Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Feb. 23, 2015 | Jun. 30, 2014 |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | LEGACY RESERVES LP | ||
Entity Central Index Key | 1358831 | ||
Current Fiscal Year End Date | -19 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | FALSE | ||
Entity Common Stock, Shares Outstanding | 69,208,533 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $1.50 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash | $725 | $2,584 |
Accounts receivable, net: | ||
Oil and natural gas | 49,390 | 47,429 |
Joint interest owners | 16,235 | 16,532 |
Other | 237 | 626 |
Fair value of derivatives (Notes 8 and 9) | 120,305 | 3,801 |
Prepaid expenses and other current assets | 5,362 | 3,727 |
Total current assets | 192,254 | 74,699 |
Oil and natural gas properties, at cost: | ||
Proved oil and natural gas properties using the successful efforts method of accounting | 2,946,820 | 2,265,788 |
Unproved properties | 47,613 | 58,392 |
Accumulated depletion, depreciation, amortization and impairment | -1,354,459 | -788,751 |
Total oil and natural gas assets | 1,639,974 | 1,535,429 |
Other property and equipment, net of accumulated depreciation and amortization of $7,446 and $6,053, respectively | 3,767 | 3,688 |
Operating rights, net of amortization of $4,509 and $4,024, respectively | 2,508 | 2,992 |
Fair value of derivatives (Notes 8 and 9) | 32,794 | 21,292 |
Other assets, net of amortization of $12,551 and $10,097, respectively | 24,255 | 17,641 |
Investments in equity method investees | 3,054 | 4,092 |
Total assets | 1,898,606 | 1,659,833 |
Current liabilities: | ||
Accounts payable | 2,787 | 6,016 |
Accrued oil and natural gas liabilities (Note 1) | 78,615 | 63,161 |
Fair value of derivatives (Notes 8 and 9) | 2,080 | 10,060 |
Asset retirement obligation (Note 11) | 3,028 | 2,610 |
Other (Notes 8 and 13) | 11,066 | 12,043 |
Total current liabilities | 97,576 | 93,890 |
Long-term debt (Note 3) | 938,876 | 878,693 |
Asset retirement obligation (Note 11) | 223,497 | 173,176 |
Fair value of derivatives (Notes 8 and 9) | 0 | 2,119 |
Other long-term liabilities | 1,452 | 1,559 |
Total liabilities | 1,261,401 | 1,149,437 |
Commitments and contingencies (Note 6) | ||
Partners’ equity: | ||
Limited partners' equity - 68,910,784 and 57,280,049 units issued and outstanding at December 31, 2014 and 2013, respectively | 376,885 | 510,322 |
General partner’s equity (approximately 0.03%) | 53 | 74 |
Total partners’ equity | 637,205 | 510,396 |
Total liabilities and partners’ equity | 1,898,606 | 1,659,833 |
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2014 | ||
Partners’ equity: | ||
Incentive distribution equity | 30,814 | 0 |
Total partners’ equity | 30,814 | 0 |
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2014 | ||
Partners’ equity: | ||
Preferred equity | 55,192 | 0 |
Total partners’ equity | 55,192 | 0 |
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2014 | ||
Partners’ equity: | ||
Preferred equity | 174,261 | 0 |
Total partners’ equity | $174,261 | $0 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | 12 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Other property and equipment, accumulated depreciation and amortization | $7,446 | $6,053 |
Operating rights, amortization | 4,509 | 4,024 |
Other assets, amortization | $12,551 | $10,097 |
Limited partners' equity, units issued (in shares) | 68,910,784 | 57,280,049 |
Limited partners' equity, units outstanding (in shares) | 68,910,784 | 57,280,049 |
General partner's equity, percent | 0.03% | 0.03% |
Incentive Distribution Equity | ||
Incentive distribution equity, units issued (in shares) | 100,000 | 0 |
Incentive distribution equity, units outstanding (in shares) | 100,000 | 0 |
Preferred Unit Series A | ||
Preferred equity, units issued (in shares) | 2,300,000 | 0 |
Preferred equity, units outstanding (in shares) | 2,300,000 | 0 |
Preferred Unit Series B | ||
Preferred equity, units issued (in shares) | 7,200,000 | 0 |
Preferred equity, units outstanding (in shares) | 7,200,000 | 0 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Oil sales | $396,774 | $405,536 | $286,254 |
Natural gas liquids (NGL) sales | 27,483 | 14,095 | 14,592 |
Natural gas sales | 108,042 | 65,858 | 45,614 |
Total revenues | 532,299 | 485,489 | 346,460 |
Expenses: | |||
Oil and natural gas production | 198,801 | 154,679 | 112,951 |
Production and other taxes | 31,534 | 29,508 | 20,778 |
General and administrative | 38,980 | 28,907 | 24,526 |
Depletion, depreciation, amortization and accretion | 173,686 | 158,415 | 102,144 |
Impairment of long-lived assets | 448,714 | 85,757 | 37,066 |
(Gain) loss on disposal of assets | -2,479 | 579 | -2,496 |
Total expenses | 889,236 | 457,845 | 294,969 |
Operating income (loss) | -356,937 | 27,644 | 51,491 |
Other income (expense): | |||
Interest income | 873 | 776 | 16 |
Interest expense (Notes 3, 8 and 9) | -67,218 | -50,089 | -20,260 |
Equity in income of equity method investees | 428 | 559 | 111 |
Net gains (losses) on commodity derivatives (Notes 8 and 9) | 138,092 | -13,531 | 38,493 |
Other | 258 | 18 | -118 |
Income (loss) before income taxes | -284,504 | -34,623 | 69,733 |
Income tax (expense) benefit | 859 | -649 | -1,096 |
Net income (loss) | -283,645 | -35,272 | 68,637 |
Distributions to preferred unitholders | -11,694 | 0 | 0 |
Net income (loss) attributable to unitholders | ($295,339) | ($35,272) | $68,637 |
Income (loss) per unit — basic and diluted (Note 12) (in dollars per share) | ($4.92) | ($0.62) | $1.40 |
Weighted average number of units used in computing net income per unit — | |||
Basic (in shares) | 60,053 | 57,220 | 48,991 |
Diluted (in shares) | 60,053 | 57,220 | 48,991 |
Consolidated_Statements_of_Uni
Consolidated Statements of Unitholders Equity (USD $) | Total | Limited Partner [Member] | General Partner [Member] | Incentive Distribution Equity | Preferred Units | Preferred Unit Series A | Preferred Unit Series B |
In Thousands, except Share data, unless otherwise specified | |||||||
Unitholders equity, beginning balance at Dec. 31, 2011 | $488,335 | $488,264 | $71 | $0 | $0 | $0 | |
Unitholders equity, beginning balance (in shares) at Dec. 31, 2011 | 47,802,000 | 0 | 0 | 0 | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||
Units issued to for services (in shares) | 20,000 | ||||||
Units issued for services | 568 | 568 | |||||
Unit-based compensation | 1,762 | 1,762 | |||||
Vesting of restricted and phantom units (in shares) | 47,000 | ||||||
Net proceeds from equity offering / Issuance of units, net (in shares) | 9,170,000 | ||||||
Net proceeds from equity offering / Issuance of units, net | 217,998 | 217,998 | |||||
Units issued in exchange for oil and natural gas properties and investment in equity method investee | 0 | ||||||
Distributions to unitholders, $2.33, $2.31 and $2.405 per unit for the years ended December 31, 2012, 2013, and 2014, respectively | -107,020 | -107,020 | |||||
Net income (loss) | 68,637 | 68,611 | 26 | ||||
Unitholders equity, ending balance at Dec. 31, 2012 | 670,280 | 670,183 | 97 | 0 | 0 | 0 | |
Unitholders equity, ending balance (in shares) at Dec. 31, 2012 | 57,039,000 | 0 | 0 | 0 | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||
Units issued to for services (in shares) | 18,000 | ||||||
Units issued for services | 509 | 509 | |||||
Unit-based compensation | 3,582 | 3,582 | |||||
Vesting of restricted and phantom units (in shares) | 70,000 | ||||||
Offering costs associated with the issuance of units | -25 | -25 | |||||
Units issued in exchange for oil and natural gas properties and investment in equity method investee (in shares) | 153,000 | ||||||
Units issued in exchange for oil and natural gas properties and investment in equity method investee | 4,001 | 4,001 | |||||
Redemption of general partner interest | -12 | -12 | |||||
Distributions to unitholders, $2.33, $2.31 and $2.405 per unit for the years ended December 31, 2012, 2013, and 2014, respectively | -132,667 | -132,667 | |||||
Net income (loss) | -35,272 | -35,261 | -11 | ||||
Unitholders equity, ending balance at Dec. 31, 2013 | 510,396 | 510,322 | 74 | 0 | 0 | 0 | |
Unitholders equity, ending balance (in shares) at Dec. 31, 2013 | 57,280,000 | 0 | 0 | 0 | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||
Units issued to for services (in shares) | 18,000 | 2,300,000 | 7,200,000 | ||||
Units issued for services | 499 | 499 | 229,453 | 55,192 | 174,261 | ||
Unit-based compensation | 3,797 | 3,797 | |||||
Vesting of restricted and phantom units (in shares) | 113,000 | ||||||
Net proceeds from equity offering / Issuance of units, net (in shares) | 11,500,000 | ||||||
Net proceeds from equity offering / Issuance of units, net | 303,457 | 303,457 | |||||
Units issued in exchange for oil and natural gas properties and investment in equity method investee (in shares) | 100,000 | ||||||
Units issued in exchange for oil and natural gas properties and investment in equity method investee | 30,814 | 30,814 | |||||
Distributions to preferred unitholders | -11,694 | -11,694 | |||||
Distributions to unitholders, $2.33, $2.31 and $2.405 per unit for the years ended December 31, 2012, 2013, and 2014, respectively | -145,872 | -145,872 | |||||
Net income (loss) | -283,645 | -283,624 | -21 | ||||
Unitholders equity, ending balance at Dec. 31, 2014 | $637,205 | $376,885 | $53 | $30,814 | $55,192 | $174,261 | |
Unitholders equity, ending balance (in shares) at Dec. 31, 2014 | 68,911,000 | 100,000 | 2,300,000 | 7,200,000 |
Consolidated_Statements_of_Uni1
Consolidated Statements of Unitholders Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Statement of Partners' Capital [Abstract] | |||
Distributions to unitholders (in dollars per share) | $2.40 | $2.31 | $2.23 |
Consolidated_Statement_of_Cash
Consolidated Statement of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income (loss) | ($283,645) | ($35,272) | $68,637 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depletion, depreciation, amortization and accretion | 173,686 | 158,415 | 102,144 |
Amortization of debt discount and issuance costs | 4,637 | 3,780 | 1,626 |
Impairment of long-lived assets | 448,714 | 85,757 | 37,066 |
(Gains) losses on derivatives | -140,771 | 8,743 | -40,999 |
Equity in income of equity method investees | -428 | -559 | -111 |
Distribution from equity method investee | 1,467 | 861 | 0 |
Unit-based compensation | 2,089 | 3,142 | 26 |
(Gain) loss on disposal of assets | -2,479 | 579 | -2,496 |
Changes in assets and liabilities: | |||
Increase in accounts receivable, oil and natural gas | -1,962 | -9,882 | -2,058 |
(Increase) decrease in accounts receivable, joint interest owners | 297 | 11,319 | -17,552 |
(Increase) decrease in accounts receivable, other | 389 | -75 | -347 |
(Increase) decrease in other assets | -1,193 | 618 | 231 |
Increase (decrease) in accounts payable | -3,228 | 4,194 | -1,464 |
Increase in accrued oil and natural gas liabilities | 15,454 | 12,999 | 4,811 |
Increase (decrease) in other liabilities | -5,811 | -3,485 | 127 |
Total adjustments | 490,861 | 276,406 | 81,004 |
Net cash provided by operating activities | 207,216 | 241,134 | 149,641 |
Cash flows from investing activities: | |||
Investment in oil and natural gas properties | -638,942 | -202,419 | -702,945 |
Proceeds from sale of assets | 5,334 | 2,566 | 9,780 |
Investment in other equipment | -1,472 | -2,492 | -1,246 |
Goodwill | 0 | 0 | -7,770 |
Net cash settlements on commodity derivatives | 2,666 | -7,056 | 5,902 |
Net cash used in investing activities | -632,414 | -209,401 | -696,279 |
Cash flows from financing activities: | |||
Proceeds from long-term debt | 1,333,000 | 802,263 | 931,784 |
Payments of long-term debt | -1,275,000 | -701,000 | -493,000 |
Payments of debt issuance costs | -10,005 | -1,217 | -2,766 |
Proceeds from issuance of limited partner interests, net | 532,910 | -25 | 217,998 |
Redemption of general partner interest | 0 | -12 | 0 |
Distributions to unitholders | -157,566 | -132,667 | -107,020 |
Net cash provided by (used in) financing activities | 423,339 | -32,658 | 546,996 |
Net increase (decrease) in cash and cash equivalents | -1,859 | -925 | 358 |
Cash and cash equivalents, beginning of period | 2,584 | 3,509 | 3,151 |
Cash and cash equivalents, end of period | 725 | 2,584 | 3,509 |
Non-Cash Investing and Financing Activities: | |||
Asset retirement obligation costs and liabilities | 941 | 494 | 878 |
Asset retirement obligations associated with property acquisitions | 50,487 | 10,969 | 38,857 |
Asset retirement obligations associated with properties sold | -5,891 | -1,606 | 0 |
Units issued in exchange for investment in equity method investee | 0 | 4,001 | 0 |
Incentive Distribution units issued in exchange for oil and natural gas properties | 30,814 | 0 | 0 |
Note receivable received in exchange for the sale of oil and natural gas properties | $0 | $11,857 | $0 |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies | |||||||
(a) Organization, Basis of Presentation and Description of Business | ||||||||
Legacy Reserves LP (“LRLP,” “Legacy” or the “Partnership”) and its affiliated entities are referred to as Legacy in these financial statements. | ||||||||
LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and it currently owns an approximately 0.03% general partner interest in LRLP. | ||||||||
Significant information regarding rights of the unitholders includes the following: | ||||||||
• | Right to receive distributions of available cash within 45 days after the end of each quarter. | |||||||
• | No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage LRLP’s activities. | |||||||
• | The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRLP’s general partner and its affiliates. | |||||||
• | Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year. | |||||||
In the event of a liquidation, after making required payments to Legacy's preferred unitholders, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation. | ||||||||
Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin (West Texas and Southeast New Mexico), Rocky Mountain and Mid-Continent regions of the United States. Legacy has acquired oil and natural gas producing properties and drilled and undrilled leasehold. | ||||||||
The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. | ||||||||
(b) Trade Accounts Receivable | ||||||||
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10). | ||||||||
(c) Oil and Natural Gas Properties | ||||||||
Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. | ||||||||
Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. | ||||||||
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. | ||||||||
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2014, Legacy recognized $448.7 million of impairment expense, $413.3 million of of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014, which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2013, Legacy recognized $78.0 million of impairment expense on 98 separate producing fields, due primarily to the decrease in commodity prices primarily related to natural gas differentials during the year ended December 31, 2013, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. The remaining $7.8 million was impairment of unproven properties acquired since 2010 that were no longer viable. For the year ended December 31, 2012, Legacy recognized $22.8 million of impairment expense on 64 separate producing fields due primarily to the decrease in commodity prices during the year ended December 31, 2012, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. In 2012, Legacy also recognized $6.5 million of impairment related to the reduction in the carrying value of a property that Legacy entered into an option to sell. Finally, Legacy recognized $7.8 million of impairment of goodwill during 2012 related to a decline in oil futures prices between announcement and closing date of a transaction, as hedging does not impact the associated fair value of properties for purposes of measuring impairment. | ||||||||
Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2014, Legacy recognized $35.0 million of impairment of unproven properties. | ||||||||
(d) Oil, NGLs and Natural Gas Reserve Quantities | ||||||||
Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. | ||||||||
Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. | ||||||||
Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered. | ||||||||
(e) Income Taxes | ||||||||
Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. | ||||||||
The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. | ||||||||
Legacy recorded income tax (expense) benefit of $0.9 million, $(0.6) million and $(1.1) million for the years ended December 31, 2014, 2013 and 2012, respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. | ||||||||
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.5 billion at December 31, 2014. | ||||||||
