Member] | Dubberly [Member] | MEMP [Member] | |||||
Maximum [Member] | MMBTU | MMBTU | Subsequent Event [Member] | MMBTU | Maximum [Member] | Minimum [Member] | Subsequent Event [Member] | Year One [Member] | After First Anniversary [Member] | ||||||||||||
MMBTU | MMBTU | ||||||||||||||||||||
Loss Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Environmental reserves | $600,000 | ' | $2,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated environmental remediation expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 |
Maximum remaining obligation | 12,200,000 | ' | 9,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expansion of processing plant | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70 | ' | ' | ' | ' | ' | ' | ' | ' |
Payback demand fee for third party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 110.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Payback demand quality per day | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 136,200 | ' | ' | ' | ' | ' | ' | ' | ' |
Payback of fee in excess of demand quantity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.26 | ' | 0.31 | ' | ' | ' | ' | ' | ' |
Increase in demand fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.275 | 0.26 | 0.26 | 0.275 | ' | ' | ' | ' | ' | ' | ' |
Payback demand fee received by the third party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 110.00% | ' | ' | ' | ' | ' | ' |
Payback of demand fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.31 | ' | ' | ' | ' | ' | ' |
Monthly demand quantity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,750 | ' | ' | ' | ' | ' | ' |
Increase of demand quantity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,500 | ' | ' | ' | ' | ' | ' |
Decrease in demand fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.31 | 0.31 | 0.275 | 0.275 | ' | ' | ' |
Accrued liabilities | 0 | 100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Environmental reserves | 577,000 | 1,469,000 | ' | 1,747,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount per barrel of oil | 0.25 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate value of account required to cease fund | 4,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted Investment | 2,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of working interest under sinking fund trust agreement | 51.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remaining obligation | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Supplemental Bond for Decommissioning Liabilities Trust Agreement | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional quarterly payments | ' | ' | ' | ' | 600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum balances attributable to net working interest | ' | ' | ' | ' | ' | ' | ' | 78,660,000 | 78,660,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Third party gatherer, maximum daily quantity of gas obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 158,000 | ' | ' | ' | ' | ' | ' | 214,750 | 271,500 | ' |
Allowable facility costs | ' | ' | ' | ' | ' | 129,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Facility costs payment percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Rent expense | 8,300,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Standby letters of credit amount issued | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Certificate of Deposits collateralized for letters of credit | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair value of the Certificates of Deposits | $500,000 | $1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_and_Contingencies_2
Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2014 |
Held-to-maturity Securities [Abstract] | ' | ' |
Less: Outside working interest owners share, Amortized Cost | ($61,884) | ($64,305) |
Amortized Cost | 66,373 | 68,970 |
Less: Outside working interest owners share, Unrealized Gain (loss) | -45 | ' |
Unrealized Gain (loss) | 48 | ' |
Less: Outside working interest owners share, Fair Market Value | -61,929 | ' |
Fair Market Value | 66,421 | ' |
US Treasury Notes Securities [Member] | ' | ' |
Held-to-maturity Securities [Abstract] | ' | ' |
Amortized Cost | 23,073 | ' |
Unrealized Gain (loss) | 93 | ' |
Fair Market Value | 23,166 | ' |
Money Market Funds [Member] | ' | ' |
Held-to-maturity Securities [Abstract] | ' | ' |
Amortized Cost | 105,184 | 133,275 |
Fair Market Value | $105,184 | ' |
Commitments_and_Contingencies_3
Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
June 30, 2014 [Member] | ' | ' |
Asset retirement obligations | ' | ' |
Minimum balances attributable to REO's net working interest | ' | $68,310 |
June 30, 2015 [Member] | ' | ' |
Asset retirement obligations | ' | ' |
Minimum balances attributable to REO's net working interest | 72,450 | 72,450 |
June 30, 2016 [Member] | ' | ' |
Asset retirement obligations | ' | ' |
Minimum balances attributable to REO's net working interest | 76,590 | 76,590 |
December 31, 2016 [Member] | ' | ' |
Asset retirement obligations | ' | ' |
Minimum balances attributable to REO's net working interest | $78,660 | $78,660 |
Commitments_and_Contingencies_4
Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) (Wyoming Acquisition [Member], USD $) | Sep. 30, 2014 |
In Thousands, unless otherwise specified | |
Wyoming Acquisition [Member] | ' |
Minimum Purchase Commitment [Line Items] | ' |
Estimated payment obligation, Total | $62,103 |
Estimated payment obligation, Remainder 2014 | 3,203 |
Estimated payment obligation, 2015 | 12,222 |
Estimated payment obligation, 2016 | 12,101 |
Estimated payment obligation, 2017 | 11,624 |
Estimated payment obligation, 2018 | 7,872 |
Estimated payment obligation, Thereafter | $15,081 |
Commitments_and_Contingencies_5
Commitments and Contingencies - Minimum Commitments to Gather before Other Owner Contributions (Detail) (USD $) | Dec. 31, 2013 | Feb. 01, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Feb. 01, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Feb. 01, 2014 |
In Thousands, unless otherwise specified | Subsequent Event [Member] | Dubach [Member] | Dubach [Member] | Dubach [Member] | Dubberly [Member] | Dubberly [Member] | Dubberly [Member] | |
Subsequent Event [Member] | Subsequent Event [Member] | |||||||
Other Commitments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
2014 | ' | $17,722 | $3,446 | ' | $12,510 | $1,436 | ' | $5,212 |
2014 | 19,346 | ' | ' | 12,925 | ' | ' | 6,421 | ' |
2015 | 25,767 | 25,064 | 13,671 | 12,925 | 13,671 | 11,393 | 12,842 | 11,393 |
2016 | 25,839 | 25,133 | 13,709 | 12,961 | 13,709 | 11,424 | 12,878 | 11,424 |
