Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2014 | Nov. 06, 2014 | |
Document And Entity Information [Abstract] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 30-Sep-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Entity Registrant Name | 'Atlas Resource Partners, L.P. | ' |
Entity Central Index Key | '0001532750 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Units Outstanding | ' | 81,547,791 |
Trading Symbol | 'ARP | ' |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ' | ' |
Cash and cash equivalents | $5,167 | $1,828 |
Accounts receivable | 99,656 | 58,822 |
Current portion of derivative asset | 21,050 | 1,891 |
Subscriptions receivable | 62,840 | 47,692 |
Prepaid expenses and other | 24,783 | 10,097 |
Total current assets | 213,496 | 120,330 |
Property, plant and equipment, net | 2,657,060 | 2,120,818 |
Goodwill and intangible assets, net | 32,543 | 32,747 |
Long-term derivative asset | 30,826 | 27,084 |
Other assets, net | 52,477 | 42,821 |
Total assets | 2,986,402 | 2,343,800 |
Current liabilities: | ' | ' |
Accounts payable | 104,275 | 69,346 |
Advances from affiliates | 26,342 | 26,742 |
Liabilities associated with drilling contracts | ' | 49,377 |
Current portion of derivative liability | 1,792 | 6,353 |
Accrued well drilling and completion costs | 100,226 | 40,481 |
Accrued interest | 10,840 | 20,622 |
Distribution payable | 18,901 | ' |
Accrued liabilities | 24,157 | 30,794 |
Total current liabilities | 286,533 | 243,715 |
Long-term debt | 1,283,022 | 942,334 |
Asset retirement obligations | 101,474 | 89,776 |
Other long-term liabilities | 1,745 | 684 |
Commitments and contingencies | ' | ' |
Partners’ Capital: | ' | ' |
General partner’s interest | -890 | 4,482 |
Preferred limited partners’ interests | 180,568 | 183,477 |
Common limited partners’ interests | 1,079,476 | 852,457 |
Accumulated other comprehensive income | 53,298 | 25,699 |
Total partners’ capital | 1,313,628 | 1,067,291 |
Total liabilities and partners' capital | 2,986,402 | 2,343,800 |
Common Class C | ' | ' |
Partners’ Capital: | ' | ' |
Class C common limited partner warrants | $1,176 | $1,176 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Revenues: | ' | ' | ' | ' | ||||
Gas and oil production | $125,394 | $80,332 | $325,696 | $173,490 | ||||
Well construction and completion | 61,204 | 10,964 | 126,917 | 92,293 | ||||
Gathering and processing | 3,061 | 3,591 | 11,287 | 11,639 | ||||
Administration and oversight | 6,177 | 4,447 | 12,072 | 8,923 | ||||
Well services | 6,597 | 5,023 | 18,441 | 14,703 | ||||
Other, net | 261 | -13,272 | 343 | -14,589 | ||||
Total revenues | 202,694 | 91,085 | 494,756 | 286,459 | ||||
Costs and expenses: | ' | ' | ' | ' | ||||
Gas and oil production | 49,922 | 29,419 | 128,477 | 63,670 | ||||
Well construction and completion | 53,221 | 9,534 | 110,363 | 80,255 | ||||
Gathering and processing | 3,214 | 4,395 | 11,900 | 13,767 | ||||
Well services | 2,617 | 2,386 | 7,525 | 7,009 | ||||
General and administrative | 13,124 | [1] | 31,983 | [1] | 50,894 | [1] | 63,767 | [1] |
Depreciation, depletion and amortization | 62,852 | 41,656 | 171,090 | 85,061 | ||||
Total costs and expenses | 184,950 | 119,373 | 480,249 | 313,529 | ||||
Operating income (loss) | 17,744 | -28,288 | 14,507 | -27,070 | ||||
Interest expense | -16,577 | [1] | -10,748 | [1] | -43,028 | [1] | -22,145 | [1] |
Loss on asset sales and disposal | -92 | [1] | -661 | [1] | -1,686 | [1] | -2,035 | [1] |
Net income (loss) | 1,075 | -39,697 | -30,207 | -51,250 | ||||
Preferred limited partner dividends | -4,475 | -3,564 | -13,298 | -7,592 | ||||
Net loss attributable to common limited partners and the general partner | -3,400 | -43,261 | -43,505 | -58,842 | ||||
Allocation of net income (loss) attributable to common limited partners and the general partner: | ' | ' | ' | ' | ||||
Common limited partners’ interest | -6,393 | -44,073 | -50,879 | -60,977 | ||||
General partner’s interest | 2,993 | 812 | 7,374 | 2,135 | ||||
Net loss attributable to common limited partners and the general partner | ($3,400) | ($43,261) | ($43,505) | ($58,842) | ||||
Net loss attributable to common limited partners per unit: | ' | ' | ' | ' | ||||
Basic and Diluted | ($0.08) | ($0.74) | ($0.70) | ($1.21) | ||||
Weighted average common limited partner units outstanding: | ' | ' | ' | ' | ||||
Basic and Diluted | 81,522 | 59,440 | 72,288 | 50,197 | ||||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Statement Of Income And Comprehensive Income [Abstract] | ' | ' | ' | ' |
Net income (loss) | $1,075 | ($39,697) | ($30,207) | ($51,250) |
Other comprehensive income (loss): | ' | ' | ' | ' |
Changes in fair value of derivative instruments accounted for as cash flow hedges | 68,811 | 15,064 | 5,675 | 33,093 |
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net income (loss) | -1,304 | -1,145 | 21,924 | -4,424 |
Total other comprehensive income | 67,507 | 13,919 | 27,599 | 28,669 |
Comprehensive income (loss) attributable to common and preferred limited partners and the general partner | $68,582 | ($25,778) | ($2,608) | ($22,581) |
CONSOLIDATED_STATEMENT_OF_PART
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (USD $) | Total | Accumulated Other Comprehensive Income (Loss) | General Partners’ Interest | Preferred Limited Partners Interests | Preferred Limited Partners Interests | Common Limited Partners’ Interests | Class C Common Limited Partner Warrants |
In Thousands, except Share data | General Class A | Preferred Class B | Preferred Class C | ||||
Balance at Dec. 31, 2013 | $1,067,291 | $25,699 | $4,482 | $96,539 | $86,938 | $852,457 | $1,176 |
Balance (units) at Dec. 31, 2013 | ' | ' | 1,368,058 | 3,836,554 | 3,749,986 | 59,448,308 | 562,497 |
Issuance of units | 426,253 | ' | ' | ' | ' | 426,253 | ' |
Issuance of units (units) | ' | ' | 450,926 | ' | ' | 21,860,000 | ' |
Net issued and unissued units under incentive plans | 5,579 | ' | ' | ' | ' | 5,579 | ' |
Net issued and unissued units under incentive plans (units) | ' | ' | ' | ' | ' | 235,402 | ' |
Distributions payable | -18,901 | ' | -1,378 | -754 | -737 | -16,032 | ' |
Distributions paid to common and preferred limited partners and the general partner | -162,290 | ' | -11,368 | -7,442 | -7,274 | -136,206 | ' |
Distribution equivalent rights paid on unissued units under incentive plan | -1,696 | ' | ' | ' | ' | -1,696 | ' |
Net income (loss) | -30,207 | ' | 7,374 | 6,724 | 6,574 | -50,879 | ' |
Other comprehensive income | 27,599 | 27,599 | ' | ' | ' | ' | ' |
Balance at Sep. 30, 2014 | $1,313,628 | $53,298 | ($890) | $95,067 | $85,501 | $1,079,476 | $1,176 |
Balance (units) at Sep. 30, 2014 | ' | ' | 1,818,984 | 3,836,554 | 3,749,986 | 81,543,710 | 562,497 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 9 Months Ended | |||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' | ||
Net loss | ($30,207) | ($51,250) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ' | ' | ||
Depreciation, depletion and amortization | 171,090 | 85,061 | ||
Loss on asset sales and disposal | 1,686 | [1] | 2,035 | [1] |
Non-cash compensation expense | 6,343 | 10,209 | ||
Amortization of deferred financing costs | 6,098 | 8,608 | ||
Changes in operating assets and liabilities: | ' | ' | ||
Accounts receivable, prepaid expenses and other | -69,008 | 27,990 | ||
Accounts payable and accrued liabilities | -16,030 | -69,463 | ||
Net cash provided by operating activities | 69,972 | 13,190 | ||
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' | ||
Capital expenditures | -150,485 | -203,996 | ||
Net cash paid for acquisitions | -507,093 | -712,984 | ||
Other | -13 | -5,676 | ||
Net cash used in investing activities | -657,591 | -922,656 | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' | ||
Borrowings under credit facilities | 1,034,000 | 752,000 | ||
Repayments under credit facilities | -793,000 | -678,425 | ||
Net proceeds from issuance of long-term debt | 97,386 | 510,518 | ||
Distributions paid to unitholders | -162,290 | -84,950 | ||
Net proceeds from issuance of common limited partner units | 426,253 | 320,092 | ||
Deferred financing costs, distribution equivalent rights and other | -11,391 | -18,129 | ||
Net cash provided by financing activities | 590,958 | 887,730 | ||
Net change in cash and cash equivalents | 3,339 | -21,736 | ||
Cash and cash equivalents, beginning of year | 1,828 | 23,188 | ||
Cash and cash equivalents, end of period | 5,167 | 1,452 | ||
Preferred Class C | ' | ' | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' | ||
Net proceeds from issuance of Class C preferred limited partner units and warrants | ' | $86,624 | ||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Basis_of_Presentation
Basis of Presentation | 9 Months Ended |
Sep. 30, 2014 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ' |
Basis of Presentation | ' |
NOTE 1 – BASIS OF PRESENTATION | |
Atlas Resource Partners, L.P. (the “Partnership”) is a publicly traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. The Partnership sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. At September 30, 2014, Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of the general partner Class A units, all of the incentive distribution rights through which it manages and effectively controls the Partnership and an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in the Partnership. | |
The Partnership was formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets (“Atlas Energy E&P Operations”), which were transferred to the Partnership on March 5, 2012. In February 2012, the board of ATLS’ general partner approved the distribution of approximately 5.24 million of the Partnership’s common units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 of the Partnership’s limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012. | |
The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2013 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation. The results of operations for the three and nine months ended September 30, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Accounting Policies [Abstract] | ' | |||||||||||||||
Summary of Significant Accounting Policies | ' | |||||||||||||||
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||||||
Principles of Consolidation | ||||||||||||||||
The Partnership’s consolidated balance sheets at September 30, 2014 and December 31, 2013 and the consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. | ||||||||||||||||
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which the Partnership has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note. | ||||||||||||||||
Use of Estimates | ||||||||||||||||
The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates. | ||||||||||||||||
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”). | ||||||||||||||||
Receivables | ||||||||||||||||
Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At September 30, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | ||||||||||||||||
Inventory | ||||||||||||||||
The Partnership had $8.6 million and $4.6 million of inventory at September 30, 2014 and December 31, 2013, respectively, which was included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. | ||||||||||||||||
Property, Plant and Equipment | ||||||||||||||||
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. | ||||||||||||||||
The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet. | ||||||||||||||||
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators. | ||||||||||||||||
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. | ||||||||||||||||
Impairment of Long-Lived Assets | ||||||||||||||||
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. | ||||||||||||||||
The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. | ||||||||||||||||
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Partnership’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Partnership’s actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. | ||||||||||||||||
The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. | ||||||||||||||||
The Partnership’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to the Partnership becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s limited partner agreement. In general, the Partnership will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon the Partnership’s determination of fair market value. | ||||||||||||||||