(f) Derivative Instruments and Hedging Activities | ||||||||
Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil, NGL and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil, NGL and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9). | ||||||||
(g) Use of Estimates | ||||||||
Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. | ||||||||
(h) Revenue Recognition | ||||||||
Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. | ||||||||
To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. | ||||||||
Legacy uses the “net-back” method of accounting for transportation arrangements of its natural gas sales. Legacy sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its purchasers and reflected in the wellhead price. Legacy’s contracts with respect to the sale of its natural gas produced, with one immaterial exception, provide Legacy with a net price payment. That is, when Legacy is paid for its natural gas by its purchasers, Legacy receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of Legacy’s contracts, the payment statements Legacy receives from its purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, Legacy’s revenues are recorded at this single net price. | ||||||||
Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2014, 2013 and 2012. | ||||||||
Legacy is paid a monthly operating fee for each well it operates for outside owners proportionate to each owner's working interest. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense. | ||||||||
(i) Investments | ||||||||
Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition. | ||||||||
(j) Intangible assets | ||||||||
Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life. The expected amortization expenses for 2015, 2016, 2017, 2018 and 2019 are $444,000, $417,000, $396,000, $358,000 and $349,000, respectively. | ||||||||
(k) Environmental | ||||||||
Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. | ||||||||
(l) Income (Loss) Per Unit | ||||||||
Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12). | ||||||||
(m) Redemption of Units | ||||||||
Units redeemed are recorded at cost. | ||||||||
(n) Segment Reporting | ||||||||
Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes. | ||||||||
(o) Unit-Based Compensation | ||||||||
Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of | ||||||||
each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2014, do not include 254,183 units related to unvested restricted unit awards. | ||||||||
(p) Accrued Oil and Natural Gas Liabilities | ||||||||
Below are the components of accrued oil and natural gas liabilities as of December 31, 2014 and 2013. | ||||||||
December 31, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Revenue payable to joint interest owners | $ | 19,267 | $ | 21,686 | ||||
Accrued lease operating expense | 21,177 | 11,914 | ||||||
Accrued capital expenditures | 20,773 | 10,409 | ||||||
Accrued ad valorem tax | 9,382 | 9,459 | ||||||
Other | 8,016 | 9,693 | ||||||
$ | 78,615 | $ | 63,161 | |||||
Fair_Values_of_Financial_Instr
Fair Values of Financial Instruments | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Values of Financial Instruments | Fair Values of Financial Instruments | ||||||||||||||||
The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts as discussed below: | |||||||||||||||||
Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $244.5 million and $449.6 million, respectively, as of December 31, 2014. As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. | |||||||||||||||||
Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. | |||||||||||||||||
Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. | |||||||||||||||||
Fair Value Measurements | |||||||||||||||||
Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: | |||||||||||||||||
Level 1: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | ||||||||||||||||
Level 2: | Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date. | ||||||||||||||||
Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. | ||||||||||||||||
As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of 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. | |||||||||||||||||
Fair Value on a Recurring Basis | |||||||||||||||||
The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013: | |||||||||||||||||
Fair Value Measurements Using | |||||||||||||||||
Quoted Prices in | Significant Other | Significant | Total Carrying | ||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | Value as of | |||||||||||||
(In thousands) | |||||||||||||||||
LTIP liability(a) | $ | — | $ | (11 | ) | $ | — | $ | (11 | ) | |||||||
Oil and natural gas derivatives | — | 152,544 | 555 | 153,099 | |||||||||||||
Interest rate swaps | — | (2,080 | ) | — | (2,080 | ) | |||||||||||
Total as of December 31, 2014 | $ | — | $ | 150,453 | $ | 555 | $ | 151,008 | |||||||||
LTIP liability(a) | $ | — | $ | (2,217 | ) | $ | — | $ | (2,217 | ) | |||||||
Oil and natural gas derivatives | — | (2,942 | ) | 20,615 | 17,673 | ||||||||||||
Interest rate swaps | — | (4,759 | ) | — | (4,759 | ) | |||||||||||
Total as of December 31, 2013 | $ | — | $ | (9,918 | ) | $ | 20,615 | $ | 10,697 | ||||||||
____________________ | |||||||||||||||||
(a) | See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. | ||||||||||||||||
Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under | |||||||||||||||||
the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. | |||||||||||||||||
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: | |||||||||||||||||
Significant | |||||||||||||||||
Unobservable | |||||||||||||||||
Inputs | |||||||||||||||||
(Level 3) | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(In thousands) | |||||||||||||||||
Beginning balance | $ | 20,615 | $ | 29,966 | $ | 30,054 | |||||||||||
Total gains (losses) | (6,185 | ) | 4,671 | 18,993 | |||||||||||||
Settlements | 677 | (6,722 | ) | (19,081 | ) | ||||||||||||
Transfers | (14,552 | ) | (a) | (7,300 | ) | (b) | — | ||||||||||
Ending balance | $ | 555 | $ | 20,615 | $ | 29,966 | |||||||||||
Gains included in earnings relating to derivatives | |||||||||||||||||
still held as of December 31, 2014, 2013 and 2012 | $ | 555 | $ | 1,407 | $ | 16,065 | |||||||||||
(a) | During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. | ||||||||||||||||
(b) | During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2. | ||||||||||||||||
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. | |||||||||||||||||
Fair Value on a Non-Recurring Basis | |||||||||||||||||
Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. | |||||||||||||||||
A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 11. | |||||||||||||||||
Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2014 and 2013 consist of: | |||||||||||||||||
Quoted Prices in | Significant Other | Significant | |||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | ||||||||||||||
(In thousands) | |||||||||||||||||
2014 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 254,266 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 536,334 | |||||||||||
2013 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 76,137 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 108,415 | |||||||||||
____________________ | |||||||||||||||||
(a) | Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended December 31, 2014, Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 million. During the year ended December 31, 2013, Legacy incurred impairment charges of $78.0 million as oil and natural gas properties with a net cost basis of $154.1 million were written down to their fair value of $76.1 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. | ||||||||||||||||
The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that are no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. In 2013, Legacy recognized an additional $7.8 million of impairment of unproved properties acquired since 2010 that are no longer viable. | |||||||||||||||||
(b) | Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2014, Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2013, Legacy acquired oil and natural gas properties with a fair value of $108.4 million in 16 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Long-Term Debt | Long-Term Debt | ||||||||
Long-term debt consists of the following at December 31, 2014 and 2013: | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Credit Facility due 2019 | $ | 109,000 | 348,000 | ||||||
8% Senior Notes due 2020 | 300,000 | 300,000 | |||||||
6.625% Senior Notes due 2021 | 550,000 | 250,000 | |||||||
959,000 | 898,000 | ||||||||
Unamortized discount on Senior Notes | (20,124 | ) | (19,307 | ) | |||||
Total long term debt | $ | 938,876 | $ | 878,693 | |||||
Credit Facility | |||||||||
Previous Credit Agreement: On March 10, 2011, Legacy entered into a five-year $1 billion secured revolving credit facility (as amended, the "Previous Credit Agreement"). Borrowings under the Previous Credit Agreement were set to mature on March 10, 2016. | |||||||||
Current Credit Agreement: On April 1, 2014, Legacy entered into a five-year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent (the "Current Credit Agreement") which replaced the Previous Credit Agreement. Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 80% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the lesser of the borrowing base and the facility amount and contains a $2 million sub-limit for letters of credit. The borrowing base at December 31, 2014 was set at $950 million, but was redetermined on February 23, 2015 pursuant to the Fourth Amendment to the revolving credit facility. Please see Note 15, Subsequent Events for more details. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.5% to 2.5%, or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00%, plus an applicable margin from 0.5% to 1.5% per annum, determined by the percentage of the borrowing base then in effect that is drawn. | |||||||||
The Current Credit Agreement contains various covenants that limit Legacy's ability to: (i) incur indebtedness, (ii) enter into certain leases, (iii) grant certain liens, (iv) enter into certain swaps, (v) make certain loans, acquisitions, capital expenditures and investments, (vi) make distributions other than from available cash, (vii) merge, consolidate or allow any material change in the character of its business and (viii) engage in certain asset dispositions, including a sale of all or substantially all of its assets. The Current Credit Agreement also contains covenants that, among other things, require Legacy to maintain specified ratios or conditions. As of December 31, 2014 these covenants were as follows: (i) total debt to EBITDA of not more than 4.5 to 1.0 through June 15, 2015 and 4.0 to 1.0 thereafter and (ii) consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives. These covenants were amended pursuant to the Fourth Amendment to the revolving credit facility. Please see Note 15, Subsequent Events for further details. | |||||||||
As of December 31, 2014, Legacy had outstanding borrowings of $109 million under the Current Credit Agreement at a weighted average interest rate of 2.12%. Thus, Legacy had approximately $840.9 million of borrowing availability remaining. For the year ended December 31, 2014, Legacy paid $8.9 million of interest expense on both the Previous and Current Credit Agreements. | |||||||||
At December 31, 2014, Legacy was in compliance with all covenants contained in the Current Credit Agreement. | |||||||||
8% Senior Notes Due 2020 | |||||||||
On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 8% Senior Notes due 2020 (the "2020 Senior Notes"), which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. | |||||||||
Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. | |||||||||
Year | Percentage | ||||||||
2016 | 104 | % | |||||||
2017 | 102 | % | |||||||
2018 | 100 | % | |||||||
Prior to December 1, 2016, Legacy may redeem all or any part of the 2020 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to December 1, 2015, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes at the redemption price of 108% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 14 - Subsidiary Guarantors for further details on Legacy's guarantors. | |||||||||
The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of | |||||||||
such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. The Partnership is in compliance with all covenants of the 2020 Senior Notes. | |||||||||
Interest is payable on June 1 and December 1 of each year. | |||||||||
6.625% Senior Notes Due 2021 | |||||||||
On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes"), which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. | |||||||||
On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 6.625% 2021 Senior Notes. These 2021 Senior Notes were issued at 99% of par. | |||||||||
The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the maturity date, interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. | |||||||||
Year | Percentage | ||||||||
2017 | 103.313 | % | |||||||
2018 | 101.656 | % | |||||||
2019 and thereafter | 100 | % | |||||||
Prior to June 1, 2017, Legacy may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to June 1, 2016, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at the redemption price of 106.625% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. The Partnership is in compliance with all covenants of the 2021 Senior Notes. | |||||||||
Interest is payable on June 1 and December 1 of each year. |
Acquisitions
Acquisitions | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Business Combinations [Abstract] | |||||||||||||
Acquisitions | Acquisitions | ||||||||||||
COG 2012 Acquisition | |||||||||||||
On December 20, 2012, Legacy purchased certain oil and natural gas properties located primarily in the Permian Basin from COG Operating LLC and Concho Oil and Gas LLC, both wholly owned subsidiaries of Concho Resources Inc., for a net cash purchase price of $502.6 million (the “COG 2012 Acquisition”). The purchase price was financed with net proceeds from Legacy’s November 2012 public offering of units and the 2020 Senior Notes. The effective date of this purchase was October 1, 2012. The operating results from these COG 2012 Acquisition properties have been included from their acquisition on December 20, 2012. | |||||||||||||
The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): | |||||||||||||
Proved oil and natural gas properties including related equipment | $ | 495,897 | |||||||||||
Unproved properties | 37,994 | ||||||||||||
Total assets | $ | 533,891 | |||||||||||
Future abandonment costs | (31,274 | ) | |||||||||||
Fair value of net assets acquired | $ | 502,617 | |||||||||||
WPX Acquisition | |||||||||||||
On June 4, 2014, Legacy purchased a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy Rocky Mountain, LLC , a subsidiary of WPX Energy, Inc., (the "WPX Acquisition") for a net purchase price of $360.0 million. Consideration included both cash and 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units"), 100,000 of which vested immediately and the remainder of which are available to vest and also subject to forfeiture pursuant to the terms of a related Incentive Distribution Unitholder Agreement. This acquisition was accounted for as a business combination. The 100,000 vested Incentive Distribution Units have been reflected in the financial statements at their estimated issuance date fair value of $30.8 million. No value was ascribed to the unvested Incentive Distribution Units upon the closing of the WPX Acquisition as the vesting of the unvested Incentive Distribution Units is dependent upon the consummation of future transactions with WPX and such Incentive Distribution Units will be a portion of the consideration of any such future transactions. During the year ended December 31, 2014, Legacy incurred acquisition costs, recorded in general and administrative expense, of approximately $5.4 million related to the WPX Acquisition and other acquisitions. | |||||||||||||
The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): | |||||||||||||
Proved oil and natural gas properties including related equipment | $ | 403,980 | |||||||||||
Future abandonment costs | (43,989 | ) | |||||||||||
Fair value of net assets acquired | $ | 359,991 | |||||||||||
Pro Forma Operating Results | |||||||||||||
The following table reflects the unaudited pro forma results of operations as though the COG 2012 Acquisition had occurred on January 1, 2011 and the WPX Acquisition had occurred on January 1, 2013. The pro forma amounts are not necessarily indicative of the results that may be reported in the future: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Revenues | $ | 569,674 | $ | 549,968 | $ | 478,115 | |||||||