2017 | 25,767 | 25,064 | 13,671 | 12,925 | 13,671 | 11,393 | 12,842 | 11,393 |
2018 | 21,463 | 23,415 | 12,772 | 10,766 | 12,772 | 10,643 | 10,697 | 10,643 |
Total | $118,182 | $116,398 | $57,269 | $62,502 | $66,333 | $46,289 | $55,680 | $50,065 |
Subsequent_Events_Additional_I
Subsequent Events - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 1 Months Ended | |||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 17, 2014 | Sep. 30, 2014 | Oct. 01, 2014 | Nov. 04, 2014 | Oct. 01, 2014 | Apr. 01, 2014 | Oct. 01, 2014 | Mar. 25, 2014 | Mar. 25, 2014 | |
WildHorse Resources, LLC [Member] | Eagle Ford Acquisition [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | |||||
Leasehold Improvements [Member] | acre | Wells | MEMP [Member] | MEMP [Member] | Eagle Ford Acquisition [Member] | Eagle Ford Acquisition [Member] | |||||||
Non Operated Oil And Natural Gas Properties [Member] | Leasehold Improvements [Member] | ||||||||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business acquisition purchase price | ' | ' | ' | ' | ' | ' | ' | ' | ' | $34,000,000 | $15,000,000 | ' | ' |
Non operating properties acquired percentage | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' |
Number of wells, Gross | ' | ' | ' | ' | ' | ' | ' | ' | 74 | ' | ' | ' | ' |
Underlying acreage associated with overriding royalty interests | ' | ' | ' | ' | ' | ' | ' | 27,000,000,000 | ' | ' | ' | ' | ' |
Percentage of revenue from royalty interests | ' | ' | ' | ' | ' | ' | ' | 7.00% | ' | ' | ' | ' | ' |
Acquisitions of oil and natural gas properties | 1,083,167,000 | 104,926,000 | 105,762,000 | 360,678,000 | ' | ' | ' | ' | ' | ' | ' | 173,000,000 | ' |
Percentage of non-operated properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' |
Percentage of leasehold interest acquired | ' | ' | ' | ' | ' | 30.00% | ' | ' | ' | ' | ' | ' | 30.00% |
Primary term of gas processing agreement | ' | ' | ' | ' | '15 years | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum annual processing fee | ' | ' | ' | ' | $18,300,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Individual_Customers_Each_Acco
Individual Customers Each Accounted for 10% or More of Total Reported Revenues (Detail) (Sales Revenue, Net [Member]) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | |||
Energy Transfer EquityLP. and subsidiaries [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | 35.00% | 13.00% | ||
MRD [Member] | Energy Transfer EquityLP. and subsidiaries [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | 77.00% | 39.00% | ||
MRD [Member] | Sunoco Inc [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | ' | 15.00% | [1] | |
MRD [Member] | Dominion Gas Ventures LP [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | ' | 15.00% | ||
MEMP [Member] | Phillips 66 [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | 15.00% | [2] | 13.00% | [2] |
MEMP [Member] | Conoco Phillips [Member] | ' | ' | ||
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items] | ' | ' | ||
Individual customers each accounted for 10% or more of total reported revenues | ' | 14.00% | [2] | |
[1] | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||
[2] | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. |
Calculation_of_Pro_Forma_Earni
Calculation of Pro Forma Earnings Per Share (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Schedule Of Earnings Per Share [Line Items] | ' | ' | ' | ' | ||
Pro forma net income (loss) | ($964,922) | $174,300 | $151,332 | $26,997 | ||
Noncontrolling interest in pro forma net (income) loss, net of tax | 34,851 | -42,134 | -49,830 | 2,701 | ||
Previous owners interest in pro forma net (income) loss, net of tax | -1,425 | -9,527 | 10,790 | 37,318 | ||
Net income (loss) available to common stockholders | -951,801 | ' | ' | ' | ||
Common shares outstanding immediately following the Offering | ' | ' | 193,676 | [1] | 193,676 | [1] |
Basic EPS | ' | ' | $0.31 | ($0.03) | ||
Diluted EPS | ' | ' | $0.30 | ($0.03) | ||
Pro Forma [Member] | ' | ' | ' | ' | ||
Schedule Of Earnings Per Share [Line Items] | ' | ' | ' | ' | ||
Pro forma net income (loss) | ' | ' | 97,797 | 17,512 | ||
Noncontrolling interest in pro forma net (income) loss, net of tax | ' | ' | -31,861 | 1,745 | ||
Previous owners interest in pro forma net (income) loss, net of tax | ' | ' | -6,899 | -24,111 | ||
Net income (loss) available to common stockholders | ' | ' | $59,037 | ($4,854) | ||
[1] | Includes dilutive effect of 1,176 restricted common shares. |
Calculation_of_Pro_Forma_Earni1
Calculation of Pro Forma Earnings Per Share (Parenthetical) (Detail) (Restricted Stock [Member], Pro Forma [Member]) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Restricted Stock [Member] | Pro Forma [Member] | ' | ' |
Schedule Of Earnings Per Share [Line Items] | ' | ' |
Dilutive effect of restricted common shares | 1,176 | 1,176 |
Calculation_of_Supplemental_Pr
Calculation of Supplemental Pro Forma Earnings Per Share (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Schedule Of Earnings Per Share [Line Items] | ' | ' | ' | ' | ||
Pro forma net income (loss) | ($964,922) | $174,300 | $151,332 | $26,997 | ||
Noncontrolling interest in pro forma net (income) loss, net of tax | 34,851 | -42,134 | -49,830 | 2,701 | ||
Net income (loss) available to common stockholders | -951,801 | ' | ' | ' | ||
Common shares outstanding immediately following the Offering | ' | ' | 193,676 | [1] | 193,676 | [1] |
Supplemental Pro Forma [Member] | ' | ' | ' | ' | ||
Schedule Of Earnings Per Share [Line Items] | ' | ' | ' | ' | ||
Pro forma net income (loss) | ' | ' | 97,797 | 17,512 | ||
Noncontrolling interest in pro forma net (income) loss, net of tax | ' | ' | -31,861 | 1,745 | ||
Net income (loss) available to common stockholders | ' | ' | $65,936 | $19,257 | ||
Common shares outstanding immediately following the Offering | ' | ' | 193,676 | [1] | 193,676 | [1] |
Basic and diluted EPS | ' | ' | $0.34 | $0.10 | ||
[1] | Includes dilutive effect of 1,176 restricted common shares. |
Calculation_of_Supplemental_Pr1
Calculation of Supplemental Pro Forma Earnings Per Share (Parenthetical) (Detail) (Restricted Stock [Member], Supplemental Pro Forma [Member]) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Restricted Stock [Member] | Supplemental Pro Forma [Member] | ' | ' |
Schedule Of Earnings Per Share [Line Items] | ' | ' |