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, the Partnership recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on its consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by the Partnership for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, the Partnership recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. There were no impairments of proved gas and oil properties recorded by the Partnership for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013 and management’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. | ||||||||||||||||
Capitalized Interest | ||||||||||||||||
The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds by the Partnership was 5.4% and 6.3% for the three months ended September 30, 2014 and 2013, respectively, and 5.7% and 6.1% for the nine months ended September 30, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $3.7 million and $3.6 million for the three months ended September 30, 2014 and 2013, respectively, and $9.4 million and $10.5 million for the nine months ended September 30, 2014 and 2013, respectively. | ||||||||||||||||
Intangible Assets | ||||||||||||||||
The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance method over their respective estimated useful lives. | ||||||||||||||||
The following table reflects the components of intangible assets being amortized at September 30, 2014 and December 31, 2013 (in thousands): | ||||||||||||||||
September 30, | December 31, | Estimated | ||||||||||||||
2014 | 2013 | Useful Lives | ||||||||||||||
In Years | ||||||||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | |||||||||||
Accumulated Amortization | (13,585 | ) | (13,381 | ) | ||||||||||||
Net Carrying Amount | $ | 759 | $ | 963 | ||||||||||||
Amortization expense on intangible assets was $0.1 million for both the three months ended September 30, 2014 and 2013, respectively, and $0.2 million and $0.3 million for the nine months ended September 30, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $0.3 million; 2015 - $0.2 million; 2016 - $0.1 million, 2017 - $0.1 million and 2018 - $0.1 million. | ||||||||||||||||
Goodwill | ||||||||||||||||
At September 30, 2014 and December 31, 2013, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The Partnership tests goodwill for impairment at each year end by comparing its reporting units’ estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the Partnership’s assets and the available market data of the industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Partnership’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. Management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and nine months ended September 30, 2014 and 2013, no impairment indicators arose, and no goodwill impairments were recognized by the Partnership. | ||||||||||||||||
Asset Retirement Obligations | ||||||||||||||||
The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization. | ||||||||||||||||
Income Taxes | ||||||||||||||||
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated financial statements. | ||||||||||||||||
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to record interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2014. | ||||||||||||||||
Net Income (Loss) Per Common Unit | ||||||||||||||||
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, income (loss) attributable to preferred limited partners and net income (loss) attributable to the General Partner’s Class A units. The General Partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the General Partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partner’s and limited partners’ ownership interests. | ||||||||||||||||
The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. | ||||||||||||||||
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. | ||||||||||||||||
The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income (loss) | $ | 1,075 | $ | (39,697 | ) | $ | (30,207 | ) | $ | (51,250 | ) | |||||
Preferred limited partner dividends | (4,475 | ) | (3,564 | ) | (13,298 | ) | (7,592 | ) | ||||||||
Net loss attributable to common limited partners and the general partner | (3,400 | ) | (43,261 | ) | (43,505 | ) | (58,842 | ) | ||||||||
Less: General partner’s interest | (2,993 | ) | (812 | ) | (7,374 | ) | (2,135 | ) | ||||||||
Net loss attributable to common limited partners | (6,393 | ) | (44,073 | ) | (50,879 | ) | (60,977 | ) | ||||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | — | ||||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (6,393 | ) | $ | (44,073 | ) | $ | (50,879 | ) | $ | (60,977 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 797,000 and 835,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the nine months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 780,000 and 918,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | |||||||||||||||
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 14). | ||||||||||||||||
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - basic | ||||||||||||||||
Add effect of dilutive | — | — | — | — | ||||||||||||
incentive awards(1) | ||||||||||||||||
Add effect of dilutive convertible | — | — | — | — | ||||||||||||
preferred limited partner units and | ||||||||||||||||
warrants(2) | ||||||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - diluted | ||||||||||||||||
(1) | For the three months ended September 30, 2014 and 2013, approximately 797,000 units and 835,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the nine months ended September 30, 2014 and 2013, approximately 780,000 units and 918,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
(2) | For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Revenue Recognition | ||||||||||||||||
Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within its consolidated statements of operations. | ||||||||||||||||
The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. | ||||||||||||||||
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues of $83.2 million and $55.3 million at September 30, 2014 and December 31, 2013, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets. | ||||||||||||||||
Gathering and processing revenue includes gathering fees the Partnership charges to the Drilling Partnership wells for the Partnership’s processing plants in the New Albany Shale and the Chattanooga Shale. Generally, the Partnership charges a gathering fee to the Drilling Partnership wells equivalent to the fees the Partnership remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby the Partnership remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, the Partnership charges the Drilling Partnership wells a 13% gathering fee. As a result, some of the Partnership’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | ||||||||||||||||
Comprehensive Income (Loss) | ||||||||||||||||
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and at September 30, 2014, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). | ||||||||||||||||
Recently Adopted Accounting Standards | ||||||||||||||||
In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application was permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | ||||||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. |
Acquisitions
Acquisitions | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Business Combinations [Abstract] | ' | |||||||||||||||
Acquisitions | ' | |||||||||||||||
NOTE 3 – ACQUISITIONS | ||||||||||||||||
Rangely Acquisition | ||||||||||||||||
On June 30, 2014, the Partnership completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado for approximately $407.8 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under the Partnership’s revolving credit facility, the issuance of an additional $100.0 million of its 7.75% senior notes due 2021 (see Note 7) and the issuance of 15,525,000 common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. | ||||||||||||||||
The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $11.6 million of transaction fees, which were included with common limited partners’ interests for the nine months ended September 30, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date. | ||||||||||||||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||||||||
Assets: | ||||||||||||||||
Prepaid expenses and other | $ | 4,041 | ||||||||||||||
Property, plant and equipment | 405,065 | |||||||||||||||
Other assets, net | 2,944 | |||||||||||||||
Total current assets | $ | 412,050 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accrued liabilities | 2,936 | |||||||||||||||
Asset retirement obligation | 1,305 | |||||||||||||||
Total liabilities assumed | 4,241 | |||||||||||||||
Net assets acquired | $ | 407,809 | ||||||||||||||
EP Energy Acquisition | ||||||||||||||||
On July 31, 2013, the Partnership completed the acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). The purchase price was funded through borrowings under the Partnership’s revolving credit facility, the issuance of the Partnership’s 9.25% senior notes due August 15, 2021 (see Note 7), and the issuance of 14,950,000 common limited partner units and 3,749,986 newly created Class C convertible preferred units (see Note 12). The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing July 31, 2013 with the transaction closing. | ||||||||||||||||
The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $12.1 million of transaction fees, which were included within common limited partners’ interests for the year ended December 31, 2013 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands): | ||||||||||||||||
Assets: | ||||||||||||||||
Prepaid expenses and other | $ | 5,268 | ||||||||||||||
Property, plant and equipment | 723,842 | |||||||||||||||
Total current assets | $ | 729,110 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accounts payable | 2,747 | |||||||||||||||
Asset retirement obligation | 16,728 | |||||||||||||||
Total liabilities assumed | 19,475 | |||||||||||||||
Net assets acquired | $ | 709,635 | ||||||||||||||
Pro Forma Financial Information | ||||||||||||||||
The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Rangely and EP Energy acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred units had occurred on January 1, 2013. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per share data; unaudited): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Total revenues and other | $ | 202,694 | $ | 127,652 | $ | 540,757 | $ | 445,018 | ||||||||
Net income (loss) | (3,400 | ) | (10,900 | ) | (12,617 | ) | 15,678 | |||||||||
Net income (loss) attributable to common limited partners | (6,393 | ) | (12,359 | ) | (20,609 | ) | 12,053 | |||||||||
Net income (loss) attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (0.08 | ) | $ | (0.15 | ) | $ | (0.26 | ) | $ | 0.15 | |||||
Diluted | $ | (0.08 | ) | $ | (0.15 | ) | $ | (0.26 | ) | $ | 0.15 | |||||
Other Acquisitions | ||||||||||||||||
On May 12, 2014, the Partnership completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $99.3 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. | ||||||||||||||||
On September 20, 2013, the Partnership completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013. |
Property_Plant_and_Equipment
Property, Plant and Equipment | 9 Months Ended | |||||||||||
Sep. 30, 2014 | ||||||||||||
Property Plant And Equipment [Abstract] | ' | |||||||||||
Property, Plant and Equipment | ' | |||||||||||
NOTE 4 – PROPERTY, PLANT AND EQUIPMENT | ||||||||||||
The following is a summary of property, plant and equipment at the dates indicated (in thousands): | ||||||||||||
September 30, | December 31, | Estimated | ||||||||||
2014 | 2013 | Useful Lives | ||||||||||
in Years | ||||||||||||
Natural gas and oil properties: | ||||||||||||
Proved properties: | ||||||||||||
Leasehold interests | $ | 401,509 | $ | 320,459 | ||||||||
Pre-development costs | 6,092 | 4,367 | ||||||||||
Wells and related equipment | 2,762,577 | 2,164,760 | ||||||||||
Total proved properties | 3,170,178 | 2,489,586 | ||||||||||
Unproved properties | 214,874 | 211,536 | ||||||||||
Support equipment | 34,692 | 23,005 | ||||||||||
Total natural gas and oil properties | 3,419,744 | 2,724,127 | ||||||||||
Pipelines, processing and compression facilities | 43,719 | 42,949 | 2 – 40 | |||||||||