Net income | $ | (289,659 | ) | $ | (50,041 | ) | $ | 97,092 | |||||
Income (loss) per unit — basic and diluted | $ | (4.82 | ) | $ | (0.87 | ) | $ | 1.71 | |||||
Units used in computing income (loss) per unit: | |||||||||||||
Basic | 60,053 | 57,220 | 56,887 | ||||||||||
Diluted | 60,053 | 57,220 | 56,887 | ||||||||||
The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the COG 2012 Acquisition and the WPX Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
COG 2012 Acquisition | (In thousands) | ||||||||||||
Revenues | $ | 96,560 | $ | 113,222 | $ | 3,693 | |||||||
Excess of revenues over direct operating expenses | $ | 54,320 | $ | 73,408 | $ | 2,654 | |||||||
WPX Acquisition | |||||||||||||
Revenues | $ | 48,470 | $ | — | $ | — | |||||||
Excess of revenues over direct operating expenses | $ | 22,333 | $ | — | $ | — | |||||||
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions |
Cary D. Brown, Legacy’s Chairman, President and Chief Executive Officer, and Kyle A. McGraw, Director and Legacy’s Executive Vice President and Chief Development Officer, own interests in partnerships which, in turn, own a combined non-controlling 4.16% interest as limited partners in a partnership which, until November 10, 2014, owned the building that Legacy occupies. Monthly rent is $64,841 without respect to property taxes and insurance. The lease expires in September 2020. | |
During the year ended December 31, 2012, Legacy acquired a 5% working interest in prospective Cline Shale acreage from FireWheel Energy, LLC ("FireWheel"), the operator of the properties, for $7.2 million. During the year ended December 31, 2013, Legacy acquired a 5% working interest in additional acreage from Firewheel for $1.2 million. FireWheel is a private-equity funded oil and natural gas exploration company in which Alan Brown, brother of Cary D. Brown, is a principal. The interests acquired by Legacy were marketed to numerous industry participants and are governed by an industry standard Participation Agreement and Joint Operating Agreement. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies |
From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows. | |
Legacy is party to a contractual agreement, extending through 2022, to purchase CO2 volumes from a third party. The contract requires Legacy to purchase minimum annual volumes, the pricing of which is calculated as a percentage of NYMEX-WTI oil prices, with a floor of $57.14. Based upon the minimum required volumes and the NYMEX-WTI strip prices as of December 31, 2014, we estimate the value of our total future obligation to be approximately $61.6 million. | |
Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected. | |
Legacy has employment agreements with its officers that specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively. |
Business_and_Credit_Concentrat
Business and Credit Concentrations | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Risks and Uncertainties [Abstract] | ||||||
Business and Credit Concentrations | Business and Credit Concentrations | |||||
Cash | ||||||
Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. | ||||||
Revenue and Trade Receivables | ||||||
Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2014, 2013 or 2012. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. | ||||||
Commodity Derivatives | ||||||
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or three-way collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2014, Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $153.1 million, collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. | ||||||
Sales to Major Customers | ||||||
Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues for the years ended December 31, 2014, 2013 and 2012 to the customers shown below: | ||||||
2014 | 2013 | 2012 | ||||
Enterprise (Teppco) Crude Oil, LP | 12% | 17% | 12% | |||
Plains Marketing, LP | 10% | 7% | 10% | |||
In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Legacy believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurements | Fair Values of Financial Instruments | ||||||||||||||||
The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts as discussed below: | |||||||||||||||||
Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $244.5 million and $449.6 million, respectively, as of December 31, 2014. As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. | |||||||||||||||||
Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. | |||||||||||||||||
Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. | |||||||||||||||||
Fair Value Measurements | |||||||||||||||||
Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: | |||||||||||||||||
Level 1: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | ||||||||||||||||
Level 2: | Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date. | ||||||||||||||||
Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. | ||||||||||||||||
As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of 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. | |||||||||||||||||
Fair Value on a Recurring Basis | |||||||||||||||||
The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013: | |||||||||||||||||
Fair Value Measurements Using | |||||||||||||||||
Quoted Prices in | Significant Other | Significant | Total Carrying | ||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | Value as of | |||||||||||||
(In thousands) | |||||||||||||||||
LTIP liability(a) | $ | — | $ | (11 | ) | $ | — | $ | (11 | ) | |||||||
Oil and natural gas derivatives | — | 152,544 | 555 | 153,099 | |||||||||||||
Interest rate swaps | — | (2,080 | ) | — | (2,080 | ) | |||||||||||
Total as of December 31, 2014 | $ | — | $ | 150,453 | $ | 555 | $ | 151,008 | |||||||||
LTIP liability(a) | $ | — | $ | (2,217 | ) | $ | — | $ | (2,217 | ) | |||||||
Oil and natural gas derivatives | — | (2,942 | ) | 20,615 | 17,673 | ||||||||||||
Interest rate swaps | — | (4,759 | ) | — | (4,759 | ) | |||||||||||
Total as of December 31, 2013 | $ | — | $ | (9,918 | ) | $ | 20,615 | $ | 10,697 | ||||||||
____________________ | |||||||||||||||||
(a) | See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. | ||||||||||||||||
Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under | |||||||||||||||||
the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. | |||||||||||||||||
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: | |||||||||||||||||
Significant | |||||||||||||||||
Unobservable | |||||||||||||||||
Inputs | |||||||||||||||||
(Level 3) | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(In thousands) | |||||||||||||||||
Beginning balance | $ | 20,615 | $ | 29,966 | $ | 30,054 | |||||||||||
Total gains (losses) | (6,185 | ) | 4,671 | 18,993 | |||||||||||||
Settlements | 677 | (6,722 | ) | (19,081 | ) | ||||||||||||
Transfers | (14,552 | ) | (a) | (7,300 | ) | (b) | — | ||||||||||
Ending balance | $ | 555 | $ | 20,615 | $ | 29,966 | |||||||||||
Gains included in earnings relating to derivatives | |||||||||||||||||
still held as of December 31, 2014, 2013 and 2012 | $ | 555 | $ | 1,407 | $ | 16,065 | |||||||||||
(a) | During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. | ||||||||||||||||
(b) | During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2. | ||||||||||||||||
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. | |||||||||||||||||
Fair Value on a Non-Recurring Basis | |||||||||||||||||
Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. | |||||||||||||||||
A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 11. | |||||||||||||||||
Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2014 and 2013 consist of: | |||||||||||||||||
Quoted Prices in | Significant Other | Significant | |||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | ||||||||||||||
(In thousands) | |||||||||||||||||
2014 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 254,266 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 536,334 | |||||||||||
2013 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 76,137 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 108,415 | |||||||||||
____________________ | |||||||||||||||||
(a) | Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended December 31, 2014, Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 million. During the year ended December 31, 2013, Legacy incurred impairment charges of $78.0 million as oil and natural gas properties with a net cost basis of $154.1 million were written down to their fair value of $76.1 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. | ||||||||||||||||
The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that are no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. In 2013, Legacy recognized an additional $7.8 million of impairment of unproved properties acquired since 2010 that are no longer viable. | |||||||||||||||||
(b) | Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2014, Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2013, Legacy acquired oil and natural gas properties with a fair value of $108.4 million in 16 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. |
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||
Derivative Financial Instruments | Derivative Financial Instruments | ||||||||||||
Commodity derivative transactions | |||||||||||||
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes. | |||||||||||||
These derivative instruments are intended to mitigate a portion of Legacy’s price-risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings. | |||||||||||||
By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties, who currently are all current or former members of Legacy's lending group. | |||||||||||||
The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2014, 2013, and 2012. | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Beginning fair value of commodity derivatives | $ | 17,673 | $ | 24,148 | $ | (8,443 | ) | ||||||
Total gain (loss) crude oil derivatives | 101,813 | (11,977 | ) | 34,257 | |||||||||
Total gain (loss) natural gas derivatives | 36,279 | (1,554 | ) | 4,236 | |||||||||
Crude oil derivative cash settlements paid | 5,431 | 14,160 | 10,211 | ||||||||||
Natural gas derivative cash settlements received | (8,097 | ) | (7,104 | ) | (16,113 | ) | |||||||
Ending fair value of commodity derivatives | $ | 153,099 | $ | 17,673 | $ | 24,148 | |||||||
Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands): | |||||||||||||
December 31, 2014 | |||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||||
Offsetting Derivative Assets: | (In thousands) | ||||||||||||
Commodity derivatives | $ | 223,778 | $ | (70,679 | ) | $ | 153,099 | ||||||
Interest rate derivatives | — | — | — | ||||||||||
Total derivative assets | $ | 223,778 | $ | (70,679 | ) | $ | 153,099 | ||||||
Offsetting Derivative Liabilities: | |||||||||||||
Commodity derivatives | $ | (70,679 | ) | $ | 70,679 | $ | — | ||||||
Interest rate derivatives | (2,080 | ) | — | (2,080 | ) | ||||||||
Total derivative liabilities | $ | (72,759 | ) | $ | 70,679 | $ | (2,080 | ) | |||||
December 31, 2013 | |||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||||
Offsetting Derivative Assets: | (In thousands) | ||||||||||||
Commodity derivatives | $ | 46,356 | $ | (21,263 | ) | $ | 25,093 | ||||||
Interest rate derivatives | — | — | — | ||||||||||
Total derivative assets | $ | 46,356 | $ | (21,263 | ) | $ | 25,093 | ||||||
Offsetting Derivative Liabilities: | |||||||||||||
Commodity derivatives | $ | (28,683 | ) | $ | 21,263 | $ | (7,420 | ) | |||||
Interest rate derivatives | (4,759 | ) | — | (4,759 | ) | ||||||||
Total derivative liabilities | $ | (33,442 | ) | $ | 21,263 | $ | (12,179 | ) | |||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: | |||||||||||||
Calendar Year | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||
2015 | 1,056,301 | $93.93 | $88.50 | - | $100.20 | ||||||||
2016 | 228,600 | $87.94 | $86.30 | - | $99.85 | ||||||||
2017 | 182,500 | $84.75 | $84.75 | ||||||||||
As of December 31, 2014, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: | |||||||||||||
Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||
Q1 2015 | 810,000 | ($2.34) | ($2.00) | - | ($2.55) | ||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: | |||||||||||||
Average Short Put | Average Long Put | Average Short Call | |||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||
2015 | 1,362,800 | $65.08 | $89.69 | $111.84 | |||||||||
2016 | 621,300 | $63.37 | $88.37 | $106.40 | |||||||||
2017 | 72,400 | $60.00 | $85.00 | $104.20 | |||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below: | |||||||||||||
Average Long Put | Average Short Put | Average Swap | |||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||
2016 | 183,000 | $57.00 | $82.00 | $91.70 | |||||||||
2017 | 182,500 | $57.00 | $82.00 | $90.85 | |||||||||
2018 | 127,750 | $57.00 | $82.00 | $90.50 | |||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and a fixed-price swap as indicated below: | |||||||||||||
Average Short Put | Average Swap | ||||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | ||||||||||
2015 | 868,000 | $76.59 | $93.68 | ||||||||||
As of December 31, 2014, Legacy had the following NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: | |||||||||||||
Average | |||||||||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | Price Range per MMBtu | ||||||||||
2015 | 18,619,300 | $4.39 | $3.98 | - | $5.82 | ||||||||
2016 | 1,419,200 | $4.30 | $4.12 | - | $5.30 | ||||||||
As of December 31, 2014, Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: | |||||||||||||
Average Short Put | Average Long Put | Average Short Call | |||||||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu | |||||||||
2015 | 8,040,000 | $3.66 | $4.21 | $5.01 | |||||||||
2016 | 5,580,000 | $3.75 | $4.25 | $5.08 | |||||||||
2017 | 5,040,000 | $3.75 | $4.25 | $5.53 | |||||||||
As of December 31, 2014, Legacy had the following Henry Hub NYMEX to Northwest Pipeline, NGPL Midcon, California SoCal NGI, San Juan Basin and West Texas Waha natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: | |||||||||||||
2015 | |||||||||||||
Average | |||||||||||||
Volumes (MMBtu) | Price per MMBtu | ||||||||||||
NWPL | 12,000,000 | ($0.13) | |||||||||||
NGPL | 480,000 | ($0.15) | |||||||||||
SoCal | 240,000 | $0.19 | |||||||||||
San Juan | 480,000 | ($0.12) | |||||||||||
WAHA | 6,000,000 | ($0.10) | |||||||||||
Interest rate derivative transactions | |||||||||||||
Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in overhedged amounts. | |||||||||||||
Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings and classified as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Beginning fair value of interest rate swaps | $ | (4,759 | ) | $ | (9,547 | ) | $ | (12,053 | ) | ||||
Total loss on interest rate swaps | (551 | ) | (1,165 | ) | (4,513 | ) | |||||||
Cash settlements paid | 3,230 | 5,953 | 7,019 | ||||||||||
Ending fair value of interest rate swaps | $ | (2,080 | ) | $ | (4,759 | ) | $ | (9,547 | ) | ||||
The table below summarizes the interest rate swap liabilities as of December 31, 2014. | |||||||||||||
Fixed | Effective | Maturity | Estimated | ||||||||||
Fair Market Value | |||||||||||||
at December 31, | |||||||||||||
Notional Amount | Rate | Date | Date | 2014 | |||||||||
(Dollars in thousands) | |||||||||||||
$29,000 | 3.07 | % | 10/16/07 | 10/16/15 | $ | (629 | ) | ||||||
$13,000 | 3.112 | % | 11/16/07 | 11/16/15 | (310 | ) | |||||||
$12,000 | 3.131 | % | 11/28/07 | 11/28/15 | (286 | ) | |||||||
$50,000 | 2.5 | % | 10/10/08 | 10/10/15 | (855 | ) | |||||||
Total fair value of interest | |||||||||||||
rate derivatives | $ | (2,080 | ) |
Sales_to_Major_Customers
Sales to Major Customers | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Risks and Uncertainties [Abstract] | ||||||
Sales to Major Customers | Business and Credit Concentrations | |||||
Cash | ||||||
Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. | ||||||
Revenue and Trade Receivables | ||||||
Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2014, 2013 or 2012. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. | ||||||
Commodity Derivatives | ||||||
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or three-way collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2014, Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $153.1 million, collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. | ||||||
Sales to Major Customers | ||||||
Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues for the years ended December 31, 2014, 2013 and 2012 to the customers shown below: | ||||||
2014 | 2013 | 2012 | ||||
Enterprise (Teppco) Crude Oil, LP | 12% | 17% | 12% | |||
Plains Marketing, LP | 10% | 7% | 10% | |||
In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Legacy believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations. |
Asset_Retirement_Obligation