Dilutive effect of restricted common shares | 1,176 | 1,176 |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||||||||||||||||||||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 18, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 18, 2014 | Nov. 22, 2013 | Jul. 13, 2012 | Jun. 18, 2014 | Nov. 22, 2013 | Nov. 01, 2013 | Oct. 01, 2013 | Apr. 25, 2013 | Nov. 20, 2012 | Jul. 13, 2012 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 18, 2013 | Dec. 18, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Nov. 22, 2013 | Nov. 01, 2013 | Oct. 01, 2013 | Apr. 25, 2013 | Nov. 20, 2012 | Jul. 13, 2012 | Jul. 13, 2012 | Dec. 31, 2013 | Nov. 22, 2013 | Jul. 13, 2012 | |
PIK notes [Member] | PIK notes [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | |||||
PIK notes [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | PIK notes [Member] | Minimum [Member] | Maximum [Member] | Revolving Credit Facility [Member] | PIK notes [Member] | PIK notes [Member] | Minimum [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MEMP [Member] | MEMP [Member] | ||||||||||
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | PIK notes [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | PIK notes [Member] | Revolving Credit Facility [Member] | |||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of revolving unused commitment fee | ' | ' | ' | ' | ' | ' | 0.38% | ' | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.38% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility expiration term | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' |
Line of credit facility, aggregate maximum borrowing amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,000,000,000 | ' | ' | ' | ' | $1,000,000,000 | $50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,000,000,000 | ' | $50,000,000 | ' | ' | ' |
Line of credit facility, borrowing base | ' | ' | 1,145,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 725,000,000 | 60,000,000 | 100,000,000 | 120,000,000 | 170,000,000 | 120,000,000 | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | 100,000,000 | 120,000,000 | 170,000,000 | 120,000,000 | ' | 35,000,000 | ' | ' | ' |
Pledged common units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,061,294 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,061,294 |
Pledged subordinated units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,360,912 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,360,912 |
Pledged equity securities sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,061,294 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,061,294 | ' |
Repayments of Lines of Credit | 2,441,900,000 | 900,368,000 | 1,766,037,000 | 251,569,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80,000,000 | 59,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate principal amount | ' | ' | ' | ' | 350,000,000 | 350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate, minimum | ' | ' | ' | ' | 10.00% | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | 10.00% | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' |
Debt interest rate, maximum | ' | ' | ' | ' | 10.75% | 10.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.75% | ' | ' | ' | ' | 10.75% | 10.75% | ' | ' | ' | ' | ' | ' | ' | ' | 10.75% | ' | ' |
Percentage of PIK toggle notes issued at par | ' | ' | ' | ' | 98.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 98.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash reserve for payment of interest on notes | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payment of distribution to funds | ' | $363,437,000 | $732,362,000 | ' | $210,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $732,362,000 | ' | $220,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other event of default minimum note holder percentage to accelerate | ' | ' | ' | ' | ' | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long_Term_Debt_Classic_Revolvi
Long Term Debt - Classic Revolving Credit Facility - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | |||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 20, 2012 | Jun. 21, 2010 | Nov. 01, 2007 | Nov. 01, 2007 | |
Classic [Member] | Classic [Member] | Classic [Member] | Classic [Member] | |||||
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | |||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility expiration term | ' | ' | ' | ' | ' | ' | '4 years | ' |
Revolving credit facility was collateralized | ' | ' | ' | ' | ' | ' | ' | $150,000,000 |
Payment of revolving credit plus accrued interest | $2,441,900,000 | $900,368,000 | $1,766,037,000 | $251,569,000 | $80,000,000 | ' | ' | ' |
Debt Instrument, maturity date | ' | ' | ' | ' | ' | 21-Jun-14 | ' | ' |
Long_Term_Debt_Black_Diamond_R
Long Term Debt - Black Diamond Revolving Credit Facility - Additional Information (Detail) (Black Diamond [Member], Revolving Credit Facility [Member], USD $) | 0 Months Ended | |
Jul. 27, 2011 | Nov. 01, 2013 | |
Black Diamond [Member] | Revolving Credit Facility [Member] | ' | ' |
Debt Obligations [Line Items] | ' | ' |
Debt Instrument, maturity date | 9-May-15 | ' |
Long-term debt | ' | $0 |
Accrued Interest payable | ' | $0 |
Long_Term_Debt_BlueStone_Revol
Long Term Debt - BlueStone Revolving Credit Facility - Additional Information (Detail) (BlueStone Natural Resources Holdings, LLC [Member], Revolving Credit Facility [Member], USD $) | 0 Months Ended | |||
Jun. 25, 2010 | Aug. 27, 2013 | Dec. 31, 2012 | Jul. 08, 2009 | |
BlueStone Natural Resources Holdings, LLC [Member] | Revolving Credit Facility [Member] | ' | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' | ' |
Revolving credit facility | $150,000,000 | ' | ' | $150,000,000 |
Long-term debt | ' | $0 | $0 | ' |
Debt Instrument, maturity date | 25-Jun-14 | ' | ' | ' |
Long_Term_Debt_Tanos_Revolving
Long Term Debt - Tanos Revolving Credit Facility - Additional Information (Detail) (Tanos Energy LLC [Member], Revolving Credit Facility [Member], USD $) | 0 Months Ended | |||
In Millions, unless otherwise specified | Apr. 25, 2013 | Apr. 01, 2013 | Dec. 16, 2010 | Dec. 16, 2010 |
Tanos Energy LLC [Member] | Revolving Credit Facility [Member] | ' | ' | ' | ' |
Debt Obligations [Line Items] | ' | ' | ' | ' |
Revolving credit facility expiration term | ' | ' | '4 years | ' |
Revolving credit facility | ' | ' | ' | $250 |
Payment of revolving credit | ' | $27 | ' | ' |
Debt instrument, pay off date | 25-Apr-13 | ' | ' | ' |
Long_Term_Debt_MEMP_WHT_Revolv
Long Term Debt - MEMP WHT Revolving Credit Facility - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | |||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 28, 2013 | Apr. 08, 2011 |
WHT Energy Partners LLC [Member] | WHT Energy Partners LLC [Member] | |||||
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | |||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' |