Rights of way | 830 | 830 | 20 – 40 | |||||||||
Land, buildings and improvements | 9,072 | 9,462 | 3 – 40 | |||||||||
Other | 17,538 | 15,318 | 3 – 10 | |||||||||
3,490,903 | 2,792,686 | |||||||||||
Less – accumulated depreciation, depletion and amortization | (833,843 | ) | (671,868 | ) | ||||||||
$ | 2,657,060 | $ | 2,120,818 | |||||||||
During the nine months ended September 30, 2014 and 2013, the Partnership recognized $42.8 million and $23.8 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s consolidated statements of cash flows. | ||||||||||||
During the three and nine months ended September 30, 2014, the Partnership recognized $0.1 and $1.7 million, respectively, of loss on asset disposal primarily related to the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farmout agreement. During the three and nine months ended September 30, 2013, the Partnership recognized $0.7 million and $2.0 million, respectively, of loss on asset disposal, pertaining to its decision not to drill wells on leasehold property that expired in such periods in Indiana and Tennessee. | ||||||||||||
During the year ended December 31, 2013, the Partnership recognized $38.0 million of asset impairments related to its oil and gas properties within property, plant and equipment, net on its consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amounts of gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013, and management’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. |
Other_Assets
Other Assets | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
Other Assets Noncurrent Disclosure [Abstract] | ' | |||||||
Other Assets | ' | |||||||
NOTE 5 – OTHER ASSETS | ||||||||
The following is a summary of other assets at the dates indicated (in thousands): | ||||||||
September 30, | December 31, | |||||||
2014 | 2013 | |||||||
Deferred financing costs, net of accumulated amortization of $18,046 and $11,948 at September 30, 2014 and December 31, 2013, respectively | $ | 40,553 | $ | 35,292 | ||||
Notes receivable | 3,754 | 3,978 | ||||||
Long-term derivative asset receivable from Drilling Partnerships | 622 | 863 | ||||||
Other | 7,548 | 2,688 | ||||||
$ | 52,477 | $ | 42,821 | |||||
Deferred financing costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7). Amortization expense of deferred financing costs was $2.4 million and $2.8 million for the three months ended September 30, 2014 and 2013, respectively, and $6.1 million and $5.4 million for the nine months ended September 30, 2014 and 2013, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the three and nine months ended September 30, 2014, the Partnership recognized $0.2 million and $8.4 million, respectively, of deferred financing costs relating to the amendment to its revolving credit facility in connection with the Rangely Acquisition (see Note 7). During the nine months ended September 30, 2013, the Partnership recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of its 7.75% senior notes due 2021 (see Note 7). There was no accelerated amortization of deferred financing costs during the three months ended September 30, 2014 and 2013 and during the nine months ended September 30, 2014. | ||||||||
At September 30, 2014 and December 31, 2013, the Partnership had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Partnership’s consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain conditions, including an extension fee of 1.0% of the outstanding principal balance. For the three and nine months ended September 30, 2014, approximately $22,000 and $68,000 of interest income, respectively, was recognized within other, net on the Partnership’s consolidated statements of operations. For the three and nine months ended September 30, 2013, there was approximately $25,000 and $50,000, respectively, of interest income recognized within other, net on the Partnership’s consolidated statements of operations. At September 30, 2014, the Partnership recorded no allowance for credit losses within its consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the notes receivable. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | |||||||||||||||
Asset Retirement Obligations | ' | |||||||||||||||
NOTE 6 – ASSET RETIREMENT OBLIGATIONS | ||||||||||||||||
The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its future asset retirement obligations where a reasonable estimate of the fair value of that liability could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization. | ||||||||||||||||
The estimated liability for asset retirement obligations was based on the Partnership’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets. | ||||||||||||||||
The Partnership proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At September 30, 2014, the Drilling Partnerships had $56.0 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of the Partnership’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, the Partnership maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of September 30, 2014, the Partnership withheld approximately $1.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. The Partnership’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, the Partnership assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, the Partnership’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the Partnership’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, the Partnership will assume the related asset retirement obligations of the limited partners. | ||||||||||||||||
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Asset retirement obligations, beginning of period | $ | 100,002 | $ | 67,732 | $ | 89,776 | $ | 64,794 | ||||||||
Liabilities incurred | 323 | 14,699 | 8,178 | 15,943 | ||||||||||||
Liabilities settled | (270 | ) | (158 | ) | (688 | ) | (381 | ) | ||||||||
Accretion expense | 1,419 | 1,294 | 4,208 | 3,211 | ||||||||||||
Asset retirement obligations, end of period | $ | 101,474 | $ | 83,567 | $ | 101,474 | $ | 83,567 | ||||||||
The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations in the Partnership’s consolidated balance sheets. During the nine months ended September 30, 2014, the Partnership incurred $6.6 million of future plugging and abandonment liabilities within purchase accounting for the Rangely and GeoMet acquisitions it consummated during the period (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three months ended September 30, 2014. During the year ended December 31, 2013, the Partnership incurred $16.7 million of future plugging and abandonment liabilities within purchase accounting for the EP Energy Acquisition it consummated during the period. |
Debt
Debt | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
Debt Disclosure [Abstract] | ' | |||||||
Debt | ' | |||||||
NOTE 7 - DEBT | ||||||||
Total debt consists of the following at the dates indicated (in thousands): | ||||||||
September 30, | December 31, | |||||||
2014 | 2013 | |||||||
Revolving credit facility | $ | 660,000 | $ | 419,000 | ||||
7.75 % Senior Notes – due 2021 | 374,525 | 275,000 | ||||||
9.25 % Senior Notes – due 2021 | 248,497 | 248,334 | ||||||
Total debt | 1,283,022 | 942,334 | ||||||
Less current maturities | — | — | ||||||
Total long-term debt | $ | 1,283,022 | $ | 942,334 | ||||
Credit Facility | ||||||||
On September 24, 2014, in connection with its Eagle Ford acquisition (see Note 16), the Partnership entered into a fourth amendment to its revolving credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (as so amended, the “Credit Agreement”). The Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of $825.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. The fourth amendment amends the Credit Agreement to permit the guarantee by the Partnership of certain deferred purchase price obligations and contingent indemnity obligations in connection with the Eagle Ford acquisition, and, with certain constraints, to permit the Partnership and its subsidiaries to enter into certain derivative instruments related to the producing wells to be acquired in the Eagle Ford acquisition. | ||||||||
The Partnership’s borrowing base under the revolving credit facility is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.4 million was outstanding at September 30, 2014. The Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of the Partnership’s material subsidiaries, and any non-guarantor subsidiaries of the Partnership are minor. Borrowings under the revolving credit facility bear interest, at the Partnership’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At September 30, 2014, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 2.5%. | ||||||||
The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of September 30, 2014. The Credit Agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended through December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter, and a ratio of current assets (as defined in the Credit Agreement) to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the Partnership’s Credit Agreement, at September 30, 2014, the Partnership’s ratio of current assets to current liabilities was 1.2 to 1.0, and its ratio of Total Funded Debt to EBITDA was 4.0 to 1.0. | ||||||||
Senior Notes | ||||||||
At September 30, 2014, the Partnership had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% Senior Notes”), inclusive of an additional $100.0 million of such notes issued in a private placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition (see Note 3). The Partnership issued $275.0 million of its 7.75% Senior Notes in a private placement transaction at par on January 23, 2013. The 7.75% Senior Notes were presented net of a $0.5 million unamortized discount as of September 30, 2014. Interest is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. | ||||||||
The Partnership entered into a registration rights agreement with respect to the $100.0 million 7.75% Senior Notes issued in June 2014. Under the registration rights agreement, the Partnership will cause to be filed with the SEC a registration statement with respect to offers to exchange the 7.75% Senior Notes for substantially identical notes that are registered under the Securities Act of 1933, as amended (the “Securities Act”). The Partnership will use reasonable best efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Partnership will use reasonable best efforts to cause an exchange offer to be consummated not later than 270 days after the issuance of the 7.75% Senior Notes. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, the Partnership has agreed to file a shelf registration statement with respect to the 7.75% Senior Notes. The Partnership is required to pay additional interest if it fails to comply with its obligations to register the 7.75% Senior Notes within the specified time periods. | ||||||||
At September 30, 2014, the Partnership had $248.5 million of its 9.25% senior unsecured notes due 2021 (“9.25% Senior Notes”). The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% Senior Notes were presented net of a $1.5 million unamortized discount as of September 30, 2014. Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. At any time on or after August 15, 2017, the Partnership may redeem some or all of the 9.25% Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, the Partnership may redeem up to 35% of the 9.25% Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 9.25% Senior Notes. | ||||||||
In connection with the issuance of the 9.25% Senior Notes, the Partnership entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014. | ||||||||
The 9.25% Senior Notes and 7.75% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 9.25% Senior Notes and 7.75% Senior Notes are full and unconditional and joint and several, and any subsidiaries of the Partnership, other than the subsidiary guarantors, are minor. There are no restrictions on the Partnership’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. | ||||||||
The indentures governing the 9.25% Senior Notes and 7.75% Senior Notes contain covenants, including limitations on the Partnership’s ability to incur certain liens; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of the Partnership’s assets. The Partnership was in compliance with these covenants as of September 30, 2014. | ||||||||