Asset Retirement Obligation | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation [Abstract] | ||||||||||||
Asset Retirement Obligation | Asset Retirement Obligation | |||||||||||
An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period in which it is incurred and becomes determinable. When liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the additions to the ARO asset and liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon Legacy’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using Legacy’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. When obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from Legacy's balance sheet. Any difference in the cost to plug and the related liability is recorded as a gain or loss on Legacy's income statement in the disposal of assets line item. | ||||||||||||
The following table reflects the changes in the ARO during the years ended December 31, 2014, 2013 and 2012. | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Asset retirement obligation — beginning of period | $ | 175,786 | $ | 162,183 | $ | 120,274 | ||||||
Liabilities incurred with properties acquired | 50,487 | 10,969 | 38,857 | |||||||||
Liabilities incurred with properties drilled | 941 | 494 | 878 | |||||||||
Liabilities settled during the period | (2,918 | ) | (2,441 | ) | (2,412 | ) | ||||||
Liabilities associated with properties sold | (5,891 | ) | (1,606 | ) | — | |||||||
Current period accretion | 8,120 | 6,187 | 4,586 | |||||||||
Asset retirement obligation — end of period | $ | 226,525 | $ | 175,786 | $ | 162,183 | ||||||
Each year the Partnership reviews and, to the extent necessary, revises its asset retirement obligation estimates. During 2012, 2013 and 2014, no revisions of previous estimates were deemed necessary. |
Partners_Equity
Partners' Equity | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Equity [Abstract] | ||||||||||||
Partners' Equity | Partners' Equity | |||||||||||
On April 17, 2014, Legacy issued 2,000,000 of its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") in a public offering at a price of $25.00 per unit. On May 12, 2014 Legacy issued an additional 300,000 Series A Preferred Units pursuant to the underwriters’ option to purchase additional Series A Preferred Units. Legacy received aggregate net proceeds of approximately $55.2 million, after deducting underwriting discounts and offering expenses, from the offering of Series A Preferred Units during the year ended December 31, 2014. | ||||||||||||
On June 17, 2014, Legacy issued 7,000,000 of its 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series B Preferred Units") in a public offering at a price of $25.00 per unit. On July 1, 2014, Legacy issued an additional 200,000 Series B Preferred Units pursuant to the underwriters' option to purchase additional Series B Preferred Units. Legacy received aggregate net proceeds of approximately $174.3 million, after deducting underwriting discounts and offering expenses, from the offering of Series B Preferred Units during the year ended December 31, 2014. | ||||||||||||
Distributions on the Series A Preferred Units and Series B Preferred Units (collectively, the "Preferred Units") are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A Preferred Units and 5.26% for Series B Preferred Units, based on the $25.00 liquidation preference per preferred unit. | ||||||||||||
At any time on or after April 15, 2019 or June 15, 2019, Legacy may redeem the Series A Preferred Units or Series B Preferred Units, respectively, in whole or in part at a redemption price of $25.00 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon through and including the date of redemption, whether or not declared. Legacy may also redeem the Preferred Units in the event of a change of control. | ||||||||||||
The Series A Preferred Units and the Series B Preferred Units trade on the NASDAQ Global Select Market under the symbols "LGCYP" and "LGCYO,” respectively. | ||||||||||||
Incentive Distribution Units | ||||||||||||
On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of the WPX Acquisition. The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy pursuant to the terms of the IDR Holders Agreement. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units. | ||||||||||||
The Incentive Distribution Units represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets are set above the current levels of Legacy's distributions to unitholders. The Unvested IDUs do not participate in cash distributions from Legacy until vested. The Unvested IDUs will automatically be forfeited on each of the first two anniversaries of the closing date of the WPX Acquisition in an amount per forfeiture equal to 66,666 Incentive Distribution Units and on the third anniversary of the closing date of the WPX Acquisition in an amount equal to 66,668 Incentive Distribution Units. Unvested IDUs that have not been forfeited will vest ratably at a rate of 10,000 Incentive Distribution Units | ||||||||||||
per $35.5 million of additional cash consideration that is paid by Legacy to WPX or to a third party (along with the fair market value of any non-cash consideration) in connection with the consummation of any transaction by which Legacy acquires oil and natural gas properties (or rights therein or other assets related thereto) from WPX or jointly with WPX. | ||||||||||||
In addition, the vested and outstanding Incentive Distribution Units held by WPX may be converted by Legacy, subject to applicable conversion factors, into units on a one-for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus, as defined in Legacy's Partnership Agreement, for such quarter. Further, WPX also has the ability to similarly convert any of its vested Incentive Distribution Units beginning three years after June 4, 2014. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX. | ||||||||||||
Income (loss) per unit | ||||||||||||
The following table sets forth the computation of basic and diluted income (loss) per unit: | ||||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Net income (loss) | $ | (283,645 | ) | $ | (35,272 | ) | $ | 68,637 | ||||
Distributions to preferred unitholders | (11,694 | ) | — | — | ||||||||
Net income (loss) attributable to unitholders | (295,339 | ) | (35,272 | ) | 68,637 | |||||||
Weighted average number of units outstanding | 60,053 | 57,220 | 48,991 | |||||||||
Effect of dilutive securities: | ||||||||||||
Restricted and phantom units | — | — | — | |||||||||
Weighted average units and potential units outstanding | 60,053 | 57,220 | 48,991 | |||||||||
Basic and diluted income (loss) per unit | $ | (4.92 | ) | $ | (0.62 | ) | $ | 1.4 | ||||
As of December 31, 2014, 254,183 restricted units and 323,965 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. Additionally, as the conditions for conversion on the Incentive Distribution Units have not been met, they have been excluded from the calculation. As of December 31, 2013, 234,686 restricted units and 189,143 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. As of December 31, 2012, 230,477 restricted units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. |
UnitBased_Compensation
Unit-Based Compensation | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||
Unit-Based Compensation | Unit-Based Compensation | ||||||||||||
Long Term Incentive Plan | |||||||||||||
On March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights (“UARs”). The LTIP permits the grant of awards that may be made or settled in units up to an aggregate of 2,000,000 units. As of December 31, 2014 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 1,254,207 units have been made, comprised of 266,014 unit option awards, 533,850 restricted unit awards, 323,965 phantom unit awards and 130,378 unit awards. The UAR awards granted | |||||||||||||
under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee of the board of directors ("Compensation Committee") of Legacy’s general partner. | |||||||||||||
The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Due to Legacy’s historical practice of settling options, UARs and certain phantom unit awards in cash, Legacy accounts for unit options, UARS and certain phantom unit awards by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods. | |||||||||||||
Unit Appreciation Rights and Unit Options | |||||||||||||
A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method. | |||||||||||||
During the year ended December 31, 2012, Legacy issued (i) 82,400 UARs to employees which vest ratably over a three-year period and (ii) 60,336 UARs to employees which cliff-vest at the end of a three-year period. During the year ended December 31, 2013, Legacy issued (i) 156,650 UARs to employees which vest ratably over a three-year period and (ii) 77,506 UARs to employees which cliff-vest at the end of a three-year period. During the year ended December 31, 2014, Legacy issued (i) 136,100 UARs to employees which vest ratably over a three-year period and (ii) 105,174 UARs to employees which cliff-vest at the end of a three-year period. All of the UARs granted in 2014, 2013 and 2012 expire seven years from the grant date and are exercisable when they vest. There were no unit options granted in 2014, 2013 or 2012. | |||||||||||||
For the years ended December 31, 2014, 2013 and 2012, Legacy recorded compensation expense/(benefit) of $(1.3) million, $0.9 million and $0.3 million, respectively, due to the changes in the compensation liability related to the above awards based on its use of the Black-Scholes model to estimate the December 31, 2014, 2013 and 2012 fair value of these UARs (see Note 8). As of December 31, 2014, there was a total of $20.7 thousand of unrecognized compensation costs related to the unexercised and non-vested portion of the UARs. At December 31, 2014, this cost was expected to be recognized over a weighted-average period of 2.5 years. Compensation expense is based upon the fair value as of the balance sheet date and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 38% and employed the Black-Scholes model to estimate the December 31, 2014 fair value to be realized as compensation cost based on the percentage of the service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 4.7%. The Partnership will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $2.44 per unit. | |||||||||||||
A summary of option and UAR activity for the year ended December 31, 2014, 2013 and 2012 is as follows: | |||||||||||||
Units | Weighted-Average | Weighted-Average Remaining | Aggregate Intrinsic Value | ||||||||||
Exercise | Contractual | ||||||||||||
Price | Term | ||||||||||||
Outstanding at January 1, 2012 | 620,031 | $ | 22.36 | ||||||||||
Granted | 142,736 | $ | 28.57 | ||||||||||
Exercised | (185,482 | ) | $ | 19.68 | |||||||||
Forfeited | (61,066 | ) | $ | 24.91 | |||||||||
Outstanding at December 31, 2012 | 516,219 | $ | 24.71 | 4.77 | $ | 681,214 | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-12 | 168,569 | $ | 20.54 | 2.93 | $ | 671,583 | |||||||
Outstanding at January 1, 2013 | 516,219 | $ | 24.71 | ||||||||||
Granted | 234,156 | $ | 26.53 | ||||||||||
Exercised | (96,166 | ) | $ | 20.21 | |||||||||
Forfeited | (27,166 | ) | $ | 26.74 | |||||||||
Outstanding at December 31, 2013 | 627,043 | $ | 25.99 | 5.16 | $ | 1,518,416 | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-13 | 240,288 | $ | 24.02 | 3.8 | $ | 1,061,542 | |||||||
Outstanding at January 1, 2014 | 627,043 | $ | 25.99 | ||||||||||
Granted | 241,274 | $ | 28.21 | ||||||||||
Exercised | (137,252 | ) | $ | 24.35 | |||||||||
Forfeited | (61,836 | ) | $ | 27.27 | |||||||||
Outstanding at December 31, 2014 | 669,229 | $ | 27.01 | 5.15 | $ | — | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-14 | 220,056 | $ | 25.5 | 3.51 | $ | — | |||||||
The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2014: | |||||||||||||
Non-Vested Options and UARs | |||||||||||||
Number of | Weighted- | ||||||||||||
Units | Average Exercise | ||||||||||||
Price | |||||||||||||
Non-vested at January 1, 2014 | 386,755 | $ | 27.21 | ||||||||||
Granted | 241,274 | 28.21 | |||||||||||
Vested | (118,020 | ) | 27.03 | ||||||||||
Forfeited | (60,836 | ) | 27.55 | ||||||||||
Non-vested at December 31, 2014 | 449,173 | $ | 27.75 | ||||||||||
Legacy has used a weighted-average risk free interest rate of 1.6% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at December 31, 2014. Expected life represents the period of time that options and UARs are expected to be outstanding and is based on the Partnership’s best estimate. The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Expected life (years) | 5.15 | 5.16 | 4.77 | ||||||||||
Annual interest rate | 1.6 | % | 1.4 | % | 1.1 | % | |||||||
Annual distribution rate per unit | $2.44 | $2.34 | $2.26 | ||||||||||
Volatility | 38 | % | 50 | % | 49 | % | |||||||
Phantom Units | |||||||||||||
Legacy has also issued phantom units under the LTIP to both executive officers, as described below, and certain other employees. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive, in the case of non-executive employees, cash valued at the closing price of units on the vesting date, or, at the discretion of the Compensation Committee, the same number of Partnership units. Because Legacy’s current intent is to settle non-executive phantom unit awards in cash, Legacy is accounting for these phantom units by utilizing the liability method. In the case of executive employees, during 2013 the Compensation Committee revised prior grants of phantom units made to executive officers to eliminate any election for cash payment. As these awards can now only be settled in Partnership units, Legacy is accounting for these phantom units by utilizing the equity method as described in ASC 718. | |||||||||||||
During February 2012, the Compensation Committee approved the award of 30,828 subjective, or service-based, phantom units and 57,189 objective, or performance-based, phantom units to Legacy’s five executive officers. During March 2013, the Compensation Committee approved the award of 46,430 subjective, or service-based, phantom units and 76,723 objective, or performance-based, phantom units to Legacy’s executive officers. During March 2014, the Compensation Committee approved the award of 117,197 subjective, or service-based, phantom units and 102,572 objective, or performance-based, phantom units to Legacy's executive officers. | |||||||||||||
Compensation expense related to the phantom units and associated DERs was $2.3 million, $1.2 million and $0.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||
Restricted Units | |||||||||||||
During the year ended December 31, 2012, Legacy issued an aggregate of 173,645 restricted units to both non-executive employees and certain executives. The majority of these restricted units awarded vest ratably over a three-year period, beginning on the date of grant. During the year ended December 31, 2013, Legacy issued an aggregate of 85,728 restricted units to non-executive employees. The majority of these restricted units awarded vest ratably over a three-year period. During the year ended December 31, 2014, Legacy issued an aggregate of 127,845 restricted units to non-executive employees. The majority of these restricted units awarded vest ratably over a three-year period beginning at the date of grant. Compensation expense related to restricted units was $2.3 million, $2.3 million and $1.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, there was a total of $4.7 million of unrecognized compensation costs related to the non-vested portion of these restricted units. At December 31, 2014, this cost was expected to be recognized over a weighted-average period of 2.2 years. | |||||||||||||
Pursuant to the provisions of ASC 718, Legacy’s issued units as reflected in the accompanying consolidated balance sheet at December 31, 2014, do not include 254,183 units related to unvested restricted unit awards. | |||||||||||||
Board and Additional Executive Units | |||||||||||||
On May 9, 2012, Legacy granted and issued 3,509 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner and 2,500 units to an executive officer. The value of each unit was $28.34 at the time of issuance. On May 14, 2013, Legacy granted and issued 3,715 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $27.39 at the time of issuance. On May 15, 2014, Legacy granted and issued 3,628 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $27.50 at the time of issuance. None of these units were subject to vesting. Legacy recognized the expense associated with the unit grants on the date of grant. |
Subsidiary_Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2014 | |
Guarantees [Abstract] | |
Subsidiary Guarantors | Subsidiary Guarantors |