Lien percentage of assets for credit facility | ' | ' | ' | ' | ' | 80.00% |
Payment of revolving credit plus accrued interest | $2,441,900 | $900,368 | $1,766,037 | $251,569 | $89,300 | ' |
Long_Term_Debt_Stanolind_Revol
Long Term Debt - Stanolind Revolving Credit Facility - Additional Information (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 09, 2010 | Dec. 31, 2012 |
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | ||
Stanolind [Member] | Stanolind [Member] | Amendment [Member] | ||
Stanolind [Member] | ||||
Debt Obligations [Line Items] | ' | ' | ' | ' |
Revolving credit facility | ' | $250,000,000 | $50,000,000 | ' |
.Line of credit facility, initial borrowing base | $1,145,000,000 | $75,000,000 | ' | $97,000,000 |
Debt Instrument, maturity date | ' | 13-Jul-17 | ' | ' |
Long_Term_Debt_Boaz_Revolving_
Long Term Debt - Boaz Revolving Credit Facility - Additional Information (Detail) (Revolving Credit Facility [Member], Boaz [Member], USD $) | 0 Months Ended | |
In Millions, unless otherwise specified | Aug. 01, 2011 | Aug. 01, 2011 |
Revolving Credit Facility [Member] | Boaz [Member] | ' | ' |
Debt Obligations [Line Items] | ' | ' |
Revolving credit facility | ' | $75 |
Debt Instrument, maturity date | 31-Aug-15 | ' |
Debt instrument, pay off date | 1-Oct-13 | ' |
Long_Term_Debt_Crown_Revolving
Long Term Debt - Crown Revolving Credit Facility - Additional Information (Detail) (Revolving Credit Facility [Member], Crown [Member], USD $) | 0 Months Ended | |
In Millions, unless otherwise specified | Jan. 28, 2010 | Jan. 28, 2010 |
Revolving Credit Facility [Member] | Crown [Member] | ' | ' |
Debt Obligations [Line Items] | ' | ' |
Revolving credit facility | ' | $75 |
Debt Instrument, maturity date | 25-Oct-16 | ' |
Debt instrument, pay off date | 1-Oct-13 | ' |
Long_Term_Debt_Propel_Energy_R
Long Term Debt - Propel Energy Revolving Credit Facility - Additional Information (Detail) (Revolving Credit Facility [Member], Propel Energy [Member], USD $) | 0 Months Ended | |
In Millions, unless otherwise specified | Jun. 15, 2011 | Jun. 15, 2011 |
Revolving Credit Facility [Member] | Propel Energy [Member] | ' | ' |
Debt Obligations [Line Items] | ' | ' |
Revolving credit facility | ' | $200 |
Debt Instrument, maturity date | 15-Jun-15 | ' |
Debt instrument, pay off date | 1-Oct-13 | ' |
Long_Term_Debt_Reo_Revolving_C
Long Term Debt - Reo Revolving Credit Facility - Additional Information (Detail) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | ||||
Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 12, 2012 | Oct. 26, 2011 | Oct. 26, 2011 | |
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | |||||
REO Sponsorship [Member] | REO Sponsorship [Member] | REO Sponsorship [Member] | |||||
Debt Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility expiration term | ' | ' | ' | ' | ' | '3 years | ' |
Revolving credit facility | ' | ' | ' | ' | ' | ' | $150,000,000 |
Payment of revolving credit | $2,441,900,000 | $900,368,000 | $1,766,037,000 | $251,569,000 | $28,500,000 | ' | ' |
Business_Segment_Data_Schedule2
Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Parenthetical) (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Impairment of proved oil and natural gas properties | $67,181 | $21 | $6,600 | $28,871 |
East Texas Properties [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Impairment of proved oil and natural gas properties | ' | ' | ' | 20,900 |
East Texas Properties [Member] | MEMP [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Impairment of proved oil and natural gas properties | ' | ' | $50,300 | ' |
Environmental_Reserves_Activit
Environmental Reserves Activity (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Commitments and Contingencies Disclosure [Abstract] | ' | ' |
Balance at beginning of period | $1,469 | $1,747 |
Charged to costs and expenses | ' | 193 |
Payments | -892 | -471 |
Balance at end of period | $577 | $1,469 |
Commitments_and_Contingencies_6
Commitments and Contingencies - Gross Held-to-Maturity Investments (Parenthetical) (Detail) (US Treasury Notes Securities [Member]) | 12 Months Ended |
Dec. 31, 2013 | |
US Treasury Notes Securities [Member] | ' |
Held-to-maturity Securities [Abstract] | ' |
Debt Instrument, maturity date | 30-Jun-14 |
Interest rate | 1.75% |
Commitments_and_Contingencies_7
Commitments and Contingencies - Minimum Lease Payment Obligations Under Non-Cancelable Operating Leases (Detail) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Leases [Abstract] | ' |
Total | $20,325 |
2014 | 2,389 |
2015 | 2,546 |
2016 | 2,583 |
2017 | 2,718 |
2018 | 2,783 |
Thereafter | $7,306 |
Commitments_and_Contingencies_8
Commitments and Contingencies - Minimum Commitments for Drilling and Compression Services Agreements (Detail) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Supply Commitment [Line Items] | ' |
Total | $118,182 |
2014 | 19,346 |
2015 | 25,767 |
2016 | 25,839 |
2017 | 25,767 |
2018 | 21,463 |
Drilling services [Member] | ' |
Supply Commitment [Line Items] | ' |
Total | 20,323 |
2014 | 20,323 |
Thereafter | ' |
Compression Services [Member] | ' |
Supply Commitment [Line Items] | ' |
Total | 7,090 |
2014 | 7,079 |
2015 | 11 |
Thereafter | ' |
Defined_Contribution_Plans_Add
Defined Contribution Plans - Additional Information (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Y | ||
Defined Contribution Plan Disclosure [Line Items] | ' | ' |
Matching contribution | 100.00% | ' |
Employee eligibility age | 18 | ' |
Tax-deferred contributions | 100.00% | ' |
Contribution By Participants, Percentage | 6.00% | ' |
Employer contributions | $0.90 | $0.40 |
REO Sponsorship [Member] | ' | ' |
Defined Contribution Plan Disclosure [Line Items] | ' | ' |
Matching contribution | 100.00% | ' |
Employee eligibility age | 21 | ' |
Tax-deferred contributions | 100.00% | ' |
Contribution By Participants, Percentage | 6.00% | ' |
Employer contributions | 0.6 | 0.5 |
Defined contribution plan, company contribution, vesting period, years | '3 years | ' |
Defined benefit plan cost and expense | 0.3 | 0.3 |
WildHorse, Tanos, BlueStone, Classic and Black Diamond [Member] | ' | ' |
Defined Contribution Plan Disclosure [Line Items] | ' | ' |
Employer contributions | 0.5 | 0.6 |
Stanolind [Member] | ' | ' |
Defined Contribution Plan Disclosure [Line Items] | ' | ' |
Employer contributions | $0.10 | $0.10 |
Capitalized_Costs_Relating_to_
Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) (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] | ' | ' | ||