Total cash payments for interest by the Partnership were $55.2 million and $15.2 million for the nine months ended September 30, 2014 and 2013, respectively. |
Derivative_Instruments
Derivative Instruments | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ' | |||||||||||||||
Derivative Instruments | ' | |||||||||||||||
NOTE 8 – DERIVATIVE INSTRUMENTS | ||||||||||||||||
The Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity and interest rate price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged. | ||||||||||||||||
Management formally documents all relationships between the Partnership’s hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. Management assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the Partnership through the utilization of market data, will be recognized immediately within other, net in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, management recognizes changes in fair value within other, net in the Partnership’s consolidated statements of operations as they occur. | ||||||||||||||||
The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its consolidated balance sheets of $50.1 million and $22.6 million at September 30, 2014 and December 31, 2013, respectively. Of the $53.3 million of net gain in accumulated other comprehensive income on the Partnership’s consolidated balance sheet at September 30, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $21.0 million of gains to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $32.3 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. Approximately $0.3 million and $0.8 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the three and nine months ended September 30, 2014, respectively. Approximately $1.3 million and $0.8 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the three and nine months ended September 30, 2013, respectively. | ||||||||||||||||
The following table summarizes the gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments for the periods indicated (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(Gain) loss reclassified from accumulated other comprehensive | ||||||||||||||||
income (loss): | ||||||||||||||||
Gas and oil production | $ | (1,304 | ) | $ | (1,145 | ) | $ | 21,924 | $ | (4,424 | ) | |||||
revenue | ||||||||||||||||
Total | $ | (1,304 | ) | $ | (1,145 | ) | $ | 21,924 | $ | (4,424 | ) | |||||
The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands): | ||||||||||||||||
Offsetting Derivative Assets | Gross | Gross | Net Amount of | |||||||||||||
Amounts of | Amounts | Assets | ||||||||||||||
Recognized | Offset in the | Presented in the | ||||||||||||||
Assets | Consolidated | Consolidated | ||||||||||||||
Balance Sheets | Balance Sheets | |||||||||||||||
As of September 30, 2014 | ||||||||||||||||
Current portion of derivative assets | $ | 23,604 | $ | (2,554 | ) | $ | 21,050 | |||||||||
Long-term portion of derivative assets | 31,950 | (1,124 | ) | 30,826 | ||||||||||||
Total derivative assets | $ | 55,554 | $ | (3,678 | ) | $ | 51,876 | |||||||||
As of December 31, 2013 | ||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | |||||||||
Long-term portion of derivative assets | 31,146 | (4,062 | ) | 27,084 | ||||||||||||
Current portion of derivative liabilities | 4,341 | (4,341 | ) | — | ||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | ||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | |||||||||
Offsetting Derivative Liabilities | Gross | Gross | Net Amount of | |||||||||||||
Amounts of | Amounts | Liabilities | ||||||||||||||
Recognized | Offset in the | Presented in the | ||||||||||||||
Liabilities | Consolidated | Consolidated | ||||||||||||||
Balance Sheets | Balance Sheets | |||||||||||||||
As of September 30, 2014 | ||||||||||||||||
Current portion of derivative assets | $ | (2,554 | ) | $ | 2,554 | $ | — | |||||||||
Long-term portion of derivative assets | (1,124 | ) | 1,124 | — | ||||||||||||
Current portion of derivative liabilities | (1,792 | ) | (1,792 | ) | ||||||||||||
Total derivative liabilities | $ | (5,470 | ) | $ | 3,678 | $ | (1,792 | ) | ||||||||
As of December 31, 2013 | ||||||||||||||||
Current portion of derivative assets | $ | (773 | ) | $ | 773 | $ | — | |||||||||
Long-term portion of derivative assets | (4,062 | ) | 4,062 | — | ||||||||||||
Current portion of derivative liabilities | (10,694 | ) | 4,341 | (6,353 | ) | |||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | |||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | ||||||||
The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts have qualified and been designated as cash flow hedges and were recorded at their fair values. | ||||||||||||||||
During the nine months ended September 30, 2013, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 3). In connection with the swaption contracts, the Partnership paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and was fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through their termination date. For the three and nine months ended September 30, 2013, the Partnership recognized $13.2 million and $14.5 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts. | ||||||||||||||||
The Partnership recognized gains of $1.3 million and gains of $1.1 million for the three months ended September 30, 2014 and 2013, respectively, and losses of $21.9 million and gains of $4.4 million for the nine months ended September 30, 2014 and 2013, respectively, on settled contracts covering commodity production. These gains and losses were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2014 and 2013, respectively, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. | ||||||||||||||||
At September 30, 2014, the Partnership had the following commodity derivatives: | ||||||||||||||||
Natural Gas – Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | 15,038,200 | $ | 4.152 | $ | 804 | |||||||||||
2015 | 51,924,500 | $ | 4.239 | 12,192 | ||||||||||||
2016 | 45,746,300 | $ | 4.311 | 10,462 | ||||||||||||
2017 | 24,840,000 | $ | 4.532 | 7,552 | ||||||||||||
2018 | 9,360,000 | $ | 4.619 | 2,590 | ||||||||||||
$ | 33,600 | |||||||||||||||
Natural Gas – Costless Collars | ||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | ||||||||||||
Period Ending | and Cap | Asset/ | ||||||||||||||
December 31, | (Liability) | |||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | Puts purchased | 960,000 | $ | 4.221 | $ | 279 | ||||||||||
2014 | Calls sold | 960,000 | $ | 5.12 | (23 | ) | ||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 1,948 | |||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (452 | ) | ||||||||||
$ | 1,752 | |||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | ||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | Puts purchased | 450,000 | $ | 3.8 | $ | 17 | ||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | 550 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 738 | |||||||||||
$ | 1,305 | |||||||||||||||
Natural Gas – WAHA Basis Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset/(Liability) | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(8) | ||||||||||||||
2014 | 2,700,000 | $ | (0.110 | ) | $ | 3 | ||||||||||
2015 | 3,000,000 | $ | (0.068 | ) | (31 | ) | ||||||||||
$ | (28 | ) | ||||||||||||||
Natural Gas – NGPL Basis Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(9) | ||||||||||||||
2014 | 2,250,000 | $ | (0.108 | ) | $ | 1 | ||||||||||
$ | 1 | |||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(10) | ||||||||||||||
2014 | 1,386,000 | $ | 2.123 | $ | 238 | |||||||||||
2015 | 5,040,000 | $ | 1.983 | 570 | ||||||||||||
$ | 808 | |||||||||||||||
Natural Gas Liquids – Ethane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | ||||||||||||||
2014 | 630,000 | $ | 0.303 | $ | 37 | |||||||||||
$ | 37 | |||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | ||||||||||||||
2014 | 3,087,000 | $ | 1 | $ | (144 | ) | ||||||||||
2015 | 8,064,000 | $ | 1.016 | (76 | ) | |||||||||||
$ | (220 | ) | ||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | ||||||||||||||
2014 | 378,000 | $ | 1.308 | $ | 34 | |||||||||||
2015 | 1,512,000 | $ | 1.248 | 98 | ||||||||||||
$ | 132 | |||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(7) | ||||||||||||||
2014 | 378,000 | $ | 1.323 | $ | 32 | |||||||||||
2015 | 1,512,000 | $ | 1.263 | 91 | ||||||||||||
$ | 123 | |||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||
December 31, | ||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | (24 | ) | ||||||||||
2017 | 60,000 | $ | 83.78 | (58 | ) | |||||||||||
$ | (82 | ) | ||||||||||||||
Crude Oil – Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2014 | 439,500 | $ | 95.09 | $ | 2,144 | |||||||||||
2015 | 1,743,000 | $ | 90.645 | 4,977 | ||||||||||||
2016 | 1,029,000 | $ | 88.65 | 2,731 | ||||||||||||
2017 | 492,000 | $ | 87.752 | 1,409 | ||||||||||||
2018 | 360,000 | $ | 88.283 | 1,302 | ||||||||||||
$ | 12,563 | |||||||||||||||
Crude Oil – Costless Collars | ||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||
Period Ending | Floor | Asset/ | ||||||||||||||
December 31, | and Cap | (Liability) | ||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2014 | Puts purchased | 10,290 | $ | 84.169 | $ | 15 | ||||||||||
2014 | Calls sold | 10,290 | $ | 113.308 | (1 | ) | ||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 110 | |||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (31 | ) | ||||||||||
$ | 93 | |||||||||||||||
Total net assets | $ | 50,084 | ||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | |||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | |||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | |||||||||||||||
(4) | Fair value based on forward Mt. Belvieu ethane prices, as applicable. | |||||||||||||||
-5 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | |||||||||||||||
-6 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | |||||||||||||||
(7) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable | |||||||||||||||
(8) | Fair value based on forward WAHA natural gas prices, as applicable | |||||||||||||||
(9) | Fair value based on forward NGPL natural gas prices, as applicable | |||||||||||||||
(10) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable | |||||||||||||||
At September 30, 2014, the Partnership had net cash proceeds of $0.8 million related to hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. The Partnership will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. | ||||||||||||||||
In June 2012, the Partnership entered into natural gas put option contracts, which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At September 30, 2014, net unrealized derivative assets of $1.3 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. | ||||||||||||||||
At September 30, 2014, the Partnership had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 7), the Partnership is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. The Partnership, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. |
Fair_Value_of_Financial_Instru
Fair Value of Financial Instruments | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||
Fair Value of Financial Instruments | ' | ||||||||||||||||
NOTE 9 – FAIR VALUE OF FINANCIAL INSTRUMENTS | |||||||||||||||||
Management has established a hierarchy to measure the Partnership’s financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: | |||||||||||||||||
Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. | |||||||||||||||||
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. | |||||||||||||||||
Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. | |||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||
The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 8). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices’ quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. | |||||||||||||||||
Information for assets and liabilities measured at fair value at September 30, 2014 and December 31, 2013 was as follows (in thousands): | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of September 30, 2014 | |||||||||||||||||
Derivative assets, gross | |||||||||||||||||
Commodity swaps | $ | — | $ | 51,734 | $ | — | $ | 51,734 | |||||||||
Commodity basis swaps | — | 163 | — | 163 | |||||||||||||
Commodity puts | — | 1,305 | — | 1,305 | |||||||||||||
Commodity options | — | 2,352 | — | 2,352 | |||||||||||||