On April 2, 2014, we filed a registration statement on Form S-3 with the Securities and Exchange Commission ("SEC") to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by Legacy Reserves Finance Corporation. The registration statement also registered guarantees of debt securities by Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015.The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by our 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., which constitute all of our wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in Note 3 - Long-Term Debt. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors. |
Subsequent_Events
Subsequent Events | 12 Months Ended | |
Dec. 31, 2014 | ||
Subsequent Events [Abstract] | ||
Subsequent Events | Subsequent Events | |
On January 23, 2015, the board of directors of Legacy’s general partner declared a $0.61 per unit cash distribution for the quarter ended December 31, 2014 to all unitholders of record on February 2, 2015. This distribution was paid on February 13, 2015. | ||
On January 23, 2015, Legacy announced that its general partner had declared a monthly cash distribution for both its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and its 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of $0.166667 per unit payable on February 17, 2015 to unitholders of record on February 2, 2015. | ||
On February 19, 2015, Legacy announced that its general partner had declared a monthly cash distribution for both its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and its 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of $0.166667 per unit payable on March 16, 2015 to unitholders of record on March 2, 2015. | ||
On February 23, 2015, Legacy entered into the Fourth Amendment to the Current Credit Agreement (the “Fourth Amendment”). Pursuant to the Fourth Amendment, the borrowing base under the Current Credit Agreement was decreased from $950 million to $700 million. As of February 23, 2015, Legacy had approximately $130 million drawn under the Current Credit Agreement, leaving approximately $569.9 million of current availability. Pursuant to the Fourth Amendment, the specific ratios or conditions Legacy is now required to maintain have been amended in their entirety to the following: | ||
• | secured debt as of the last day of the most recent quarter to EBITDA (as defined in the Current Credit Agreement) in total over the last four quarters of not more than 2.5 to 1.0; | |
• | as of the last day of the most recent quarter, total EBITDA over the last four quarters to total Interest Expense over the last four quarters to be greater than 2.5 to 1.0; and | |
• | consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. |
Trade Accounts Receivable | Trade Accounts Receivable |
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10). | |
Oil and Natural Gas Properties and Oil, NGLs and Natural Gas Reserve Quantities | Oil and Natural Gas Properties |
Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. | |
Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. | |
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. | |
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2014, Legacy recognized $448.7 million of impairment expense, $413.3 million of of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014, which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2013, Legacy recognized $78.0 million of impairment expense on 98 separate producing fields, due primarily to the decrease in commodity prices primarily related to natural gas differentials during the year ended December 31, 2013, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. The remaining $7.8 million was impairment of unproven properties acquired since 2010 that were no longer viable. For the year ended December 31, 2012, Legacy recognized $22.8 million of impairment expense on 64 separate producing fields due primarily to the decrease in commodity prices during the year ended December 31, 2012, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. In 2012, Legacy also recognized $6.5 million of impairment related to the reduction in the carrying value of a property that Legacy entered into an option to sell. Finally, Legacy recognized $7.8 million of impairment of goodwill during 2012 related to a decline in oil futures prices between announcement and closing date of a transaction, as hedging does not impact the associated fair value of properties for purposes of measuring impairment. | |
Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2014, Legacy recognized $35.0 million of impairment of unproven properties. | |
(d) Oil, NGLs and Natural Gas Reserve Quantities | |
Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. | |
Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. | |
Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered. | |
Income Taxes | Income Taxes |
Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. | |
The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. | |
Legacy recorded income tax (expense) benefit of $0.9 million, $(0.6) million and $(1.1) million for the years ended December 31, 2014, 2013 and 2012, respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. | |
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.5 billion at December 31, 2014. | |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities |
Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil, NGL and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil, NGL and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9). | |
Use of Estimates | Use of Estimates |
Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. | |
Revenue Recognition | Revenue Recognition |
Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. | |
To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. | |
Legacy uses the “net-back” method of accounting for transportation arrangements of its natural gas sales. Legacy sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its purchasers and reflected in the wellhead price. Legacy’s contracts with respect to the sale of its natural gas produced, with one immaterial exception, provide Legacy with a net price payment. That is, when Legacy is paid for its natural gas by its purchasers, Legacy receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of Legacy’s contracts, the payment statements Legacy receives from its purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, Legacy’s revenues are recorded at this single net price. | |
Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2014, 2013 and 2012. | |
Legacy is paid a monthly operating fee for each well it operates for outside owners proportionate to each owner's working interest. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense. | |
Investments | Investments |
Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition. | |
Intangible assets | Intangible assets |
Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life. | |
Environmental | Environmental |
Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. | |
Income (Loss) Per Unit | Income (Loss) Per Unit |
Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12). | |
Redemption of Units | Redemption of Units |
Units redeemed are recorded at cost. | |
Segment Reporting | Segment Reporting |
Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes. | |
Unit-Based Compensation | Unit-Based Compensation |
Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of | |
each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2014, do not include 254,183 units related to unvested restricted unit awards. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||
Schedule of components of accrued oil and natural gas liabilities | Below are the components of accrued oil and natural gas liabilities as of December 31, 2014 and 2013. | |||||||
December 31, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Revenue payable to joint interest owners | $ | 19,267 | $ | 21,686 | ||||
Accrued lease operating expense | 21,177 | 11,914 | ||||||
Accrued capital expenditures | 20,773 | 10,409 | ||||||
Accrued ad valorem tax | 9,382 | 9,459 | ||||||
Other | 8,016 | 9,693 | ||||||
$ | 78,615 | $ | 63,161 | |||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Schedule of long-term debt | Long-term debt consists of the following at December 31, 2014 and 2013: | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Credit Facility due 2019 | $ | 109,000 | 348,000 | ||||||
8% Senior Notes due 2020 | 300,000 | 300,000 | |||||||
6.625% Senior Notes due 2021 | 550,000 | 250,000 | |||||||
959,000 | 898,000 | ||||||||
Unamortized discount on Senior Notes | (20,124 | ) | (19,307 | ) | |||||
Total long term debt | $ | 938,876 | $ | 878,693 | |||||
Schedule of debt redemption | Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. | ||||||||
Year | Percentage | ||||||||
2017 | 103.313 | % | |||||||
2018 | 101.656 | % | |||||||
2019 and thereafter | 100 | % | |||||||
Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. | |||||||||
Year | Percentage | ||||||||
2016 | 104 | % | |||||||
2017 | 102 | % | |||||||
2018 | 100 | % |
Acquisitions_Tables
Acquisitions (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Schedule of unaudited pro forma results of operations | The following table reflects the unaudited pro forma results of operations as though the COG 2012 Acquisition had occurred on January 1, 2011 and the WPX Acquisition had occurred on January 1, 2013. The pro forma amounts are not necessarily indicative of the results that may be reported in the future: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Revenues | $ | 569,674 | $ | 549,968 | $ | 478,115 | |||||||
Net income | $ | (289,659 | ) | $ | (50,041 | ) | $ | 97,092 | |||||
Income (loss) per unit — basic and diluted | $ | (4.82 | ) | $ | (0.87 | ) | $ | 1.71 | |||||
Units used in computing income (loss) per unit: | |||||||||||||
Basic | 60,053 | 57,220 | 56,887 | ||||||||||
Diluted | 60,053 | 57,220 | 56,887 | ||||||||||
The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the COG 2012 Acquisition and the WPX Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
COG 2012 Acquisition | (In thousands) | ||||||||||||
Revenues | $ | 96,560 | $ | 113,222 | $ | 3,693 | |||||||
Excess of revenues over direct operating expenses | $ | 54,320 | $ | 73,408 | $ | 2,654 | |||||||
WPX Acquisition | |||||||||||||
Revenues | $ | 48,470 | $ | — | $ | — | |||||||
Excess of revenues over direct operating expenses | $ | 22,333 | $ | — | $ | — | |||||||
COG 2012 Acquisition | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): | ||||||||||||
Proved oil and natural gas properties including related equipment | $ | 495,897 | |||||||||||
Unproved properties | 37,994 | ||||||||||||
Total assets | $ | 533,891 | |||||||||||
Future abandonment costs | (31,274 | ) | |||||||||||
Fair value of net assets acquired | $ | 502,617 | |||||||||||
WPX acquisition | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): | ||||||||||||
Proved oil and natural gas properties including related equipment | $ | 403,980 | |||||||||||
Future abandonment costs | (43,989 | ) | |||||||||||
Fair value of net assets acquired | $ | 359,991 | |||||||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013: | ||||||||||||||||
Fair Value Measurements Using | |||||||||||||||||
Quoted Prices in | Significant Other | Significant | Total Carrying | ||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | Value as of | |||||||||||||
(In thousands) | |||||||||||||||||
LTIP liability(a) | $ | — | $ | (11 | ) | $ | — | $ | (11 | ) | |||||||
Oil and natural gas derivatives | — | 152,544 | 555 | 153,099 | |||||||||||||
Interest rate swaps | — | (2,080 | ) | — | (2,080 | ) | |||||||||||
Total as of December 31, 2014 | $ | — | $ | 150,453 | $ | 555 | $ | 151,008 | |||||||||
LTIP liability(a) | $ | — | $ | (2,217 | ) | $ | — | $ | (2,217 | ) | |||||||
Oil and natural gas derivatives | — | (2,942 | ) | 20,615 | 17,673 | ||||||||||||
Interest rate swaps | — | (4,759 | ) | — | (4,759 | ) | |||||||||||
Total as of December 31, 2013 | $ | — | $ | (9,918 | ) | $ | 20,615 | $ | 10,697 | ||||||||
____________________ | |||||||||||||||||
(a) | See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. | ||||||||||||||||
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: | ||||||||||||||||
Significant | |||||||||||||||||
Unobservable | |||||||||||||||||
Inputs | |||||||||||||||||
(Level 3) | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(In thousands) | |||||||||||||||||
Beginning balance | $ | 20,615 | $ | 29,966 | $ | 30,054 | |||||||||||
Total gains (losses) | (6,185 | ) | 4,671 | 18,993 | |||||||||||||
Settlements | 677 | (6,722 | ) | (19,081 | ) | ||||||||||||
Transfers | (14,552 | ) | (a) | (7,300 | ) | (b) | — | ||||||||||
Ending balance | $ | 555 | $ | 20,615 | $ | 29,966 | |||||||||||
Gains included in earnings relating to derivatives | |||||||||||||||||
still held as of December 31, 2014, 2013 and 2012 | $ | 555 | $ | 1,407 | $ | 16,065 | |||||||||||
(a) | During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. | ||||||||||||||||
(b) | During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2. | ||||||||||||||||
Schedule of fair value measurements of proved oil and natural gas properties | Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2014 and 2013 consist of: | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | |||||||||||||||
Active Markets for | Observable | Unobservable | |||||||||||||||
Identical Assets | Inputs | Inputs | |||||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | ||||||||||||||
(In thousands) | |||||||||||||||||
2014 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 254,266 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 536,334 | |||||||||||
2013 | |||||||||||||||||
Impairment(a) | $ | — | $ | — | $ | 76,137 | |||||||||||
Acquisitions(b) | $ | — | $ | — | $ | 108,415 | |||||||||||
____________________ | |||||||||||||||||
(a) | Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended December 31, 2014, Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 million. During the year ended December 31, 2013, Legacy incurred impairment charges of $78.0 million as oil and natural gas properties with a net cost basis of $154.1 million were written down to their fair value of $76.1 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. | ||||||||||||||||
The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that are no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. In 2013, Legacy recognized an additional $7.8 million of impairment of unproved properties acquired since 2010 that are no longer viable. | |||||||||||||||||
(b) | Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2014, Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2013, Legacy acquired oil and natural gas properties with a fair value of $108.4 million in 16 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||
Schedule of reconciliation of the changes in fair value of Legacy's commodity derivatives | The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2014, 2013, and 2012. | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Beginning fair value of commodity derivatives | $ | 17,673 | $ | 24,148 | $ | (8,443 | ) | ||||||
Total gain (loss) crude oil derivatives | 101,813 | (11,977 | ) | 34,257 | |||||||||
Total gain (loss) natural gas derivatives | 36,279 | (1,554 | ) | 4,236 | |||||||||
Crude oil derivative cash settlements paid | 5,431 | 14,160 | 10,211 | ||||||||||
Natural gas derivative cash settlements received | (8,097 | ) | (7,104 | ) | (16,113 | ) | |||||||
Ending fair value of commodity derivatives | $ | 153,099 | $ | 17,673 | $ | 24,148 | |||||||
Schedule of gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities | Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands): | ||||||||||||
December 31, 2014 | |||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||||
Offsetting Derivative Assets: | (In thousands) | ||||||||||||
Commodity derivatives | $ | 223,778 | $ | (70,679 | ) | $ | 153,099 | ||||||
Interest rate derivatives | — | — | — | ||||||||||
Total derivative assets | $ | 223,778 | $ | (70,679 | ) | $ | 153,099 | ||||||
Offsetting Derivative Liabilities: | |||||||||||||
Commodity derivatives | $ | (70,679 | ) | $ | 70,679 | $ | — | ||||||
Interest rate derivatives | (2,080 | ) | — | (2,080 | ) | ||||||||
Total derivative liabilities | $ | (72,759 | ) | $ | 70,679 | $ | (2,080 | ) | |||||
December 31, 2013 | |||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||||
Offsetting Derivative Assets: | (In thousands) | ||||||||||||
Commodity derivatives | $ | 46,356 | $ | (21,263 | ) | $ | 25,093 | ||||||
Interest rate derivatives | — | — | — | ||||||||||
Total derivative assets | $ | 46,356 | $ | (21,263 | ) | $ | 25,093 | ||||||
Offsetting Derivative Liabilities: | |||||||||||||
Commodity derivatives | $ | (28,683 | ) | $ | 21,263 | $ | (7,420 | ) | |||||
Interest rate derivatives | (4,759 | ) | — | (4,759 | ) | ||||||||