Evaluated oil and natural gas properties | $2,985,370 | [1] | $2,597,621 | [1] |
Unevaluated oil and natural gas properties | 46,413 | 31,593 | ||
Accumulated depletion, depreciation, and amortization | -623,362 | [1] | -468,291 | [1] |
Subtotal | 2,408,421 | 2,160,923 | ||
Other, Adjustments & Eliminations [Member] | ' | ' | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ||
Accumulated depletion, depreciation, and amortization | 49,884 | [1] | ' | |
MRD [Member] | ' | ' | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ||
Evaluated oil and natural gas properties | 1,226,417 | 1,052,219 | ||
Unevaluated oil and natural gas properties | 46,413 | 26,589 | ||
Accumulated depletion, depreciation, and amortization | -256,629 | -202,581 | ||
Subtotal | 1,016,201 | 876,227 | ||
MEMP [Member] | ' | ' | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ||
Evaluated oil and natural gas properties | 1,758,953 | [1] | 1,545,402 | [1] |
Unevaluated oil and natural gas properties | ' | 5,004 | ||
Accumulated depletion, depreciation, and amortization | -416,617 | [1] | -265,710 | [1] |
Subtotal | $1,342,336 | $1,284,696 | ||
[1] | Amounts do not include costs for SPBPC and related support equipment. |
Costs_Incurred_for_Property_Ac
Costs Incurred for Property Acquisition, Exploration and Development (Detail) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ||
Property acquisition costs, proved | $93,894 | $366,103 | ||
Property acquisition costs, unproved | 19,975 | 5,293 | ||
Exploration and extension well costs | 13,313 | 42,642 | ||
Development | 356,270 | [1] | 198,423 | [1] |
Subtotal | 483,452 | 612,461 | ||
MRD [Member] | ' | ' | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ||
Property acquisition costs, proved | 56,108 | 87,857 | ||
Property acquisition costs, unproved | 19,975 | 5,293 | ||
Exploration and extension well costs | 13,313 | 212 | ||
Development | 210,440 | 135,951 | ||
Subtotal | 299,836 | 229,313 | ||
MEMP [Member] | ' | ' | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ||
Property acquisition costs, proved | 37,786 | 278,246 | ||
Exploration and extension well costs | ' | 42,430 | ||
Development | 145,830 | [1] | 62,472 | [1] |
Subtotal | $183,616 | $383,148 | ||
[1] | Amounts do not include costs for SPBPC and related support equipment. |
Weighted_Average_Product_Price
Weighted Average Product Price (Detail) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | |||
Oil [Member] | ' | ' | ||
Supplemental Oil And Gas Reserve Information [Line Items] | ' | ' | ||
Spot | 93.42 | [1] | 91.33 | [1] |
Natural Gas Liquids [Member] | ' | ' | ||
Supplemental Oil And Gas Reserve Information [Line Items] | ' | ' | ||
Spot | 93.42 | [1] | 91.75 | [1] |
Natural Gas [Member] | ' | ' | ||
Supplemental Oil And Gas Reserve Information [Line Items] | ' | ' | ||
Spot | 3.67 | [2] | 2.75 | [2] |
[1] | The unweighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential. | |||
[2] | The unweighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. |
Reserve_Quantity_Information_D
Reserve Quantity Information (Detail) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | |||
MMcfe | MMcfe | |||
MRD [Member] | Natural Gas Equivalent [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 1,059,895 | [1] | 1,312,533 | |
Extensions and discoveries | 210,652 | 62,819 | ||
Purchase of minerals in place | 39,183 | 45,987 | ||
Production | -46,819 | -31,731 | ||
Sales of minerals in place | -27,169 | -752 | ||
Revision of previous estimates | -110,165 | -328,961 | ||
End of year | 1,125,577 | [2] | 1,059,895 | [1] |
Beginning of year | 337,869 | 250,073 | ||
End of year | 367,641 | 337,869 | ||
Beginning of year | 722,026 | 1,062,460 | ||
End of year | 757,936 | 722,026 | ||
MRD [Member] | Oil [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 11,953 | [1] | 10,834 | |
Extensions and discoveries | 1,794 | 689 | ||
Purchase of minerals in place | 211 | 1,100 | ||
Production | -665 | -369 | ||
Sales of minerals in place | -599 | -4 | ||
Revision of previous estimates | -1,383 | -297 | ||
End of year | 11,311 | [2] | 11,953 | [1] |
Beginning of year | 3,082 | 2,107 | ||
End of year | 3,402 | 3,082 | ||
Beginning of year | 8,871 | 8,727 | ||
End of year | 7,909 | 8,871 | ||
MRD [Member] | Natural Gas [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 739,378 | [1] | 929,335 | |
Extensions and discoveries | 149,974 | 42,019 | ||
Purchase of minerals in place | 31,815 | 28,115 | ||
Production | -34,092 | -24,131 | ||
Sales of minerals in place | -14,137 | -728 | ||
Revision of previous estimates | -70,684 | -235,232 | ||
End of year | 802,254 | [2] | 739,378 | [1] |
Beginning of year | 245,449 | 191,557 | ||
End of year | 263,797 | 245,449 | ||
Beginning of year | 493,929 | 737,778 | ||
End of year | 538,457 | 493,929 | ||
MRD [Member] | Natural Gas Liquids [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 41,466 | [1] | 53,031 | |
Extensions and discoveries | 8,319 | 2,778 | ||
Purchase of minerals in place | 1,017 | 1,879 | ||
Production | -1,457 | -898 | ||
Sales of minerals in place | -1,573 | ' | ||
Revision of previous estimates | -5,196 | -15,324 | ||
End of year | 42,576 | [2] | 41,466 | [1] |
Beginning of year | 12,321 | 7,644 | ||
End of year | 13,904 | 12,321 | ||
Beginning of year | 29,145 | 45,387 | ||
End of year | 28,672 | 29,145 | ||
MEMP [Member] | Natural Gas Equivalent [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 1,015,095 | [3],[4] | 832,913 | |
Extensions and discoveries | 85,180 | 71,192 | ||
Purchase of minerals in place | 18,554 | 224,202 | ||
Production | -56,303 | -43,329 | ||
Sales of minerals in place | ' | -29,499 | ||
Revision of previous estimates | -47,421 | -40,384 | ||
End of year | 1,015,105 | [5] | 1,015,095 | [3],[4] |
Beginning of year | 619,704 | 589,504 | ||
End of year | 616,893 | 619,704 | ||
Beginning of year | 395,391 | 243,409 | ||
End of year | 398,212 | 395,391 | ||
MEMP [Member] | Oil [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 39,089 | [3],[4] | 27,150 | |
Extensions and discoveries | 5,655 | 7,501 | ||
Purchase of minerals in place | 119 | 11,336 | ||
Production | -1,764 | -1,519 | ||
Sales of minerals in place | ' | -4,214 | ||
Revision of previous estimates | -3,950 | -1,165 | ||
End of year | 39,149 | [5] | 39,089 | [3],[4] |
Beginning of year | 24,515 | 19,332 | ||
End of year | 22,265 | 24,515 | ||
Beginning of year | 14,574 | 7,818 | ||
End of year | 16,884 | 14,574 | ||
MEMP [Member] | Natural Gas [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 604,440 | [3],[4] | 579,751 | |
Extensions and discoveries | 40,770 | 19,869 | ||