Total derivative assets, gross | — | 55,554 | — | 55,554 | |||||||||||||
Derivative liabilities, gross | |||||||||||||||||
Commodity swaps | — | (4,773 | ) | — | (4,773 | ) | |||||||||||
Commodity basis swaps | — | (190 | ) | — | (190 | ) | |||||||||||
Commodity options | — | (507 | ) | — | (507 | ) | |||||||||||
Total derivative liabilities, gross | — | (5,470 | ) | — | (5,470 | ) | |||||||||||
Total derivatives, fair value, net | $ | — | $ | 50,084 | $ | — | $ | 50,084 | |||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of December 31, 2013 | |||||||||||||||||
Derivative assets, gross | |||||||||||||||||
Commodity swaps | $ | — | $ | 33,594 | $ | — | $ | 33,594 | |||||||||
Commodity puts | — | 1,374 | — | 1,374 | |||||||||||||
Commodity options | — | 3,305 | — | 3,305 | |||||||||||||
Total derivative assets, gross | — | 38,273 | — | 38,273 | |||||||||||||
Derivative liabilities, gross | |||||||||||||||||
Commodity swaps | — | (14,624 | ) | — | (14,624 | ) | |||||||||||
Commodity options | — | (1,094 | ) | — | (1,094 | ) | |||||||||||
Total derivative liabilities, gross | — | (15,718 | ) | — | (15,718 | ) | |||||||||||
Total derivatives, fair value, net | $ | — | $ | 22,555 | $ | — | $ | 22,555 | |||||||||
Other Financial Instruments | |||||||||||||||||
The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments. | |||||||||||||||||
The Partnership’s other current assets and liabilities on its consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of the Partnership’s long-term debt at September 30, 2014 and December 31, 2013, which consists of its Senior Notes and outstanding borrowings under its revolving credit facility (see Note 7), were $1,297.8 million and $938.6 million, respectively, compared with the carrying amounts of $1,283.0 million and $942.3 million, respectively. At September 30, 2014 and December 31, 2013, the carrying values of outstanding borrowings under the Partnership’s revolving credit facility (see Note 7), which bears interest at variable interest rates, approximated its estimated fair value. The estimated fair values of the Partnership’s Senior Notes were based upon the market approach and calculated using yields of the Partnership as provided by financial institutions and thus were categorized as Level 3 values. | |||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis | |||||||||||||||||
Management estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates. | |||||||||||||||||
Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2014 and 2013 were as follows (in thousands): | |||||||||||||||||
Three Months Ended September 30, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 323 | $ | 323 | $ | 14,699 | $ | 14,699 | |||||||||
Total | $ | 323 | $ | 323 | $ | 14,699 | $ | 14,699 | |||||||||
Nine Months Ended September 30, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 8,178 | $ | 8,178 | $ | 15,943 | $ | 15,943 | |||||||||
Total | $ | 8,178 | $ | 8,178 | $ | 15,943 | $ | 15,943 | |||||||||
Management estimates the fair value of the Partnership’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2013, the Partnership recognized $38.0 million of impairment of long-lived assets which were defined as Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized during the three and nine months ended September 30, 2014 and 2013. | |||||||||||||||||
During the nine months ended September 30, 2014, the Partnership completed the Rangely Acquisition and the GeoMet acquisition (see Note 3). During the year ended December 31, 2013, the Partnership completed the acquisition of certain oil and gas assets from EP Energy (see Note 3). The fair value measurements of assets acquired and liabilities assumed for these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Rangely Acquisition and the GeoMet acquisition as of the respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of September 30, 2014, are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Partnership’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuations and are subject to change. | |||||||||||||||||
The fair value of the warrants associated with the Class C preferred units (see Note 12) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including a conversion price of $23.10, discount rate of 0.21% and estimated volatility rate of 35%. |
Certain_Relationships_and_Rela
Certain Relationships and Related Party Transactions | 9 Months Ended |
Sep. 30, 2014 | |
Related Party Transactions [Abstract] | ' |
Certain Relationships And Related Party Transactions | ' |
NOTE 10 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS | |
Relationship with Drilling Partnerships. The Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership is entitled to receive management fees, reimbursement for administrative costs incurred and to share in the Drilling Partnerships’ revenues and costs and expenses according to the respective partnership agreements. | |
Relationship with Atlas Pipeline Partners, L.P. The Partnership’s general partner, ATLS, also maintains a general partner ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States and gas gathering services in the Appalachian Basin in the northwest region of the United States. In the Chattanooga Shale, a portion of the natural gas produced by the Partnership is gathered and processed by APL. For each of the three month periods ended September 30, 2014 and 2013, $0.1 million of gathering fees were paid by the Partnership to APL. For each of the nine month periods ended September 30, 2014 and 2013, $0.2 million of gathering fees were paid by the Partnership to APL. |
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2014 | |
Commitments And Contingencies Disclosure [Abstract] | ' |
Commitments and Contingencies | ' |
NOTE 11 — COMMITMENTS AND CONTINGENCIES | |
General Commitments | |
The Partnership is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of September 30, 2014, the management of the Partnership believes that any such liability incurred would not be material. Also, the Partnership has agreed to subordinate a portion of its share of net partnership revenues from certain of the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% to 12% per year for the first five to eight years, in accordance with the terms of the partnership agreements. For the three months ended September 30, 2014 and 2013, $0.9 million and $2.2 million, respectively, and $4.7 million and $6.5 million for the nine months ended September 30, 2014 and 2013, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. | |
Certain of the Partnership’s executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances. | |
In connection with the EP Energy Acquisition (see Note 3), the Partnership acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of the Partnership’s firm transportation obligations as of September 30, 2014 were as follows: 2014 - $2.1 million; 2015 ‑ $8.6 million; 2016 ‑ $2.1 million; and 2017 to 2018 ‑ none. | |
As of September 30, 2014, the Partnership is committed to expend approximately $65.4 million, principally on drilling and completion expenditures. | |
Legal Proceedings | |
The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations. |
Issuances_of_Units
Issuances of Units | 9 Months Ended |
Sep. 30, 2014 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | ' |
Issuances of Units | ' |
NOTE 12 —ISSUANCES OF UNITS | |
In August 2014, the Partnership entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, the Partnership may sell from time to time through the Agents common units representing limited partner interests of the Partnership having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. The Partnership will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, the Partnership may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between the Partnership and such Agent. As of September 30, 2014, no units have been sold under this program. | |
In May 2014, in connection with the closing of the Rangely Acquisition (see Note 3), the Partnership issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.5 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014. | |
In March 2014, the Partnership issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.1 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014. | |
In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 3), the Partnership issued 3,749,986 of its newly created Class C convertible preferred units to ATLS, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, ATLS, as purchaser of the Class C preferred units, received 562,497 warrants to purchase the Partnership’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of common units of the Partnership at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016. | |
Upon issuance of the Class C preferred units and warrants on July 31, 2013, the Partnership entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. The Partnership agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. | |
In June 2013, in connection with entering the EP Energy Acquisition (see Note 3), the Partnership sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. The Partnership utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 7). | |
In May 2013, the Partnership entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, the Partnership could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, the Partnership issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions and other offering costs paid. The Partnership utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. The Partnership terminated the equity distribution agreement effective December 27, 2013. |
Cash_Distributions
Cash Distributions | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||||
Distributions Made To Members Or Limited Partners [Abstract] | ' | ||||||||||||||||||
Cash Distributions | ' | ||||||||||||||||||
NOTE 13 – CASH DISTRIBUTIONS | |||||||||||||||||||
In January 2014, the Partnership’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby it would distribute all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, the partnership paid quarterly cash distributions within 45 days from the end of each calendar quarter. If the Partnership’s common unit distributions in any quarter exceed specified target levels, ATLS will receive between 13% and 48% of such distributions in excess of the specified target levels. | |||||||||||||||||||
Distributions declared by the Partnership for the period from January 1, 2013 through September 30, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash | For | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Distribution | Quarter/Month | Distribution | Distribution | Distribution | Distribution | ||||||||||||||
Paid | Ended | per Common | to Common | To | to the General | ||||||||||||||
Limited | Limited | Preferred | Partner’s | ||||||||||||||||
Partner Unit | Partners | Limited | Class | ||||||||||||||||
Partners | A Units | ||||||||||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.51 | $ | 22,428 | $ | 1,957 | $ | 946 | ||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.54 | $ | 32,097 | $ | 2,072 | $ | 1,884 | ||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.56 | $ | 33,291 | $ | 4,248 | $ | 2,443 | ||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | ||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | ||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | ||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | ||||||||||
On October 29, 2014, the Partnership declared a monthly distribution of $0.1966 per common unit for the month of September 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2014 to holders of record as of November 10, 2014. |
Benefit_Plan
Benefit Plan | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | |||||||||||||||
Benefit Plan | ' | |||||||||||||||
NOTE 14 — BENEFIT PLAN | ||||||||||||||||
2012 Long-Term Incentive Plan | ||||||||||||||||
The Partnership’s 2012 Long-Term Incentive Plan (“2012 LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners (collectively, the “Participants”), who perform services for the Partnership. The 2012 LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “LTIP Committee”). Under the 2012 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 2,900,000 common limited partner units. At September 30, 2014, the Partnership had 2,258,110 phantom units, restricted units and restricted options outstanding under the 2012 LTIP with 148,663 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value. | ||||||||||||||||