Total derivative liabilities | $ | (33,442 | ) | $ | 21,263 | $ | (12,179 | ) | |||||
Schedule of notional amounts of outstanding derivative positions | As of December 31, 2014, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: | ||||||||||||
Calendar Year | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||
2015 | 1,056,301 | $93.93 | $88.50 | - | $100.20 | ||||||||
2016 | 228,600 | $87.94 | $86.30 | - | $99.85 | ||||||||
2017 | 182,500 | $84.75 | $84.75 | ||||||||||
As of December 31, 2014, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: | |||||||||||||
Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||
Q1 2015 | 810,000 | ($2.34) | ($2.00) | - | ($2.55) | ||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: | |||||||||||||
Average Short Put | Average Long Put | Average Short Call | |||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||
2015 | 1,362,800 | $65.08 | $89.69 | $111.84 | |||||||||
2016 | 621,300 | $63.37 | $88.37 | $106.40 | |||||||||
2017 | 72,400 | $60.00 | $85.00 | $104.20 | |||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below: | |||||||||||||
Average Long Put | Average Short Put | Average Swap | |||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||
2016 | 183,000 | $57.00 | $82.00 | $91.70 | |||||||||
2017 | 182,500 | $57.00 | $82.00 | $90.85 | |||||||||
2018 | 127,750 | $57.00 | $82.00 | $90.50 | |||||||||
As of December 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and a fixed-price swap as indicated below: | |||||||||||||
Average Short Put | Average Swap | ||||||||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | ||||||||||
2015 | 868,000 | $76.59 | $93.68 | ||||||||||
As of December 31, 2014, Legacy had the following NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: | |||||||||||||
Average | |||||||||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | Price Range per MMBtu | ||||||||||
2015 | 18,619,300 | $4.39 | $3.98 | - | $5.82 | ||||||||
2016 | 1,419,200 | $4.30 | $4.12 | - | $5.30 | ||||||||
As of December 31, 2014, Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: | |||||||||||||
Average Short Put | Average Long Put | Average Short Call | |||||||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu | |||||||||
2015 | 8,040,000 | $3.66 | $4.21 | $5.01 | |||||||||
2016 | 5,580,000 | $3.75 | $4.25 | $5.08 | |||||||||
2017 | 5,040,000 | $3.75 | $4.25 | $5.53 | |||||||||
As of December 31, 2014, Legacy had the following Henry Hub NYMEX to Northwest Pipeline, NGPL Midcon, California SoCal NGI, San Juan Basin and West Texas Waha natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: | |||||||||||||
2015 | |||||||||||||
Average | |||||||||||||
Volumes (MMBtu) | Price per MMBtu | ||||||||||||
NWPL | 12,000,000 | ($0.13) | |||||||||||
NGPL | 480,000 | ($0.15) | |||||||||||
SoCal | 240,000 | $0.19 | |||||||||||
San Juan | 480,000 | ($0.12) | |||||||||||
WAHA | 6,000,000 | ($0.10) | |||||||||||
Schedule of total impact on interest expense from the mark-to-market and settlements | The total impact on interest expense from the mark-to-market and settlements was as follows: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Beginning fair value of interest rate swaps | $ | (4,759 | ) | $ | (9,547 | ) | $ | (12,053 | ) | ||||
Total loss on interest rate swaps | (551 | ) | (1,165 | ) | (4,513 | ) | |||||||
Cash settlements paid | 3,230 | 5,953 | 7,019 | ||||||||||
Ending fair value of interest rate swaps | $ | (2,080 | ) | $ | (4,759 | ) | $ | (9,547 | ) | ||||
Schedule of interest rate swap liabilities | The table below summarizes the interest rate swap liabilities as of December 31, 2014. | ||||||||||||
Fixed | Effective | Maturity | Estimated | ||||||||||
Fair Market Value | |||||||||||||
at December 31, | |||||||||||||
Notional Amount | Rate | Date | Date | 2014 | |||||||||
(Dollars in thousands) | |||||||||||||
$29,000 | 3.07 | % | 10/16/07 | 10/16/15 | $ | (629 | ) | ||||||
$13,000 | 3.112 | % | 11/16/07 | 11/16/15 | (310 | ) | |||||||
$12,000 | 3.131 | % | 11/28/07 | 11/28/15 | (286 | ) | |||||||
$50,000 | 2.5 | % | 10/10/08 | 10/10/15 | (855 | ) | |||||||
Total fair value of interest | |||||||||||||
rate derivatives | $ | (2,080 | ) |
Sales_to_Major_Customers_Table
Sales to Major Customers (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Risks and Uncertainties [Abstract] | ||||||
Schedule of revenue by major customer | Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues for the years ended December 31, 2014, 2013 and 2012 to the customers shown below: | |||||
2014 | 2013 | 2012 | ||||
Enterprise (Teppco) Crude Oil, LP | 12% | 17% | 12% | |||
Plains Marketing, LP | 10% | 7% | 10% |
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation [Abstract] | ||||||||||||
Schedule of changes in asset retirement obligations | The following table reflects the changes in the ARO during the years ended December 31, 2014, 2013 and 2012. | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Asset retirement obligation — beginning of period | $ | 175,786 | $ | 162,183 | $ | 120,274 | ||||||
Liabilities incurred with properties acquired | 50,487 | 10,969 | 38,857 | |||||||||
Liabilities incurred with properties drilled | 941 | 494 | 878 | |||||||||
Liabilities settled during the period | (2,918 | ) | (2,441 | ) | (2,412 | ) | ||||||
Liabilities associated with properties sold | (5,891 | ) | (1,606 | ) | — | |||||||
Current period accretion | 8,120 | 6,187 | 4,586 | |||||||||
Asset retirement obligation — end of period | $ | 226,525 | $ | 175,786 | $ | 162,183 | ||||||
Partners_Equity_Tables
Partners' Equity (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Equity [Abstract] | ||||||||||||
Schedule of computation of basic and diluted income (loss) per unit | The following table sets forth the computation of basic and diluted income (loss) per unit: | |||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Net income (loss) | $ | (283,645 | ) | $ | (35,272 | ) | $ | 68,637 | ||||
Distributions to preferred unitholders | (11,694 | ) | — | — | ||||||||
Net income (loss) attributable to unitholders | (295,339 | ) | (35,272 | ) | 68,637 | |||||||
Weighted average number of units outstanding | 60,053 | 57,220 | 48,991 | |||||||||
Effect of dilutive securities: | ||||||||||||
Restricted and phantom units | — | — | — | |||||||||
Weighted average units and potential units outstanding | 60,053 | 57,220 | 48,991 | |||||||||
Basic and diluted income (loss) per unit | $ | (4.92 | ) | $ | (0.62 | ) | $ | 1.4 | ||||
UnitBased_Compensation_Tables
Unit-Based Compensation (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||
Schedule of option and UAR activity | A summary of option and UAR activity for the year ended December 31, 2014, 2013 and 2012 is as follows: | ||||||||||||
Units | Weighted-Average | Weighted-Average Remaining | Aggregate Intrinsic Value | ||||||||||
Exercise | Contractual | ||||||||||||
Price | Term | ||||||||||||
Outstanding at January 1, 2012 | 620,031 | $ | 22.36 | ||||||||||
Granted | 142,736 | $ | 28.57 | ||||||||||
Exercised | (185,482 | ) | $ | 19.68 | |||||||||
Forfeited | (61,066 | ) | $ | 24.91 | |||||||||
Outstanding at December 31, 2012 | 516,219 | $ | 24.71 | 4.77 | $ | 681,214 | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-12 | 168,569 | $ | 20.54 | 2.93 | $ | 671,583 | |||||||
Outstanding at January 1, 2013 | 516,219 | $ | 24.71 | ||||||||||
Granted | 234,156 | $ | 26.53 | ||||||||||
Exercised | (96,166 | ) | $ | 20.21 | |||||||||
Forfeited | (27,166 | ) | $ | 26.74 | |||||||||
Outstanding at December 31, 2013 | 627,043 | $ | 25.99 | 5.16 | $ | 1,518,416 | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-13 | 240,288 | $ | 24.02 | 3.8 | $ | 1,061,542 | |||||||
Outstanding at January 1, 2014 | 627,043 | $ | 25.99 | ||||||||||
Granted | 241,274 | $ | 28.21 | ||||||||||
Exercised | (137,252 | ) | $ | 24.35 | |||||||||
Forfeited | (61,836 | ) | $ | 27.27 | |||||||||
Outstanding at December 31, 2014 | 669,229 | $ | 27.01 | 5.15 | $ | — | |||||||
Options and UARs exercisable at | |||||||||||||
31-Dec-14 | 220,056 | $ | 25.5 | 3.51 | $ | — | |||||||
Schedule of status of the Partnership’s non-vested UARs | The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2014: | ||||||||||||
Non-Vested Options and UARs | |||||||||||||
Number of | Weighted- | ||||||||||||
Units | Average Exercise | ||||||||||||
Price | |||||||||||||
Non-vested at January 1, 2014 | 386,755 | $ | 27.21 | ||||||||||
Granted | 241,274 | 28.21 | |||||||||||
Vested | (118,020 | ) | 27.03 | ||||||||||
Forfeited | (60,836 | ) | 27.55 | ||||||||||
Non-vested at December 31, 2014 | 449,173 | $ | 27.75 | ||||||||||
Schedule of weighted average assumptions used for the Black-Scholes option-pricing model | The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Expected life (years) | 5.15 | 5.16 | 4.77 | ||||||||||
Annual interest rate | 1.6 | % | 1.4 | % | 1.1 | % | |||||||
Annual distribution rate per unit | $2.44 | $2.34 | $2.26 | ||||||||||
Volatility | 38 | % | 50 | % | 49 | % |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Other Narrative (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
field | field | field | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
General partner's equity, percent | 0.03% | 0.03% | |
Term of right to receive distributions of available cash after quarter end | 45 days | ||
Minimum percentage of unitholder approval to remove general partner | 66.67% | ||
Term of right to receive information reasonably required for tax reporting purposes after close of year | 90 days | ||
Property, Plant and Equipment [Line Items] | |||
Impairment expense | $448,714,000 | $85,757,000 | $37,066,000 |
Impairment expense recorded of proved and unproved oil and natural gas properties | 78,000,000 | 22,800,000 | |
Number of impaired fields | 250 | 98 | 64 |
Goodwill impairment recognized | 500,000 | 7,800,000 | |
Impairment of property held for sale | 6,500,000 | ||
Proved Oil and Gas Properties [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairment expense recorded of proved and unproved oil and natural gas properties | 413,300,000 | ||
Unproved Oil and Gas Properties [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairment expense recorded of proved and unproved oil and natural gas properties | $34,950,000 | $7,800,000 |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Income Taxes (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Tax Contingency [Line Items] | |||
Income tax expense (benefit) | ($859,000) | $649,000 | $1,096,000 |
Partnership’s book basis in its net assets excess of Partnership’s net tax basis | $1,500,000,000 | ||
Texas | State jurisdiction | |||
Income Tax Contingency [Line Items] | |||
Franchise tax rate | 1.00% |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Intangible Assets (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Estimated economic useful life | 15 years |
Expected amortization expense, year one | $444 |
Expected amortization expense, year two | 417 |
Expected amortization expense, year three | 396 |
Expected amortization expense, year four | 358 |
Expected amortization expense, year five | $349 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Unit-Based Compensation (Details) (Restricted stock units (RSUs)) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Restricted stock units (RSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive restricted units excluded from computation of EPS | 254,183 | 234,686 | 230,477 |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Revenue payable to joint interest owners | $19,267 | $21,686 |
Accrued lease operating expense | 21,177 | 11,914 |
Accrued capital expenditures | 20,773 | 10,409 |
Accrued ad valorem tax | 9,382 | 9,459 |
Other | 8,016 | 9,693 |
Accrued oil and natural gas liabilities | $78,615 | $63,161 |
Fair_Values_of_Financial_Instr1
Fair Values of Financial Instruments (Details) (Senior notes, USD $) | Dec. 31, 2014 | Dec. 04, 2012 |
In Millions, unless otherwise specified | ||
8% Senior Notes due 2020 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Stated interest rate | 8.00% | 8.00% |
8% Senior Notes due 2020 | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of notes payable | 244.5 | |
6.625% Senior Notes due 2021 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Stated interest rate | 6.63% | |
6.625% Senior Notes due 2021 | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of notes payable | 449.6 |
LongTerm_Debt_Schedule_of_Long
Long-Term Debt - Schedule of Long-term Debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 04, 2012 | 13-May-14 | 28-May-13 |
In Thousands, unless otherwise specified | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $959,000 | $898,000 | |||
Unamortized discount on Senior Notes | -20,124 | -19,307 | |||
Total long term debt | 938,876 | 878,693 | |||
Senior notes | 8% Senior Notes due 2020 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 8.00% | 8.00% | |||
Long-term debt, gross | 300,000 | 300,000 | |||
Senior notes | 6.625% Senior Notes due 2021 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 6.63% | ||||
Long-term debt, gross | 550,000 | 250,000 | 300,000 | 250,000 | |
Credit Facility due 2019 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $109,000 | $348,000 |
LongTerm_Debt_Credit_Facility_
Long-Term Debt - Credit Facility (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
Mar. 10, 2011 | Apr. 01, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | |
Line of Credit Facility [Line Items] | ||||
Long-term debt, gross | $959,000,000 | $898,000,000 | ||
Previous Credit Agreement | ||||
Line of Credit Facility [Line Items] | ||||
Expiration period | 5 years | |||
Maximum borrowing capacity | 1,000,000,000 | |||
Credit Facility due 2019 | ||||
Line of Credit Facility [Line Items] | ||||
Expiration period | 5 years | |||
Maximum borrowing capacity | 1,500,000,000 | |||
Minimum percent of total property value securing credit agreement | 80.00% | |||
Current borrowing capacity | 950,000,000 | |||
Purchase price of properties as a percentage of borrowing base required for potential re-determination of borrowing base, minimum | 10.00% | |||
Minimum percent of outstanding principal amount required for changes to credit agreement | 66.67% | |||
Long-term debt, gross | 109,000,000 | 348,000,000 | ||
Interest rate at period end | 2.12% | |||
Remaining borrowing capacity | 840,900,000 | |||
Interest Paid | 8,900,000 | |||
Credit Facility due 2019 | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Ratio of indebtedness to EBITDA | 4 | |||
Credit Facility due 2019 | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Ratio of indebtedness to EBITDA | 4.5 | |||
Credit Facility due 2019 | ABR, Federal Funds | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
Credit Facility due 2019 | Standard ABR | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
Credit Facility due 2019 | Standard ABR | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.50% | |||
Credit Facility due 2019 | one-, two-, three- or six-month LIBOR | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.50% | |||
Credit Facility due 2019 | one-, two-, three- or six-month LIBOR | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 2.50% | |||
Credit Facility due 2019 | ABR, one-month LIBOR | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.00% | |||
Letters of credit | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $2,000,000 |
LongTerm_Debt_Senior_Notes_Det
Long-Term Debt - Senior Notes (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | 13-May-14 | 28-May-13 | Dec. 04, 2012 | Dec. 31, 2013 |
Debt Instrument [Line Items] | |||||
Long-term debt, gross | 959,000 | $898,000 | |||
Senior notes | 8% Senior Notes due 2020 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | 300,000 | 300,000 | |||
Stated interest rate | 8.00% | 8.00% | |||
Issuance percent of par | 97.85% | ||||
Percent of notes eligible of early redemption | 35.00% | ||||
Senior notes | 8% Senior Notes due 2020 | Company Option [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 108.00% | ||||
Senior notes | 8% Senior Notes due 2020 | Change in Control [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 101.00% | ||||
Senior notes | 8% Senior Notes due 2020 | Redemption Premium Year Four [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 104.00% | ||||
Senior notes | 8% Senior Notes due 2020 | Redemption Premium Year Five [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 102.00% | ||||
Senior notes | 8% Senior Notes due 2020 | Redemption Premium Year Six [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 100.00% | ||||
Senior notes | 6.625% Senior Notes due 2021 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | 550,000 | 300,000 | 250,000 | $250,000 | |
Stated interest rate | 6.63% | ||||
Issuance percent of par | 99.00% | 98.41% | |||
Percent of notes eligible of early redemption | 35.00% | ||||