Purchase of minerals in place | 16,294 | 113,617 | ||
Production | -35,924 | -29,744 | ||
Sales of minerals in place | ' | -4,214 | ||
Revision of previous estimates | -18,441 | -74,839 | ||
End of year | 607,139 | [5] | 604,440 | [3],[4] |
Beginning of year | 376,932 | 413,431 | ||
End of year | 387,548 | 376,932 | ||
Beginning of year | 227,508 | 166,320 | ||
End of year | 219,591 | 227,508 | ||
MEMP [Member] | Natural Gas Liquids [Member] | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ||
Beginning of year | 29,352 | [3],[4] | 15,045 | |
Extensions and discoveries | 1,747 | 1,053 | ||
Purchase of minerals in place | 258 | 7,095 | ||
Production | -1,632 | -745 | ||
Revision of previous estimates | -879 | 6,904 | ||
End of year | 28,846 | [5] | 29,352 | [3],[4] |
Beginning of year | 15,947 | 10,015 | ||
End of year | 15,959 | 15,947 | ||
Beginning of year | 13,405 | 5,030 | ||
End of year | 12,887 | 13,405 | ||
[1] | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||
[2] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||
[3] | Includes reserves of 406,324 MMcfe attributable to common control acquisitions. | |||
[4] | MRD Segment's share of these reserves is 476,550 MMcfe. | |||
[5] | MRD Segment's share of these reserves is 89,837 MMcfe. |
Reserve_Quantity_Information_P
Reserve Quantity Information (Parenthetical) (Detail) (Natural Gas Equivalent [Member]) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
MMcfe | MMcfe | MMcfe | |||
Noncontrolling Interest [Member] | ' | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ' | ||
End of year | 41,077 | 67,135 | ' | ||
MRD [Member] | ' | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ' | ||
End of year | 1,125,577 | [1] | 1,059,895 | [2] | 1,312,533 |
MRD [Member] | Noncontrolling Interest [Member] | ' | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ' | ||
End of year | 89,837 | 476,550 | ' | ||
MEMP [Member] | ' | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ' | ||
End of year | 1,015,105 | [3] | 1,015,095 | [4],[5] | 832,913 |
MEMP [Member] | Common [Member] | ' | ' | ' | ||
Reserve Quantities [Line Items] | ' | ' | ' | ||
End of year | ' | 406,324 | ' | ||
[1] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||
[2] | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | ||||
[3] | MRD Segment's share of these reserves is 89,837 MMcfe. | ||||
[4] | Includes reserves of 406,324 MMcfe attributable to common control acquisitions. | ||||
[5] | MRD Segment's share of these reserves is 476,550 MMcfe. |
Recovered_Sheet1
Supplemental Oil And Gas Information - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Bcfe | Bcfe | |
MRD [Member] | WildHorse Resources, LLC [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Extensions and discoveries | 148.6 | 43.5 |
MEMP [Member] | Multiple Acquisition [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Purchase of minerals in place | ' | 224.2 |
MEMP [Member] | Goodrich Acquisition [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Purchase of minerals in place | ' | 148.9 |
Stanolind And Propel Energy [Member] | Multiple Acquisition [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Purchase of minerals in place | ' | 43.6 |
Stanolind And Propel Energy [Member] | Menemsha Acquisition [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Purchase of minerals in place | ' | 23.9 |
Stanolind And Propel Energy [Member] | Natural Gas Partners [Member] | ' | ' |
Reserve Quantities [Line Items] | ' | ' |
Purchase of minerals in place | ' | 19 |
Discounted_Future_Net_Cash_Flo
Discounted Future Net Cash Flow (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
In Thousands, unless otherwise specified | |||||
MRD [Member] | ' | ' | ' | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | ||
Future cash inflows | $5,722,848 | $4,921,192 | ' | ||
Future production costs | -1,587,374 | -1,255,289 | ' | ||
Future development costs | -1,352,945 | -1,060,777 | ' | ||
Future net cash flows for estimated timing of cash flows | 2,782,529 | [1] | 2,605,126 | [1] | ' |
10% annual discount for estimated timing of cash flows | -1,313,577 | -1,284,531 | ' | ||
Standardized measure of discounted future net cash flows | 1,468,952 | [2] | 1,320,595 | [2] | 1,386,071 |
MEMP [Member] | ' | ' | ' | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | ||
Future cash inflows | 6,892,150 | 6,511,776 | ' | ||
Future production costs | -2,719,024 | -2,258,554 | ' | ||
Future development costs | -685,858 | -620,944 | ' | ||
Future net cash flows for estimated timing of cash flows | 3,487,268 | [3] | 3,632,278 | [3] | ' |
10% annual discount for estimated timing of cash flows | -1,879,156 | -2,042,362 | ' | ||
Standardized measure of discounted future net cash flows | $1,608,112 | [4],[5] | $1,589,916 | [4],[5] | $1,499,414 |
[1] | We are subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas to immateriality we have excluded the impact of this tax. However, had we not been a tax exempt entity future income tax for the years ended December 31, 2013 and 2012 would have been $760,433 and $647,464, respectively. | ||||
[2] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | ||||
[3] | MEMP is subject to the Texas Franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax. MEMP is organized as a pass-through entity for income tax purposes. Had we not been a tax exempt entity our share of future income tax related to our ownership of MEMP for the years ended December 31, 2013 and 2012 would have been $61,300 and $306,297, respectively. | ||||
[4] | Includes $503,021 attributable to the MEMP previous owners for the year ended December 31, 2012. | ||||
[5] | MRD Segment's share of the standardized measure of discounted future net cash flows was $142,318 and $554,981 for the years ended December 31, 2013 and 2012, respectively. |
Discounted_Future_Net_Cash_Flo1
Discounted Future Net Cash Flow (Parenthetical) (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | ||||
In Thousands, unless otherwise specified | Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MRD [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | MEMP [Member] | Maximum [Member] | Maximum [Member] | ||||
Previous Owners [Member] | Previous Owners [Member] | Texas Franchise Tax [Member] | Texas Franchise Tax [Member] | Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | Previous Owners [Member] | Texas Franchise Tax [Member] | Texas Franchise Tax [Member] | MRD [Member] | MEMP [Member] | |||||||||||
Texas Franchise Tax [Member] | Texas Franchise Tax [Member] | ||||||||||||||||||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Franchise effective tax rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.70% | 0.70% | ||||