In the case of awards held by eligible employees, following a “change in control”, as defined in the 2012 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2012 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. | ||||||||||||||||
In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, but subject to the terms of any award agreements and employment agreements to which the general partner (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason): | ||||||||||||||||
· | cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); | |||||||||||||||
· | accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; | |||||||||||||||
· | provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); | |||||||||||||||
· | terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and | |||||||||||||||
· | make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the LTIP Committee deems necessary or appropriate. | |||||||||||||||
Phantom Units | ||||||||||||||||
Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property. Phantom units are subject to terms and conditions determined by the LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the LTIP Committee may grant distribution equivalent rights (“DERs”), which are the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by the Partnership with respect to a common unit during the period that the underlying phantom unit is outstanding. Phantom units granted under the 2012 LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the 2012 LTIP at September 30, 2014, 314,775 units will vest within the following twelve months. All phantom units outstanding under the 2012 LTIP at September 30, 2014 include DERs. During both the three months ended September 30, 2014 and 2013, the Partnership paid $0.5 million with respect to the 2012 LTIP’s DERs. During both the nine months ended September 30, 2014 and 2013, the Partnership paid $1.5 million with respect to the 2012 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets. | ||||||||||||||||
The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated: | ||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Grant Date | Grant Date | |||||||||||||||
Fair Value | Fair Value | |||||||||||||||
Outstanding, beginning of period | 901,207 | $ | 23.29 | 845,932 | $ | 24.51 | ||||||||||
Granted | 9,400 | 19.85 | 37,191 | 21.86 | ||||||||||||
Vested and issued(1) | (115,797 | ) | 24.54 | (33,123 | ) | 24.72 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
Outstanding, end of period(2)(3) | 794,810 | $ | 23.07 | 850,000 | $ | 24.38 | ||||||||||
Vested and not yet issued(4) | 5,412 | $ | 25.25 | 7,749 | $ | 25.51 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,647 | $ | 2,045 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Grant Date | Grant Date | |||||||||||||||
Fair Value | Fair Value | |||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | ||||||||||
Granted | 236,423 | 20.28 | 128,981 | 22.07 | ||||||||||||
Vested and issued(1) | (262,671 | ) | 24.51 | (204,582 | ) | 24.7 | ||||||||||
Forfeited | (18,750 | ) | 23 | (22,875 | ) | 24.23 | ||||||||||
Outstanding, end of period(2)(3) | 794,810 | $ | 23.07 | 850,000 | $ | 24.38 | ||||||||||
Vested and not yet issued(4) | 5,412 | $ | 25.25 | 7,749 | $ | 25.51 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 4,968 | $ | 7,329 | ||||||||||||
-1 | The intrinsic value of phantom unit awards vested and issued during the three months ended September 30, 2014 and 2013 was $2.8 million and $0.8 million, respectively, and $5.7 million and $5.0 million during the nine months ended September 30, 2014 and 2013, respectively. | |||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2014 was $15.5 million. | |||||||||||||||
-3 | There was $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets representing 29,035 and 16,084 units for the periods ending September 30, 2014 and December 31, 2013, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.09 and $22.15 for the periods ending September 30, 2014 and December 31, 2013, respectively. There was approximately $40,000 recognized as liabilities on the Partnership’s consolidated balance sheet at September 30, 2013, representing 7,939 units due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $25.19 as of September 30, 2013. | |||||||||||||||
-4 | The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2014 and 2013 were $0.1 million and $0.2 million, respectively. | |||||||||||||||
At September 30, 2014, the Partnership had approximately $8.3 million in unrecognized compensation expense related to unvested phantom units outstanding under the 2012 LTIP based upon the fair value of the awards. | ||||||||||||||||
Unit Options | ||||||||||||||||
A unit option is the right to purchase a Partnership common unit in the future at a predetermined price (the exercise price). The exercise price of each option is determined by the LTIP Committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted. The LTIP Committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method by which the exercise price may be paid by the Participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the 2012 LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 362,888 unit options outstanding under the 2012 LTIP at September 30, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The following table sets forth the 2012 LTIP unit option activity for the periods indicated: | ||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Exercise | Exercise | |||||||||||||||
Price | Price | |||||||||||||||
Outstanding, beginning of period | 1,467,050 | $ | 24.66 | 1,494,750 | $ | 24.67 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised (1) | — | — | — | — | ||||||||||||
Forfeited | (3,750 | ) | 24.67 | (6,250 | ) | 24.67 | ||||||||||
Outstanding, end of period(2)(3) | 1,463,300 | $ | 24.66 | 1,488,500 | $ | 24.67 | ||||||||||
Options exercisable, end of period(4) | 732,025 | $ | 24.67 | 371,375 | $ | 24.67 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 342 | $ | 915 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Exercise | Exercise | |||||||||||||||
Price | Price | |||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | ||||||||||
Granted | — | — | 2,500 | 22.88 | ||||||||||||
Exercised (1) | — | — | — | — | ||||||||||||
Forfeited | (19,375 | ) | 24.48 | (29,500 | ) | 24.74 | ||||||||||
Outstanding, end of period(2)(3) | 1,463,300 | $ | 24.66 | 1,488,500 | $ | 24.67 | ||||||||||
Options exercisable, end of period(4) | 732,025 | $ | 24.67 | 371,375 | $ | 24.67 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,374 | $ | 2,880 | ||||||||||||
-1 | No options were exercised during the three and nine months ended September 30, 2014 and 2013, respectively. | |||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at September 30, 2014 was 7.6 years. | |||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at September 30, 2014. | |||||||||||||||
-4 | The weighted average remaining contractual lives for exercisable options at September 30, 2014 and 2013 were 7.6 years and 8.6 years, respectively. There were no aggregate intrinsic values of options exercisable at September 30, 2014 and 2013. | |||||||||||||||
At September 30, 2014, the Partnership had approximately $1.4 million in unrecognized compensation expense related to unvested unit options outstanding under the 2012 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Expected dividend yield | — | % | — | % | — | % | 6.7 | % | ||||||||
Expected unit price volatility | — | % | — | % | — | % | 35.8 | % | ||||||||
Risk-free interest rate | — | % | — | % | — | % | 1.1 | % | ||||||||
Expected term (in years) | — | — | — | 6.35 | ||||||||||||
Fair value of unit options granted | $ | — | $ | — | $ | — | $ | 3.63 | ||||||||
Operating_Segment_Information
Operating Segment Information | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Operating Segment Information | ' | |||||||||||||||
NOTE 15 – OPERATING SEGMENT INFORMATION | ||||||||||||||||
The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Gas and oil production: | ||||||||||||||||
Revenues | $ | 125,394 | $ | 80,332 | $ | 325,696 | $ | 173,490 | ||||||||
Operating costs and expenses | (49,922 | ) | (29,419 | ) | (128,477 | ) | (63,670 | ) | ||||||||
Depreciation, depletion and amortization expense | (60,103 | ) | (39,900 | ) | (163,663 | ) | (80,176 | ) | ||||||||
Segment income | $ | 15,369 | $ | 11,013 | $ | 33,556 | $ | 29,644 | ||||||||
Well construction and completion: | ||||||||||||||||
Revenues | $ | 61,204 | $ | 10,964 | $ | 126,917 | $ | 92,293 | ||||||||
Operating costs and expenses | (53,221 | ) | (9,534 | ) | (110,363 | ) | (80,255 | ) | ||||||||
Segment income | $ | 7,983 | $ | 1,430 | $ | 16,554 | $ | 12,038 | ||||||||
Other partnership management:(1) | ||||||||||||||||
Revenues | $ | 16,096 | $ | (211 | ) | $ | 42,143 | $ | 20,676 | |||||||
Operating costs and expenses | (5,831 | ) | (6,781 | ) | (19,425 | ) | (20,776 | ) | ||||||||
Depreciation, depletion and amortization expense | (2,749 | ) | (1,756 | ) | (7,427 | ) | (4,885 | ) | ||||||||
Segment income (loss) | $ | 7,516 | $ | (8,748 | ) | $ | 15,291 | $ | (4,985 | ) | ||||||
Reconciliation of segment income (loss) to net income (loss): | ||||||||||||||||
Segment income (loss): | ||||||||||||||||
Gas and oil production | $ | 15,369 | $ | 11,013 | $ | 33,556 | $ | 29,644 | ||||||||
Well construction and completion | 7,983 | 1,430 | 16,554 | 12,038 | ||||||||||||
Other partnership management | 7,516 | (8,748 | ) | 15,291 | (4,985 | ) | ||||||||||
Total segment income | 30,868 | 3,695 | 65,401 | 36,697 | ||||||||||||
General and administrative expenses(2) | (13,124 | ) | (31,983 | ) | (50,894 | ) | (63,767 | ) | ||||||||
Interest expense(2) | (16,577 | ) | (10,748 | ) | (43,028 | ) | (22,145 | ) | ||||||||
Loss on asset sales and disposal(2) | (92 | ) | (661 | ) | (1,686 | ) | (2,035 | ) | ||||||||
Net income (loss) | $ | 1,075 | $ | (39,697 | ) | $ | (30,207 | ) | $ | (51,250 | ) | |||||
Reconciliation of segment revenues to total revenues: | ||||||||||||||||
Segment revenues: | ||||||||||||||||
Gas and oil production | $ | 125,394 | $ | 80,332 | $ | 325,696 | $ | 173,490 | ||||||||
Well construction and completion | 61,204 | 10,964 | 126,917 | 92,293 | ||||||||||||
Other partnership management | 16,096 | (211 | ) | 42,143 | 20,676 | |||||||||||
Total revenues | $ | 202,694 | $ | 91,085 | $ | 494,756 | $ | 286,459 | ||||||||
Capital expenditures: | ||||||||||||||||
Gas and oil production | $ | 50,596 | $ | 64,094 | $ | 134,388 | $ | 186,529 | ||||||||
Other partnership management | 4,097 | 7,753 | 11,637 | 11,798 | ||||||||||||
Corporate and other | 1,237 | 2,097 | 4,460 | 5,669 | ||||||||||||
Total capital expenditures | $ | 55,930 | $ | 73,944 | $ | 150,485 | $ | 203,996 | ||||||||
September 30, | December 31, | |||||||||||||||
2014 | 2013 | |||||||||||||||
Balance sheet | ||||||||||||||||
Goodwill: | ||||||||||||||||
Gas and oil production | $ | 18,145 | $ | 18,145 | ||||||||||||
Well construction and completion | 6,389 | 6,389 | ||||||||||||||
Other partnership management | 7,250 | 7,250 | ||||||||||||||
$ | 31,784 | $ | 31,784 | |||||||||||||
Total assets: | ||||||||||||||||
Gas and oil production | $ | 2,783,035 | $ | 2,170,712 | ||||||||||||
Well construction and completion | 70,021 | 55,031 | ||||||||||||||
Other partnership management | 58,918 | 56,493 | ||||||||||||||
Corporate and other | 74,428 | 61,564 | ||||||||||||||
$ | 2,986,402 | $ | 2,343,800 | |||||||||||||
-1 | Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information. | |||||||||||||||
-2 | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Subsequent_Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2014 | |
Subsequent Events [Abstract] | ' |
Subsequent Events | ' |
NOTE 16 — SUBSEQUENT EVENTS | |
Eagle Ford Shale Asset Acquisition. On November 5, 2014, the Partnership and ATLS’s development subsidiary (the “Development Subsidiary”) completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas (the “Eagle Ford Acquisition”). Approximately $199.0 million was paid in cash by the Partnership and the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. The Partnership will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. The Partnership may pay up to $20.0 million of its deferred portion of the purchase price by issuing its Class D cumulative redeemable perpetual preferred units at a price of $25.00 per unit. | |