Senior notes | 6.625% Senior Notes due 2021 | Company Option [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 106.63% | ||||
Senior notes | 6.625% Senior Notes due 2021 | Change in Control [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 101.00% | ||||
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Four [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 103.31% | ||||
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Five [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 101.66% | ||||
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Six [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price percentage | 100.00% | ||||
Legacy Reserves Finance Corporation [Member] | |||||
Debt Instrument [Line Items] | |||||
Ownership interest | 100.00% | 100.00% | 100.00% |
Acquisitions_Details
Acquisitions (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 20, 2012 | Jun. 04, 2014 | |
Pro Forma Operating Results | |||||
Revenues | $569,674,000 | $549,968,000 | $478,115,000 | ||
Net income | -289,659,000 | -50,041,000 | 97,092,000 | ||
Income (loss) per unit - basic and diluted (in dollars per share) | ($4.82) | ($0.87) | $1.71 | ||
Units Used In Computing Income (Loss) Per Unit [Abstract] | |||||
Basic (in shares) | 60,053,000 | 57,220,000 | 56,887,000 | ||
Diluted (in shares) | 60,053,000 | 57,220,000 | 56,887,000 | ||
COG 2012 Acquisition | |||||
Business Acquisition [Line Items] | |||||
Purchase price | 502,600,000 | ||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | |||||
Proved oil and natural gas properties including related equipment | 495,897,000 | ||||
Unproved properties | 37,994,000 | ||||
Total assets | 533,891,000 | ||||
Future abandonment costs | -31,274,000 | ||||
Fair value of net assets acquired | 502,617,000 | ||||
Units Used In Computing Income (Loss) Per Unit [Abstract] | |||||
Revenues | 96,560,000 | 113,222,000 | 3,693,000 | ||
Excess of revenues over direct operating expenses | 54,320,000 | 73,408,000 | 2,654,000 | ||
WPX acquisition | |||||
Business Acquisition [Line Items] | |||||
Purchase price | 360,000,000 | ||||
Consideration transferred (in shares) | 300,000 | ||||
Estimated issuance date fair value of consideration transfered | 30,800,000 | ||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | |||||
Proved oil and natural gas properties including related equipment | 403,980,000 | ||||
Future abandonment costs | -43,989,000 | ||||
Fair value of net assets acquired | 359,991,000 | ||||
Units Used In Computing Income (Loss) Per Unit [Abstract] | |||||
Revenues | 48,470,000 | 0 | 0 | ||
Excess of revenues over direct operating expenses | 22,333,000 | 0 | 0 | ||
WPX acquisition | General and administrative expense | |||||
Business Acquisition [Line Items] | |||||
Acquisition costs | $5,400,000 | ||||
Immediate vesting | WPX acquisition | |||||
Business Acquisition [Line Items] | |||||
Consideration transferred (in shares) | 100,000 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
President/CEO and Director, EVP, CDO | |||
Related Party Transaction [Line Items] | |||
Noncontrolling ownership interest in third party by related party | 4.16% | ||
Monthly rent expense | $64,841 | ||
FireWheel Energy, LLC | |||
Related Party Transaction [Line Items] | |||
Working interest associated with prospective acreage | 5.00% | 5.00% | |
Prospective acreage purchase price | $1,200,000 | $7,200,000 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Loss Contingencies [Line Items] | |
Purchase obligation, calculated floor price | 57.14 |
Estimated total future purchase obligation | 61.6 |
Officer | |
Loss Contingencies [Line Items] | |
Employment agreements with officers, severance pay consideration period, minimum | 24 months |
Employment agreements with officers, severance pay consideration period, maximum | 36 months |
Business_and_Credit_Concentrat1
Business and Credit Concentrations (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Risks and Uncertainties [Abstract] | |||
Bad debt expense | $0 | $0 | $0 |
Fair value of derivative transactions | $153,100,000 |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 12 Months Ended | 1 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | |
counterparty | ||||
contract | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Impairment expense recorded of proved and unproved oil and natural gas properties | $78,000,000 | $22,800,000 | ||
Total oil and natural gas assets | 1,639,974,000 | 1,535,429,000 | 1,535,429,000 | |
Goodwill impairment recognized | 500,000 | 7,800,000 | ||
Proved Oil and Gas Properties [Member] | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Impairment expense recorded of proved and unproved oil and natural gas properties | 413,300,000 | |||
Unproved Oil and Gas Properties [Member] | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Impairment expense recorded of proved and unproved oil and natural gas properties | 34,950,000 | 7,800,000 | ||
Recurring | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
LTIP liability | -11,000 | -2,217,000 | -2,217,000 | |
Fair value of assets (liabilities) | 151,008,000 | 10,697,000 | 10,697,000 | |
Recurring | Energy related derivative | Oil and natural gas | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative assets | 153,099,000 | 17,673,000 | 17,673,000 | |
Recurring | Interest rate swaps | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative liability | -2,080,000 | -4,759,000 | -4,759,000 | |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
LTIP liability | 0 | 0 | 0 | |
Fair value of assets (liabilities) | 0 | 0 | 0 | |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy related derivative | Oil and natural gas | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative assets | 0 | 0 | 0 | |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate swaps | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative liability | 0 | 0 | 0 | |
Recurring | Significant Other Observable Inputs (Level 2) | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
LTIP liability | -11,000 | -2,217,000 | -2,217,000 | |
Fair value of assets (liabilities) | 150,453,000 | -9,918,000 | -9,918,000 | |
Recurring | Significant Other Observable Inputs (Level 2) | Swap | ||||
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | ||||
Number of contracts amended | 3 | |||
Number of counterparties | 2 | |||
Recurring | Significant Other Observable Inputs (Level 2) | Energy related derivative | Oil and natural gas | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative assets | 152,544,000 | -2,942,000 | -2,942,000 | |
Recurring | Significant Other Observable Inputs (Level 2) | Interest rate swaps | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative liability | -2,080,000 | -4,759,000 | -4,759,000 | |
Recurring | Significant Unobservable Inputs (Level 3) | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
LTIP liability | 0 | 0 | 0 | |
Fair value of assets (liabilities) | 555,000 | 20,615,000 | 20,615,000 | |
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | ||||
Beginning balance | 20,615,000 | 29,966,000 | 30,054,000 | |
Total gains (losses) | -6,185,000 | 4,671,000 | 18,993,000 | |
Settlements | 677,000 | -6,722,000 | -19,081,000 | |
Transfers | -14,552,000 | -7,300,000 | 0 | |
Ending balance | 555,000 | 20,615,000 | 29,966,000 | 20,615,000 |
Gains (losses) included in earnings relating to derivatives still held as of December 31, 2013, 2012 and 2011 | -6,185,000 | 4,671,000 | 18,993,000 | |
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets | ||||
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | ||||
Total gains (losses) | 555,000 | 1,407,000 | 16,065,000 | |
Gains (losses) included in earnings relating to derivatives still held as of December 31, 2013, 2012 and 2011 | 555,000 | 1,407,000 | 16,065,000 | |
Recurring | Significant Unobservable Inputs (Level 3) | Energy related derivative | Oil and natural gas | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative assets | 555,000 | 20,615,000 | 20,615,000 | |
Recurring | Significant Unobservable Inputs (Level 3) | Interest rate swaps | ||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | ||||
Derivative liability | 0 | 0 | 0 | |
Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Total oil and natural gas assets | 0 | 0 | 0 | |
Acquisitions | 0 | 0 | ||
Nonrecurring | Significant Other Observable Inputs (Level 2) | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Total oil and natural gas assets | 0 | 0 | 0 | |
Acquisitions | 0 | 0 | ||
Nonrecurring | Significant Unobservable Inputs (Level 3) | ||||
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract] | ||||
Impairment expense recorded of proved and unproved oil and natural gas properties | 35,400,000 | |||
Oil and gas properties, gross | 667,500,000 | 154,100,000 | 154,100,000 | |
Total oil and natural gas assets | 254,266,000 | 76,137,000 | 76,137,000 | |
Acquisitions | $536,334,000 | $108,415,000 | ||
Number of immaterial transactions | 6 | 16 |
Derivative_Financial_Instrumen2
Derivative Financial Instruments - Commodity Derivatives (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | ||||
Total gain (loss) on derivatives | $140,771 | ($8,743) | $40,999 | |
Derivative cash settlements paid (received) | -2,666 | 7,056 | -5,902 | |
Ending fair value of derivatives | 153,100 | |||
Not designated as hedging instrument | Commodity contract | ||||
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | ||||
Beginning fair value of derivatives | -8,443 | |||
Ending fair value of derivatives | 153,099 | 17,673 | 24,148 | -8,443 |
Not designated as hedging instrument | Commodity contract | Oil | ||||
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | ||||
Total gain (loss) on derivatives | 101,813 | -11,977 | 34,257 | |
Derivative cash settlements paid (received) | 5,431 | 14,160 | 10,211 | |
Not designated as hedging instrument | Commodity contract | Natural gas | ||||
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | ||||
Total gain (loss) on derivatives | 36,279 | -1,554 | 4,236 | |
Derivative cash settlements paid (received) | ($8,097) | ($7,104) | ($16,113) |
Derivative_Financial_Instrumen3
Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Offsetting Derivative Assets: | ||
Gross Amounts of Recognized Assets | $223,778 | $46,356 |
Gross Amounts Offset in the Consolidated Balance Sheets | -70,679 | -21,263 |
Net Amounts Presented in the Consolidated Balance Sheets | 153,099 | 25,093 |
Offsetting Derivative Liabilities: | ||
Gross Amounts of Recognized Liabilities | -72,759 | -33,442 |
Gross Amounts Offset in the Consolidated Balance Sheets | 70,679 | 21,263 |
Net Amounts Presented in the Consolidated Balance Sheets | -2,080 | -12,179 |
Commodity contract | ||
Offsetting Derivative Assets: | ||
Gross Amounts of Recognized Assets | 223,778 | 46,356 |
Gross Amounts Offset in the Consolidated Balance Sheets | -70,679 | -21,263 |
Net Amounts Presented in the Consolidated Balance Sheets | 153,099 | 25,093 |
Offsetting Derivative Liabilities: | ||
Gross Amounts of Recognized Liabilities | -70,679 | -28,683 |
Gross Amounts Offset in the Consolidated Balance Sheets | 70,679 | 21,263 |
Net Amounts Presented in the Consolidated Balance Sheets | 0 | -7,420 |
Interest rate contract | ||
Offsetting Derivative Assets: | ||
Gross Amounts of Recognized Assets | 0 | 0 |
Gross Amounts Offset in the Consolidated Balance Sheets | 0 | 0 |
Net Amounts Presented in the Consolidated Balance Sheets | 0 | 0 |
Offsetting Derivative Liabilities: | ||
Gross Amounts of Recognized Liabilities | -2,080 | -4,759 |
Gross Amounts Offset in the Consolidated Balance Sheets | 0 | 0 |
Net Amounts Presented in the Consolidated Balance Sheets | ($2,080) | ($4,759) |
Derivative_Financial_Instrumen4
Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | bbl |
NYMEX WTI Swaps | Crude Oil | 2015 | |
Derivative [Line Items] | |
Volumes | 1,056,301 |
Average Price | 93.93 |
NYMEX WTI Swaps | Crude Oil | 2015 | Minimum | |
Derivative [Line Items] | |
Price Range | 88.5 |
NYMEX WTI Swaps | Crude Oil | 2015 | Maximum | |
Derivative [Line Items] | |
Price Range | 100.2 |
NYMEX WTI Swaps | Crude Oil | 2016 | |
Derivative [Line Items] | |
Volumes | 228,600 |
Average Price | 87.94 |
NYMEX WTI Swaps | Crude Oil | 2016 | Minimum | |
Derivative [Line Items] | |
Price Range | 86.3 |
NYMEX WTI Swaps | Crude Oil | 2016 | Maximum | |
Derivative [Line Items] | |
Price Range | 99.85 |
NYMEX WTI Swaps | Crude Oil | 2017 | |
Derivative [Line Items] | |
Volumes | 182,500 |
Average Price | 84.75 |
NYMEX WTI Swaps | Crude Oil | 2017 | Minimum | |
Derivative [Line Items] | |
Price Range | 84.75 |
Midland-to-Cushing Differential Swaps | Crude Oil | Q1 2015 | |
Derivative [Line Items] | |
Volumes | 810,000 |
Average Price | -2.34 |
Midland-to-Cushing Differential Swaps | Crude Oil | Q1 2015 | Minimum | |
Derivative [Line Items] | |
Price Range | -2 |
Midland-to-Cushing Differential Swaps | Crude Oil | Q1 2015 | Maximum | |
Derivative [Line Items] | |
Price Range | -2.55 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2015 | |
Derivative [Line Items] | |
Volumes | 1,362,800 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2015 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 65.08 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2015 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 89.69 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2015 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 111.84 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | |
Derivative [Line Items] | |
Volumes | 621,300 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 63.37 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 88.37 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 106.4 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | |
Derivative [Line Items] | |
Volumes | 72,400 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 60 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 85 |
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 104.2 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | |
Derivative [Line Items] | |
Volumes | 183,000 |
Average Price | 91.7 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 82 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 57 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | |
Derivative [Line Items] | |
Volumes | 182,500 |
Average Price | 90.85 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 82 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 57 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | |
Derivative [Line Items] | |
Volumes | 127,750 |
Average Price | 90.5 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 82 |
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 57 |
NYMEX WTI Enhanced Swap Contracts 2 | Crude Oil | 2015 | |
Derivative [Line Items] | |
Volumes | 868,000 |
Average Price | 93.68 |
NYMEX WTI Enhanced Swap Contracts 2 | Crude Oil | 2015 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 76.59 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 18,619,300 |
Average Price | 4.39 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2015 | Minimum | |
Derivative [Line Items] | |
Price Range | 3.98 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2015 | Maximum | |
Derivative [Line Items] | |
Price Range | 5.82 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2016 | |
Derivative [Line Items] | |
Volumes | 1,419,200 |
Average Price | 4.3 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2016 | Minimum | |
Derivative [Line Items] | |
Price Range | 4.12 |
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2016 | Maximum | |
Derivative [Line Items] | |
Price Range | 5.3 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 8,040,000 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2015 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 3.66 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2015 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 4.21 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2015 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 5.01 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | |
Derivative [Line Items] | |
Volumes | 5,580,000 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 3.75 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 4.25 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 5.08 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | |
Derivative [Line Items] | |
Volumes | 5,040,000 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Short | |
Derivative [Line Items] | |
Average Strike Price | 3.75 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Long | |
Derivative [Line Items] | |
Average Strike Price | 4.25 |
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Call option | Short | |
Derivative [Line Items] | |
Average Strike Price | 5.53 |