Future net cash flows for estimated timing of cash flows | ' | ' | ' | ' | ' | $760,433 | $647,464 | ' | ' | ' | ' | ' | ' | $61,300 | $306,297 | ' | ' | ||||
Standardized measure of discounted future net cash flows | $63,422 | $78,518 | $1,468,952 | [1] | $1,320,595 | [1] | $1,386,071 | ' | ' | $142,318 | $554,981 | $1,608,112 | [2],[3] | $1,589,916 | [2],[3] | $1,499,414 | $503,021 | ' | ' | ' | ' |
[1] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | ||||||||||||||||||||
[2] | Includes $503,021 attributable to the MEMP previous owners for the year ended December 31, 2012. | ||||||||||||||||||||
[3] | MRD Segment's share of the standardized measure of discounted future net cash flows was $142,318 and $554,981 for the years ended December 31, 2013 and 2012, respectively. |
Summary_of_the_Changes_in_the_
Summary of the Changes in the Standardized Measure of Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
MRD [Member] | ' | ' | ||
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items] | ' | ' | ||
Beginning of year | $1,320,595 | [1] | $1,386,071 | |
Sale of oil and natural gas produced, net of production costs | -196,444 | -107,316 | ||
Purchase of minerals in place | 51,177 | 98,384 | ||
Sale of minerals in place | -54,091 | ' | ||
Extensions and discoveries | 301,004 | 127,994 | ||
Changes in prices and costs | -11,336 | -402,202 | ||
Previously estimated development costs incurred | 87,297 | 64,390 | ||
Net changes in future development costs | 57,353 | -67,331 | ||
Revisions of previous quantities | -186,804 | -176,788 | ||
Accretion of discount | 128,544 | 138,607 | ||
Change in production rates and other | -28,343 | 258,786 | ||
End of year | 1,468,952 | [1] | 1,320,595 | [1] |
MEMP [Member] | ' | ' | ||
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items] | ' | ' | ||
Beginning of year | 1,589,916 | [2],[3] | 1,499,414 | |
Sale of oil and natural gas produced, net of production costs | -234,520 | -160,023 | ||
Purchase of minerals in place | 23,160 | 375,953 | ||
Sale of minerals in place | ' | -154,963 | ||
Extensions and discoveries | 136,423 | 265,108 | ||
Changes in income taxes, net | ' | 1,947 | ||
Changes in prices and costs | -74,395 | -331,760 | ||
Previously estimated development costs incurred | 174,490 | 66,360 | ||
Net changes in future development costs | -74,867 | -1,140 | ||
Revisions of previous quantities | -141,122 | -90,587 | ||
Accretion of discount | 158,991 | 150,136 | ||
Change in production rates and other | 50,036 | -30,529 | ||
End of year | $1,608,112 | [2],[3] | $1,589,916 | [2],[3] |
[1] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | |||
[2] | Includes $503,021 attributable to the MEMP previous owners for the year ended December 31, 2012. | |||
[3] | MRD Segment's share of the standardized measure of discounted future net cash flows was $142,318 and $554,981 for the years ended December 31, 2013 and 2012, respectively. |
Schedule_Condensed_Financial_I
Schedule - Condensed Financial Information - Condensed Balance Sheets (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | |||||
Current assets: | ' | ' | ' | ' | ' |
Cash and cash equivalents | $10,316 | $77,721 | $82,945 | $49,391 | $53,964 |
Restricted cash | ' | 35,000 | ' | 2,013 | ' |
Accounts receivable: | ' | ' | ' | ' | ' |
Affiliates | ' | 4,652 | ' | 77 | ' |
Prepaid expenses and other current assets | 20,696 | 19,513 | ' | 13,577 | ' |
Total current assets | 190,127 | 234,897 | ' | 188,808 | ' |
Property and equipment, at cost: | ' | ' | ' | ' | ' |
Accumulated depreciation, depletion and impairment | -877,843 | -627,925 | ' | -471,949 | ' |
Oil and natural gas properties, net | 3,681,810 | 2,419,704 | ' | 2,175,437 | ' |
Long-term derivative instruments | 34,515 | 48,616 | ' | 17,179 | ' |
Restricted cash | 260 | 15,506 | ' | ' | ' |
Other long-term assets | 38,687 | 37,053 | ' | 9,856 | ' |
Total assets | 4,021,667 | 2,829,161 | ' | 2,459,304 | ' |
Current liabilities: | ' | ' | ' | ' | ' |
Accounts payable | 16,846 | 20,734 | ' | 36,633 | ' |
Accrued liabilities | 179,381 | 98,130 | ' | 33,487 | ' |
Total current liabilities | 261,658 | 186,641 | ' | 125,754 | ' |
Other long-term liabilities | ' | 3,412 | ' | 3,846 | ' |
Total liabilities | 2,562,668 | 1,971,029 | ' | 1,182,595 | ' |
Commitments and contingencies | ' | ' | ' | ' | ' |
Equity: | ' | ' | ' | ' | ' |
Members | ' | 237,186 | ' | 811,614 | ' |
Previous Owners | ' | 40,331 | ' | 233,433 | ' |
Total liabilities and equity | 4,021,667 | 2,829,161 | ' | 2,459,304 | ' |
MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | ' | ' | ' | ' | ' |
Current assets: | ' | ' | ' | ' | ' |
Cash and cash equivalents | ' | 19,293 | ' | 8,019 | 5,530 |
Restricted cash | ' | 35,000 | ' | ' | ' |
Accounts receivable: | ' | ' | ' | ' | ' |
Affiliates | ' | 90,917 | ' | 84,347 | ' |
Other | ' | ' | ' | 3 | ' |
Prepaid expenses and other current assets | ' | 2,802 | ' | 707 | ' |
Total current assets | ' | 148,012 | ' | 93,076 | ' |
Property and equipment, at cost: | ' | ' | ' | ' | ' |
Furniture and fixtures | ' | 1,679 | ' | 1,217 | ' |
Accumulated depreciation, depletion and impairment | ' | -547 | ' | -199 | ' |
Oil and natural gas properties, net | ' | 1,132 | ' | 1,018 | ' |
Long-term derivative instruments | ' | ' | ' | ' | ' |
Investments in subsidiary | ' | 411,657 | ' | 797,868 | ' |
Investments in previous owners | ' | 40,331 | ' | 233,433 | ' |
Restricted cash | ' | 15,000 | ' | ' | ' |
Other long-term assets | ' | 6,596 | ' | 259 | ' |
Total assets | ' | 622,728 | ' | 1,125,654 | ' |
Current liabilities: | ' | ' | ' | ' | ' |
Accounts payable | ' | 130 | ' | 161 | ' |
Accrued liabilities | ' | 1,896 | ' | 225 | ' |
Total current liabilities | ' | 2,026 | ' | 386 | ' |
Long-term debt | ' | 343,050 | ' | 80,000 | ' |
Other long-term liabilities | ' | 135 | ' | 221 | ' |
Total liabilities | ' | 345,211 | ' | 80,607 | ' |
Commitments and contingencies | ' | ' | ' | ' | ' |
Equity: | ' | ' | ' | ' | ' |
Members | ' | 237,186 | ' | 811,614 | ' |
Previous Owners | ' | 40,331 | ' | 233,433 | ' |
Total liabilities and equity | ' | $622,728 | ' | $1,125,654 | ' |
Schedule_Condensed_Financial_I1
Schedule - Condensed Financial Information - Condensed Statements of Income (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Costs and expenses: | ' | ' | ' | ' |
Depreciation, depletion, and amortization | $215,906 | $132,328 | $184,717 | $138,672 |
General and administrative | 61,061 | 55,982 | 125,358 | 69,187 |