In connection with the closing of the Eagle Ford Acquisition, the borrowing base under the Partnership’s revolving credit facility was increased to $900.0 million. | |
Targa Resources Acquisition and ATLS Spin-Off. On October 13, 2014, ATLS entered into a definitive merger agreement with Targa Resources Corp. (“TRC”) (the “Merger Agreement”), pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly owned subsidiary of TRC with and into ATLS (the “Merger”). Concurrently with the ATLS Merger Agreement, ATLS, APL and Atlas Pipeline Partners GP, LLC entered into a definitive merger agreement with TRC, Targa Resources Partners LP (“TRP”), and certain other parties (the “APL Merger Agreement”), pursuant to which TRP agreed to acquire APL through a merger of a newly formed wholly owned subsidiary of TRP with and into APL (the “APL Merger”). Concurrent with the execution of the ATLS Merger Agreement and the APL Merger Agreement, ATLS agreed to (i) transfer its assets and liabilities, other than those related to APL, to the Partnership’s General Partner, which has changed its name to Atlas Energy Group, LLC (“Atlas Energy Group”), and (ii) immediately prior to the ATLS Merger, effect a pro rata distribution to the ATLS unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”). On November 5, 2014, Atlas Energy Group filed a registration statement on Form 10 in connection with the Spin-Off. | |
The closing of the ATLS Merger is subject to approval by holders of a majority of the ATLS’ common units, approval by a majority of the holders of TRC common stock voting at a special meeting held to approve the issuance of TRC shares in the Merger and other closing conditions, including the closing of the APL Merger and the Spin-Off. The closing of the APL Merger is subject to approval by APL’s unitholders and other closing conditions, including the completion of the ATLS Merger and the Spin-Off. Completion of the Spin-Off is also conditioned on the parties standing ready to complete the ATLS Merger. | |
Cash Distribution. On October 29, 2014, the Partnership declared a cash distribution of $0.1966 per common unit for the month of September 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2014 to holders of record as of November 10, 2014. | |
Issuance of Preferred Units. In connection with the Eagle Ford Acquisition, on October 2, 2014, the Partnership issued 3,200,000 8.625% Class D cumulative redeemable perpetual preferred units at a public offering price of $25.00 per Class D Unit. The Partnership will pay cumulative distributions in cash on the units on a quarterly basis at a rate of $2.15625 per unit, or 8.625% of the liquidation preference, per year. | |
9.25% Senior Notes. Also in connection with the Eagle Ford Acquisition, on October 14, 2014, the Partnership issued an additional $75.0 million of its 9.25% Senior Notes in a private transaction under Rule 144A and Regulation S of the Securities Act at an offering price of 100.5%, yielding net proceeds of approximately $73.6 million. In connection with the issuance, the Partnership also entered into a registration rights agreement. Under the registration rights agreement, the Partnership agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by no later than 270 days after the issuance of the 9.25% Senior Notes. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, the Partnership agreed to file a shelf registration statement with respect to the issuance. If the Partnership fails to comply with its obligations to register the notes within the specified time periods, the Partnership will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration is declared effective, as applicable. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Accounting Policies [Abstract] | ' | |||||||||||||||
Principles of Consolidation | ' | |||||||||||||||
Principles of Consolidation | ||||||||||||||||
The Partnership’s consolidated balance sheets at September 30, 2014 and December 31, 2013 and the consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. | ||||||||||||||||
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which the Partnership has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note. | ||||||||||||||||
Use of Estimates | ' | |||||||||||||||
Use of Estimates | ||||||||||||||||
The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates. | ||||||||||||||||
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”). | ||||||||||||||||
Receivables | ' | |||||||||||||||
Receivables | ||||||||||||||||
Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At September 30, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | ||||||||||||||||
Inventory | ' | |||||||||||||||
Inventory | ||||||||||||||||
The Partnership had $8.6 million and $4.6 million of inventory at September 30, 2014 and December 31, 2013, respectively, which was included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. | ||||||||||||||||
Property, Plant and Equipment | ' | |||||||||||||||
Property, Plant and Equipment | ||||||||||||||||
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. | ||||||||||||||||
The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet. | ||||||||||||||||
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators. | ||||||||||||||||
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. | ||||||||||||||||
Impairment of Long-Lived Assets | ' | |||||||||||||||
Impairment of Long-Lived Assets | ||||||||||||||||
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. | ||||||||||||||||
The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. | ||||||||||||||||
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Partnership’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Partnership’s actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. | ||||||||||||||||
The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. | ||||||||||||||||
The Partnership’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to the Partnership becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s limited partner agreement. In general, the Partnership will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon the Partnership’s determination of fair market value. | ||||||||||||||||
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, the Partnership recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on its consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by the Partnership for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, the Partnership recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. There were no impairments of proved gas and oil properties recorded by the Partnership for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013 and management’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. | ||||||||||||||||
Capitalized Interest | ' | |||||||||||||||
Capitalized Interest | ||||||||||||||||
The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds by the Partnership was 5.4% and 6.3% for the three months ended September 30, 2014 and 2013, respectively, and 5.7% and 6.1% for the nine months ended September 30, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $3.7 million and $3.6 million for the three months ended September 30, 2014 and 2013, respectively, and $9.4 million and $10.5 million for the nine months ended September 30, 2014 and 2013, respectively. | ||||||||||||||||
Intangible Assets | ' | |||||||||||||||
Intangible Assets | ||||||||||||||||
The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance method over their respective estimated useful lives. | ||||||||||||||||
The following table reflects the components of intangible assets being amortized at September 30, 2014 and December 31, 2013 (in thousands): | ||||||||||||||||
September 30, | December 31, | Estimated | ||||||||||||||
2014 | 2013 | Useful Lives | ||||||||||||||
In Years | ||||||||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | |||||||||||
Accumulated Amortization | (13,585 | ) | (13,381 | ) | ||||||||||||
Net Carrying Amount | $ | 759 | $ | 963 | ||||||||||||
Amortization expense on intangible assets was $0.1 million for both the three months ended September 30, 2014 and 2013, respectively, and $0.2 million and $0.3 million for the nine months ended September 30, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $0.3 million; 2015 - $0.2 million; 2016 - $0.1 million, 2017 - $0.1 million and 2018 - $0.1 million. | ||||||||||||||||
Goodwill | ' | |||||||||||||||
Goodwill | ||||||||||||||||
At September 30, 2014 and December 31, 2013, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The Partnership tests goodwill for impairment at each year end by comparing its reporting units’ estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the Partnership’s assets and the available market data of the industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Partnership’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. Management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and nine months ended September 30, 2014 and 2013, no impairment indicators arose, and no goodwill impairments were recognized by the Partnership. | ||||||||||||||||
Asset Retirement Obligations | ' | |||||||||||||||
Asset Retirement Obligations | ||||||||||||||||
The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization. | ||||||||||||||||
Income Taxes | ' | |||||||||||||||
Income Taxes | ||||||||||||||||
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated financial statements. | ||||||||||||||||
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to record interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three and nine months ended September 30, 2014 and 2013. | ||||||||||||||||
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2014. | ||||||||||||||||
Net Income (Loss) Per Common Unit | ' | |||||||||||||||
Net Income (Loss) Per Common Unit | ||||||||||||||||
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, income (loss) attributable to preferred limited partners and net income (loss) attributable to the General Partner’s Class A units. The General Partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the General Partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partner’s and limited partners’ ownership interests. | ||||||||||||||||
The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. | ||||||||||||||||
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. | ||||||||||||||||
The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income (loss) | $ | 1,075 | $ | (39,697 | ) | $ | (30,207 | ) | $ | (51,250 | ) | |||||
Preferred limited partner dividends | (4,475 | ) | (3,564 | ) | (13,298 | ) | (7,592 | ) | ||||||||
Net loss attributable to common limited partners and the general partner | (3,400 | ) | (43,261 | ) | (43,505 | ) | (58,842 | ) | ||||||||
Less: General partner’s interest | (2,993 | ) | (812 | ) | (7,374 | ) | (2,135 | ) | ||||||||
Net loss attributable to common limited partners | (6,393 | ) | (44,073 | ) | (50,879 | ) | (60,977 | ) | ||||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | — | ||||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (6,393 | ) | $ | (44,073 | ) | $ | (50,879 | ) | $ | (60,977 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 797,000 and 835,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the nine months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 780,000 and 918,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | |||||||||||||||
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 14). | ||||||||||||||||
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - basic | ||||||||||||||||
Add effect of dilutive | — | — | — | — | ||||||||||||
incentive awards(1) | ||||||||||||||||
Add effect of dilutive convertible | — | — | — | — | ||||||||||||
preferred limited partner units and | ||||||||||||||||
warrants(2) | ||||||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - diluted | ||||||||||||||||