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps [Member] | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 12,000,000 |
Average Price | -0.13 |
Henry Hub NYMEX to NGPL Midcon Natural Gas Differential Swaps [Member] | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 480,000 |
Average Price | -0.15 |
Henry Hub NYMEX to California SoCal Natural Gas Differential Swaps [Member] | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 240,000 |
Average Price | 0.19 |
Henry Hub NYMEX to San Juan Basin Natural Gas Differential Swaps [Member] | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 480,000 |
Average Price | -0.12 |
Henry Hub NYMEX to West Texas WAHA Natural Gas Differential Swaps [Member] | Natural gas | 2015 | |
Derivative [Line Items] | |
Volumes | 6,000,000 |
Average Price | -0.1 |
Interest rate swaps | Libor Swap All Tranches [Member] | |
Derivative [Line Items] | |
Total fair value of interest rate derivatives | ($2,080) |
Interest rate swaps | Libor Swap Tranche 1 | |
Derivative [Line Items] | |
Notional Amount | 29,000 |
Fixed Rate | 3.07% |
Total fair value of interest rate derivatives | -629 |
Interest rate swaps | Libor Swap Tranche 2 | |
Derivative [Line Items] | |
Notional Amount | 13,000 |
Fixed Rate | 3.11% |
Total fair value of interest rate derivatives | -310 |
Interest rate swaps | Libor Swap Tranche 3 | |
Derivative [Line Items] | |
Notional Amount | 12,000 |
Fixed Rate | 3.13% |
Total fair value of interest rate derivatives | -286 |
Interest rate swaps | Libor Swap Tranche 4 | |
Derivative [Line Items] | |
Notional Amount | 50,000 |
Fixed Rate | 2.50% |
Total fair value of interest rate derivatives | ($855) |
Derivative_Financial_Instrumen5
Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative cash settlements paid | ($2,666) | $7,056 | ($5,902) |
Ending fair value of derivatives | 153,100 | ||
Interest rate swaps | Not designated as hedging instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Beginning fair value of derivatives | -4,759 | -9,547 | -12,053 |
Derivative cash settlements paid | 3,230 | 5,953 | 7,019 |
Ending fair value of derivatives | -2,080 | -4,759 | -9,547 |
Interest rate swaps | Not designated as hedging instrument | Interest expense | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total loss interest rate swaps | ($551) | ($1,165) | ($4,513) |
Sales_to_Major_Customers_Detai
Sales to Major Customers (Details) (Sales Revenue, Goods, Net, Customer Concentration Risk) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Enterprise (Teppco) Crude Oil, LP | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated oil and natural gas revenue | 12.00% | 17.00% | 12.00% |
Plains Marketing, LP | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated oil and natural gas revenue | 10.00% | 7.00% | 10.00% |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Changes in the ARO | |||
Asset retirement obligation — beginning of period | $175,786,000 | $162,183,000 | $120,274,000 |
Liabilities incurred with properties acquired | 50,487,000 | 10,969,000 | 38,857,000 |
Liabilities incurred with properties drilled | 941,000 | 494,000 | 878,000 |
Liabilities settled during the period | -2,918,000 | -2,441,000 | -2,412,000 |
Liabilities associated with properties sold | -5,891,000 | -1,606,000 | 0 |
Current period accretion | 8,120,000 | 6,187,000 | 4,586,000 |
Asset retirement obligation — end of period | 226,525,000 | 175,786,000 | 162,183,000 |
Revisions to previous estimates | $0 | $0 | $0 |
Partners_Equity_Preferred_Unit
Partners' Equity - Preferred Units (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Jun. 04, 2014 | 12-May-14 | Apr. 17, 2014 | Dec. 31, 2014 | Jul. 01, 2014 | Jun. 17, 2014 |
Class of Stock [Line Items] | ||||||
Liquidation preference (in dollars per share) | $25 | |||||
WPX acquisition | ||||||
Class of Stock [Line Items] | ||||||
Consideration transferred (in shares) | 300,000 | |||||
Conversion terms, minimum distribution per share | $0.90 | |||||
WPX acquisition | Immediate vesting | ||||||
Class of Stock [Line Items] | ||||||
Consideration transferred (in shares) | 100,000 | |||||
WPX acquisition | Ratable vesting | ||||||
Class of Stock [Line Items] | ||||||
Consideration transferred (in shares) | 10,000 | |||||
Additional cash consideration | $35.50 | |||||
WPX acquisition | Forfeiture, first two anniversaries | ||||||
Class of Stock [Line Items] | ||||||
Equity interests forfeiture (in shares) | 66,666 | |||||
WPX acquisition | Forfeiture, third anniversary | ||||||
Class of Stock [Line Items] | ||||||
Equity interests forfeiture (in shares) | 66,668 | |||||
Series A Preferred Equity | ||||||
Class of Stock [Line Items] | ||||||
Stock issuance (in shares) | 2,000,000 | |||||
Dividend rate | 8.00% | |||||
Share price (in dollars per share) | $25 | |||||
Additional shares of underwriter purchase option | 300,000 | |||||
Proceeds from offering | 55.2 | |||||
Series A Preferred Equity | three-month LIBOR | ||||||
Class of Stock [Line Items] | ||||||
Variable dividend rate | 5.24% | |||||
Series B Preferred Equity | ||||||
Class of Stock [Line Items] | ||||||
Stock issuance (in shares) | 7,000,000 | |||||
Share price (in dollars per share) | $25 | |||||
Additional shares of underwriter purchase option | 200,000 | |||||
Proceeds from offering | $174.30 | |||||
Series B Preferred Equity | three-month LIBOR | ||||||
Class of Stock [Line Items] | ||||||
Variable dividend rate | 5.26% | |||||
Unvested IDUs [Member] | WPX acquisition | ||||||
Class of Stock [Line Items] | ||||||
Consideration transferred (in shares) | 200,000 |
Partners_Equity_Income_loss_pe
Partners' Equity - Income (loss) per unit (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Equity [Abstract] | |||
Net income (loss) | ($283,645) | ($35,272) | $68,637 |
Distributions to preferred unitholders | -11,694 | 0 | 0 |
Net income (loss) attributable to unitholders | ($295,339) | ($35,272) | $68,637 |
Weighted average number of units outstanding (in shares) | 60,053,000 | 57,220,000 | 48,991,000 |
Effect of dilutive securities: | |||
Restricted and phantom units (in shares) | 0 | 0 | 0 |
Weighted average unit and potential units outstanding (in shares) | 60,053,000 | 57,220,000 | 48,991,000 |
Basic and diluted income (loss) per unit (in dollars per share) | ($4.92) | ($0.62) | $1.40 |
Restricted stock units (RSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive restricted units excluded from computation of EPS | 254,183 | 234,686 | 230,477 |
Phantom share units (PSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive restricted units excluded from computation of EPS | 323,965 | 189,143 |
UnitBased_Compensation_LTIP_Un
Unit-Based Compensation - LTIP, Unit Appreciation Rights and Unit Options (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 15, 2006 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Volatility | 38.00% | 50.00% | 49.00% | |
Annual distribution rate per unit (in dollars per share) | $2.44 | $2.34 | $2.26 | |
Annual interest rate | 1.60% | 1.40% | 1.10% | |
Unit option awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options granted (in shares) | 0 | 0 | 0 | |
Unit appreciation rights (UARs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Other than options granted (in shares) | 241,274 | 234,156 | 142,736 | |
Unit award expiration period | 7 years | 7 years | 7 years | |
Share-based compensation expense | ($1,300,000) | $900,000 | $300,000 | |
Unrecognized compensation costs | 20,700 | |||
Unrecognized compensation costs, weighted-average remaining period for recognition | 2 years 6 months 15 days | |||
Share based compensation, forfeiture rate | 4.70% | |||
Unit appreciation rights (UARs) | Ratable vesting | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Other than options granted (in shares) | 136,100 | 156,650 | 82,400 | |
Award vesting period | 3 years | 3 years | 3 years | |
Unit appreciation rights (UARs) | Cliff vesting | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Other than options granted (in shares) | 105,174 | 77,506 | 60,336 | |
Award vesting period | 3 years | 3 years | 3 years | |
Restricted stock units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based compensation expense | 2,300,000 | 2,300,000 | 1,800,000 | |
Unrecognized compensation costs | 4,700,000 | |||
Unrecognized compensation costs, weighted-average remaining period for recognition | 2 years 2 months 21 days | |||
Phantom share units (PSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based compensation expense | $2,300,000 | $1,200,000 | $900,000 | |
Long Term Incentive Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Units authorized for issuance (in shares) | 2,000,000 | |||
Units issued as compensation (in shares) | 1,254,207 | |||
Long Term Incentive Plan | Unit option awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Units issued as compensation (in shares) | 266,014 | |||
Long Term Incentive Plan | Restricted stock units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Units issued as compensation (in shares) | 533,850 | |||
Long Term Incentive Plan | Phantom share units (PSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Units issued as compensation (in shares) | 323,965 | |||
Long Term Incentive Plan | Unrestricted units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Units issued as compensation (in shares) | 130,378 |
UnitBased_Compensation_Option_
Unit-Based Compensation - Option and UAR Activity (Details) (Unit appreciation rights (UARs), USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Unit appreciation rights (UARs) | |||
Units (in shares) | |||
Outstanding | 627,043 | 516,219 | 620,031 |
Granted | 241,274 | 234,156 | 142,736 |
Exercised | -137,252 | -96,166 | -185,482 |
Forfeited | -61,836 | -27,166 | -61,066 |
Outstanding | 669,229 | 627,043 | 516,219 |
Options and UARs exercisable | 220,056 | 240,288 | 168,569 |
Weighted-Average Exercise Price (in dollars per share) | |||
Outstanding | $25.99 | $24.71 | $22.36 |
Granted | $28.21 | $26.53 | $28.57 |
Exercised | $24.35 | $20.21 | $19.68 |
Forfeited | $27.27 | $26.74 | $24.91 |
Outstanding | $27.01 | $25.99 | $24.71 |
Options and UARs exercisable | $25.50 | $24.02 | $20.54 |
Weighted-Average Remaining Contractual Term | |||
Outstanding | 5 years 1 month 25 days | 5 years 1 month 28 days | 4 years 9 months 8 days |
Options and UARs exercisable | 3 years 6 months 5 days | 3 years 9 months 18 days | 2 years 11 months 5 days |
Aggregate Intrinsic Value | |||
Outstanding | $0 | $1,518,416 | $681,214 |
Options and UARs exercisable | $0 | $1,061,542 | $671,583 |
UnitBased_Compensation_Status_
Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details) (Unit appreciation rights (UARs), USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Unit appreciation rights (UARs) | |
Number of Units | |
Non-vested at January 1, 2014 | 386,755 |
Granted | 241,274 |
Vested | -118,020 |
Forfeited | -60,836 |
Non-vested at December 31, 2014 | 449,173 |
Weighted- Average Exercise Price | |
Non-vested at January 1, 2014 | $27.21 |
Granted | $28.21 |
Vested | $27.03 |
Forfeited | $27.55 |
Non-vested at December 31, 2014 | $27.75 |
UnitBased_Compensation_Weighte
Unit-Based Compensation - Weighted Average Assumptions (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Expected life (years) | 5 years 1 month 25 days | 5 years 1 month 27 days | 4 years 9 months 8 days |
Annual interest rate | 1.60% | 1.40% | 1.10% |
Annual distribution rate per unit (in dollars per share) | $2.44 | $2.34 | $2.26 |
Volatility | 38.00% | 50.00% | 49.00% |
UnitBased_Compensation_Phantom
Unit-Based Compensation - Phantom, Board and Restricted Units (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2013 | Feb. 28, 2012 | 9-May-12 | 15-May-14 | 14-May-13 | Feb. 28, 2011 | |
officer | ||||||||||
Restricted stock units (RSUs) | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Antidilutive restricted units excluded from computation of EPS | 254,183 | 234,686 | 230,477 | |||||||
Executive officers | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Individuals eligible for plan | 5 | |||||||||
Non-employee directors | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Value of each unit at issuance (in dollars per share) | 27.5 | 27.39 | ||||||||
Subjective phantom share units (PSUs) | Executive officers | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 117,197 | 46,430 | 30,828 | |||||||
Objective phantom share units (PSUs) | Executive officers | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 102,572 | 76,723 | 57,189 | |||||||
Phantom share units (PSUs) | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Share-based compensation expense | 2,300,000 | 1,200,000 | 900,000 | |||||||
Restricted stock units (RSUs) | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Share-based compensation expense | 2,300,000 | 2,300,000 | 1,800,000 | |||||||
Unrecognized compensation costs | 4,700,000 | |||||||||
Unrecognized compensation costs, period of recognition | 2 years 2 months 21 days | |||||||||
Restricted stock units (RSUs) | Non-executive employees and certain executives | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 173,645 | |||||||||
Restricted stock units (RSUs) | Non-executive employees and certain executives | Ratable vesting | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Award vesting period | 3 years | |||||||||
Restricted stock units (RSUs) | Non-executive employees | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 127,845 | 85,728 | ||||||||
Restricted stock units (RSUs) | Non-executive employees | Ratable vesting | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Award vesting period | 3 years | 3 years | ||||||||
Unrestricted units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Value of each unit at issuance (in dollars per share) | 28.34 | |||||||||
Unrestricted units | Executive officers | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 2,500 | |||||||||
Unrestricted units | Non-employee directors | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Granted (in shares) | 3,509 | 3,628 | 3,715 | |||||||
Individuals eligible for plan | 5 | 5 | 5 |
Subsidiary_Guarantors_Details
Subsidiary Guarantors (Details) (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | 8-May-14 | Dec. 31, 2014 | 13-May-14 | Dec. 31, 2013 | 28-May-13 |
offering | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $959,000 | $898,000 | |||
Senior notes | 6.625% Senior Notes due 2021 | |||||
Debt Instrument [Line Items] | |||||
Number of private offerings | 2 | ||||
Long-term debt, gross | $550,000 | $300,000 | $250,000 | $250,000 | |
Senior notes | 2020 and 2021 Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Percent of guarantee by subsidiaries owned | 100.00% |
Subsequent_Events_Details
Subsequent Events (Details) (USD $) | 12 Months Ended | 0 Months Ended | ||||
Dec. 31, 2014 | Feb. 19, 2015 | Jan. 23, 2015 | Dec. 31, 2013 | Apr. 01, 2014 | Feb. 23, 2015 | |
Subsequent Event [Line Items] | ||||||
Long-term debt, gross | 959,000,000 | $898,000,000 | ||||
Series A Preferred Equity | ||||||
Subsequent Event [Line Items] | ||||||
Dividend rate | 8.00% | |||||
Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Distribution declared and paid | 0.61 | |||||
Subsequent Event | Series A Preferred Equity | ||||||
Subsequent Event [Line Items] | ||||||
Dividend rate | 8.00% | 8.00% | ||||
Monthly cash distributions to preferred unit holders declared | $0.17 | |||||
Subsequent Event | Series B Preferred Equity | ||||||
Subsequent Event [Line Items] | ||||||
Dividend rate | 8.00% | 8.00% | ||||
Monthly cash distributions to preferred unit holders declared | $0.17 | 0.166667 | ||||
Credit Facility | ||||||
Subsequent Event [Line Items] | ||||||
Current borrowing capacity | 950,000,000 | |||||
Long-term debt, gross | 109,000,000 | 348,000,000 | ||||
Remaining borrowing capacity | 840,900,000 | |||||
Credit Facility | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Current borrowing capacity | 700,000,000 | |||||
Long-term debt, gross | 130,000,000 | |||||
Remaining borrowing capacity | $569,900,000 | |||||
Maximum | Credit Facility | ||||||
Subsequent Event [Line Items] | ||||||
Ratio of Indebtedness to Earnings Before Interest, Taxes, Depreciation and Amortization | 4.5 | |||||
Maximum | Credit Facility | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Ratio of Indebtedness to Earnings Before Interest, Taxes, Depreciation and Amortization | 2.5 | |||||
Minimum | Credit Facility | ||||||
Subsequent Event [Line Items] | ||||||
Ratio of Indebtedness to Earnings Before Interest, Taxes, Depreciation and Amortization | 4 | |||||
Minimum | Credit Facility | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Ratio of Earnings Before Interest Taxes Depreciation And Amortization to Interest Expense | 2.5 | |||||
Ratio of Current Assets Current Liabilities | 1 |