(Gain) loss on commodity derivative instruments | 11,580 | -29,556 | -29,294 | -34,905 |
Total costs and expenses | 1,481,335 | 205,096 | 352,967 | 336,867 |
Operating income (loss) | -808,450 | 217,645 | 222,056 | 60,001 |
Other income (expense): | ' | ' | ' | ' |
Interest expense, net | -104,928 | -41,994 | -69,250 | -33,238 |
Total other income (expense) | -142,074 | -41,913 | -69,105 | -32,897 |
Net income (loss) | -964,922 | 174,300 | 151,332 | 26,997 |
MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | ' | ' | ' | ' |
Costs and expenses: | ' | ' | ' | ' |
Depreciation, depletion, and amortization | ' | ' | 348 | 195 |
General and administrative | ' | ' | 20,111 | 10,176 |
(Gain) loss on commodity derivative instruments | ' | ' | 546 | ' |
Total costs and expenses | ' | ' | 21,005 | 10,371 |
Operating income (loss) | ' | ' | -21,005 | -10,371 |
Other income (expense): | ' | ' | ' | ' |
Equity income (loss) from subsidiaries | ' | ' | 114,974 | 2,970 |
Equity income (loss) from previous owners | ' | ' | 10,790 | 37,318 |
Interest expense, net | ' | ' | -3,257 | -219 |
Total other income (expense) | ' | ' | 122,507 | 40,069 |
Net income (loss) | ' | ' | $101,502 | $29,698 |
Schedule_Condensed_Financial_I2
Schedule - Condensed Financial Information - Condensed Statements of Cash Flows (Detail) (USD $) | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Condensed Cash Flow Statements, Captions [Line Items] | ' | ' | ' | ' |
Net cash provided by (used in) operating activities | $365,460 | $237,176 | $277,823 | $240,404 |
Cash flows from investing activities: | ' | ' | ' | ' |
Proceeds from changes in ownership interests in MEMP | ' | ' | 135,012 | ' |
Changes in restricted cash | 49,946 | 653 | -49,347 | -3 |
Net cash (used in) provided by investing activities | -1,496,677 | -235,883 | -367,443 | -606,738 |
Cash flows from financing activities: | ' | ' | ' | ' |
Advances on revolving credit facility | 2,464,800 | 478,055 | 1,132,755 | 619,450 |
Payments on revolving credit facility | -2,441,900 | -900,368 | -1,766,037 | -251,569 |
Proceeds from issuance of senior notes | 1,092,425 | 397,563 | 1,031,563 | ' |
Loan origination fees | -30,284 | -23,839 | -41,175 | -3,501 |
Distributions to the Funds | ' | -363,437 | -732,362 | ' |
Net cash (used in) provided by financing activities | 1,063,812 | 32,261 | 117,950 | 361,761 |
Net change in cash and cash equivalents | -67,405 | 33,554 | 28,330 | -4,573 |
Cash and cash equivalents, beginning of period | 77,721 | 49,391 | 49,391 | 53,964 |
Cash and cash equivalents, end of period | 10,316 | 82,945 | 77,721 | 49,391 |
MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | ' | ' | ' | ' |
Condensed Cash Flow Statements, Captions [Line Items] | ' | ' | ' | ' |
Net cash provided by (used in) operating activities | ' | ' | -3,556 | -75,088 |
Cash flows from investing activities: | ' | ' | ' | ' |
Investments in subsidiaries | ' | ' | -40,666 | -718 |
Additions to furniture and fixtures | ' | ' | -461 | -903 |
Proceeds from changes in ownership interests in MEMP | ' | ' | 135,012 | ' |
Changes in restricted cash | ' | ' | -50,000 | ' |
Net cash (used in) provided by investing activities | ' | ' | 43,885 | -1,621 |
Cash flows from financing activities: | ' | ' | ' | ' |
Advances on revolving credit facility | ' | ' | ' | 80,000 |
Payments on revolving credit facility | ' | ' | -80,000 | ' |
Proceeds from issuance of senior notes | ' | ' | 343,000 | ' |
Distributions received from subsidiaries (see Note 3) | ' | ' | 448,349 | ' |
Loan origination fees | ' | ' | -8,042 | -802 |
Distributions to the Funds | ' | ' | -732,362 | ' |
Net cash (used in) provided by financing activities | ' | ' | -29,055 | 79,198 |
Net change in cash and cash equivalents | ' | ' | 11,274 | 2,489 |
Cash and cash equivalents, beginning of period | ' | 8,019 | 8,019 | 5,530 |
Cash and cash equivalents, end of period | ' | ' | $19,293 | $8,019 |
LongTerm_Debt_Obligations_Unde
Long-Term Debt - Obligations Under Revolving Credit Facilities (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
In Thousands, unless otherwise specified | ||||
Debt Instrument [Line Items] | ' | ' | ' | |
Total long-term debt | $2,111,800 | $1,663,217 | $939,382 | |
MRD [Member] | 1.0 billion revolving credit facility [Member] | ' | ' | ' | |
Debt Instrument [Line Items] | ' | ' | ' | |
Credit facility | ' | ' | 80,000 | |
MRD [Member] | PIK notes [Member] | ' | ' | ' | |
Debt Instrument [Line Items] | ' | ' | ' | |
Senior Notes | ' | 350,000 | [1] | ' |
MRD [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | ' | ' | ' | |
Debt Instrument [Line Items] | ' | ' | ' | |
Total long-term debt | ' | 343,050 | 80,000 | |
MRD [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | 1.0 billion revolving credit facility [Member] | ' | ' | ' | |
Debt Instrument [Line Items] | ' | ' | ' | |
Credit facility | ' | ' | 80,000 | |
MRD [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | PIK notes [Member] | ' | ' | ' | |
Debt Instrument [Line Items] | ' | ' | ' | |
Senior Notes | ' | 350,000 | ' | |
Unamortized discounts | ' | ($6,950) | ' | |
[1] | The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. |
LongTerm_Debt_Obligations_Unde1
Long-Term Debt - Obligations Under Revolving Credit Facilities (Parenthetical) (Detail) (USD $) | 0 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 18, 2013 | Sep. 30, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 18, 2013 | Dec. 31, 2013 | Nov. 20, 2012 | Dec. 31, 2012 | Dec. 31, 2013 |
PIK notes [Member] | PIK notes [Member] | MRD [Member] | MRD [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | |
1.0 billion revolving credit facility [Member] | PIK notes [Member] | PIK notes [Member] | PIK notes [Member] | MRD [Member] | MRD [Member] | MRD [Member] | |||
1.0 billion revolving credit facility [Member] | PIK notes [Member] | ||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt interest rate, minimum | 10.00% | 10.00% | ' | 10.00% | 10.00% | 10.00% | ' | ' | 10.00% |
Revolving credit facility | ' | ' | $1,000 | ' | ' | ' | $1,000 | $1,000 | ' |
Debt interest rate, maximum | 10.75% | 10.75% | ' | 10.75% | 10.75% | 10.75% | ' | ' | 10.75% |
Debt Instrument, maturity date | ' | 15-Dec-18 | 31-Dec-13 | 15-Dec-18 | ' | ' | ' | 31-Dec-13 | 31-Dec-18 |
Distribution_From_Subsidiaries
Distribution From Subsidiaries (Detail) (MEMORIAL RESOURCE DEVELOPMENT LLC [Member], USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
MEMORIAL RESOURCE DEVELOPMENT LLC [Member] | ' | ' |
Distribution Made to Limited Liability Company (LLC) Member [Line Items] | ' | ' |
Distributions received from subsidiaries | $25,966 | $19,228 |