(1) | For the three months ended September 30, 2014 and 2013, approximately 797,000 units and 835,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the nine months ended September 30, 2014 and 2013, approximately 780,000 units and 918,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
(2) | For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Revenue Recognition | ' | |||||||||||||||
Revenue Recognition | ||||||||||||||||
Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within its consolidated statements of operations. | ||||||||||||||||
The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. | ||||||||||||||||
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues of $83.2 million and $55.3 million at September 30, 2014 and December 31, 2013, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets. | ||||||||||||||||
Gathering and processing revenue includes gathering fees the Partnership charges to the Drilling Partnership wells for the Partnership’s processing plants in the New Albany Shale and the Chattanooga Shale. Generally, the Partnership charges a gathering fee to the Drilling Partnership wells equivalent to the fees the Partnership remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby the Partnership remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, the Partnership charges the Drilling Partnership wells a 13% gathering fee. As a result, some of the Partnership’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | ||||||||||||||||
Comprehensive Income (Loss) | ' | |||||||||||||||
Comprehensive Income (Loss) | ||||||||||||||||
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and at September 30, 2014, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). | ||||||||||||||||
Recently Adopted Accounting Standards | ' | |||||||||||||||
Recently Adopted Accounting Standards | ||||||||||||||||
In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application was permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
Recently Issued Accounting Standards | ' | |||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | ||||||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | ||||||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Accounting Policies [Abstract] | ' | |||||||||||||||
Schedule of the Components of Intangible Assets Being Amortized | ' | |||||||||||||||
The following table reflects the components of intangible assets being amortized at September 30, 2014 and December 31, 2013 (in thousands): | ||||||||||||||||
September 30, | December 31, | Estimated | ||||||||||||||
2014 | 2013 | Useful Lives | ||||||||||||||
In Years | ||||||||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | |||||||||||
Accumulated Amortization | (13,585 | ) | (13,381 | ) | ||||||||||||
Net Carrying Amount | $ | 759 | $ | 963 | ||||||||||||
Reconciliation of Net Loss | ' | |||||||||||||||
The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income (loss) | $ | 1,075 | $ | (39,697 | ) | $ | (30,207 | ) | $ | (51,250 | ) | |||||
Preferred limited partner dividends | (4,475 | ) | (3,564 | ) | (13,298 | ) | (7,592 | ) | ||||||||
Net loss attributable to common limited partners and the general partner | (3,400 | ) | (43,261 | ) | (43,505 | ) | (58,842 | ) | ||||||||
Less: General partner’s interest | (2,993 | ) | (812 | ) | (7,374 | ) | (2,135 | ) | ||||||||
Net loss attributable to common limited partners | (6,393 | ) | (44,073 | ) | (50,879 | ) | (60,977 | ) | ||||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | — | ||||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (6,393 | ) | $ | (44,073 | ) | $ | (50,879 | ) | $ | (60,977 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 797,000 and 835,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the nine months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 780,000 and 918,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | |||||||||||||||
Reconciliation of the Partnership's Weighted Average Number of Common Limited Partner Units | ' | |||||||||||||||
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - basic | ||||||||||||||||
Add effect of dilutive | — | — | — | — | ||||||||||||
incentive awards(1) | ||||||||||||||||
Add effect of dilutive convertible | — | — | — | — | ||||||||||||
preferred limited partner units and | ||||||||||||||||
warrants(2) | ||||||||||||||||
Weighted average number of common | 81,522 | 59,440 | 72,288 | 50,197 | ||||||||||||
limited partner units - diluted | ||||||||||||||||
(1) | For the three months ended September 30, 2014 and 2013, approximately 797,000 units and 835,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the nine months ended September 30, 2014 and 2013, approximately 780,000 units and 918,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
(2) | For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Acquisitions_Tables
Acquisitions (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Business Acquisition [Line Items] | ' | |||||||||||||||
Business Acquisition, Pro Forma Information | ' | |||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Total revenues and other | $ | 202,694 | $ | 127,652 | $ | 540,757 | $ | 445,018 | ||||||||
Net income (loss) | (3,400 | ) | (10,900 | ) | (12,617 | ) | 15,678 | |||||||||
Net income (loss) attributable to common limited partners | (6,393 | ) | (12,359 | ) | (20,609 | ) | 12,053 | |||||||||
Net income (loss) attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (0.08 | ) | $ | (0.15 | ) | $ | (0.26 | ) | $ | 0.15 | |||||
Diluted | $ | (0.08 | ) | $ | (0.15 | ) | $ | (0.26 | ) | $ | 0.15 | |||||
Rangely Acquisition | ' | |||||||||||||||
Business Acquisition [Line Items] | ' | |||||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | |||||||||||||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||||||||
Assets: | ||||||||||||||||
Prepaid expenses and other | $ | 4,041 | ||||||||||||||
Property, plant and equipment | 405,065 | |||||||||||||||
Other assets, net | 2,944 | |||||||||||||||
Total current assets | $ | 412,050 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accrued liabilities | 2,936 | |||||||||||||||
Asset retirement obligation | 1,305 | |||||||||||||||
Total liabilities assumed | 4,241 | |||||||||||||||
Net assets acquired | $ | 407,809 | ||||||||||||||
EP Energy Acquisition | ' | |||||||||||||||
Business Acquisition [Line Items] | ' | |||||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | |||||||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands): | ||||||||||||||||
Assets: | ||||||||||||||||
Prepaid expenses and other | $ | 5,268 | ||||||||||||||
Property, plant and equipment | 723,842 | |||||||||||||||
Total current assets | $ | 729,110 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accounts payable | 2,747 | |||||||||||||||
Asset retirement obligation | 16,728 | |||||||||||||||
Total liabilities assumed | 19,475 | |||||||||||||||
Net assets acquired | $ | 709,635 | ||||||||||||||
Property_Plant_and_Equipment_T
Property, Plant and Equipment (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2014 | ||||||||||||
Property Plant And Equipment [Abstract] | ' | |||||||||||
Property, Plant and Equipment | ' | |||||||||||
The following is a summary of property, plant and equipment at the dates indicated (in thousands): | ||||||||||||
September 30, | December 31, | Estimated | ||||||||||
2014 | 2013 | Useful Lives | ||||||||||
in Years | ||||||||||||
Natural gas and oil properties: | ||||||||||||
Proved properties: | ||||||||||||
Leasehold interests | $ | 401,509 | $ | 320,459 | ||||||||
Pre-development costs | 6,092 | 4,367 | ||||||||||
Wells and related equipment | 2,762,577 | 2,164,760 | ||||||||||
Total proved properties | 3,170,178 | 2,489,586 | ||||||||||
Unproved properties | 214,874 | 211,536 | ||||||||||
Support equipment | 34,692 | 23,005 | ||||||||||
Total natural gas and oil properties | 3,419,744 | 2,724,127 | ||||||||||
Pipelines, processing and compression facilities | 43,719 | 42,949 | 2 – 40 | |||||||||
Rights of way | 830 | 830 | 20 – 40 | |||||||||
Land, buildings and improvements | 9,072 | 9,462 | 3 – 40 | |||||||||
Other | 17,538 | 15,318 | 3 – 10 | |||||||||
3,490,903 | 2,792,686 | |||||||||||
Less – accumulated depreciation, depletion and amortization | (833,843 | ) | (671,868 | ) | ||||||||
$ | 2,657,060 | $ | 2,120,818 | |||||||||
Other_Assets_Tables
Other Assets (Tables) | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
Other Assets Noncurrent Disclosure [Abstract] | ' | |||||||
Schedule of Other Assets | ' | |||||||
The following is a summary of other assets at the dates indicated (in thousands): | ||||||||
September 30, | December 31, | |||||||
2014 | 2013 | |||||||
Deferred financing costs, net of accumulated amortization of $18,046 and $11,948 at September 30, 2014 and December 31, 2013, respectively | $ | 40,553 | $ | 35,292 | ||||
Notes receivable | 3,754 | 3,978 | ||||||
Long-term derivative asset receivable from Drilling Partnerships | 622 | 863 | ||||||
Other | 7,548 | 2,688 | ||||||
$ | 52,477 | $ | 42,821 | |||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | |||||||||||||||
Reconciliation of Liability for Well Plugging and Abandonment Costs | ' | |||||||||||||||
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Asset retirement obligations, beginning of period | $ | 100,002 | $ | 67,732 | $ | 89,776 | $ | 64,794 | ||||||||
Liabilities incurred | 323 | 14,699 | 8,178 | 15,943 | ||||||||||||
Liabilities settled | (270 | ) | (158 | ) | (688 | ) | (381 | ) | ||||||||
Accretion expense | 1,419 | 1,294 | 4,208 | 3,211 | ||||||||||||
Asset retirement obligations, end of period | $ | 101,474 | $ | 83,567 | $ | 101,474 | $ | 83,567 | ||||||||
Debt_Tables
Debt (Tables) | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
Debt Disclosure [Abstract] | ' | |||||||
Schedule of Long-term Debt Instruments | ' | |||||||
Total debt consists of the following at the dates indicated (in thousands): | ||||||||
September 30, | December 31, | |||||||
2014 | 2013 | |||||||
Revolving credit facility | $ | 660,000 | $ | 419,000 | ||||
7.75 % Senior Notes – due 2021 | 374,525 | 275,000 | ||||||
9.25 % Senior Notes – due 2021 | 248,497 | 248,334 | ||||||
Total debt | 1,283,022 | 942,334 | ||||||
Less current maturities | — | — | ||||||
Total long-term debt | $ | 1,283,022 | $ | 942,334 | ||||
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ' | |||||||||||||||
Summary of Gains or Losses Derivative Instruments Recognized in Statements of Operations | ' | |||||||||||||||
The following table summarizes the gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments for the periods indicated (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(Gain) loss reclassified from accumulated other comprehensive | ||||||||||||||||
income (loss): | ||||||||||||||||
Gas and oil production | $ | (1,304 | ) | $ | (1,145 | ) | $ | 21,924 | $ | (4,424 | ) | |||||
revenue | ||||||||||||||||
Total | $ | (1,304 | ) | $ | (1,145 | ) | $ | 21,924 | $ | (4,424 | ) | |||||
Fair Values of the Partnership's Derivative Instruments Table | ' | |||||||||||||||
The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands): | ||||||||||||||||
Offsetting Derivative Assets | Gross | Gross | Net Amount of | |||||||||||||
Amounts of | Amounts | Assets | ||||||||||||||
Recognized | Offset in the | Presented in the | ||||||||||||||
Assets | Consolidated | Consolidated | ||||||||||||||
Balance Sheets | Balance Sheets | |||||||||||||||
As of September 30, 2014 | ||||||||||||||||
Current portion of derivative assets | $ | 23,604 | $ | (2,554 | ) | $ | 21,050 | |||||||||
Long-term portion of derivative assets | 31,950 | (1,124 | ) | 30,826 | ||||||||||||
Total derivative assets | $ | 55,554 | $ | (3,678 | ) | $ | 51,876 | |||||||||
As of December 31, 2013 | ||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | |||||||||
Long-term portion of derivative assets | 31,146 | (4,062 | ) | 27,084 | ||||||||||||
Current portion of derivative liabilities | 4,341 | (4,341 | ) | — | ||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | ||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | |||||||||
Offsetting Derivative Liabilities | Gross | Gross | Net Amount of | |||||||||||||
Amounts of | Amounts | Liabilities | ||||||||||||||
Recognized | Offset in the | Presented in the | ||||||||||||||
Liabilities | Consolidated | Consolidated | ||||||||||||||
Balance Sheets | Balance Sheets | |||||||||||||||
As of September 30, 2014 | ||||||||||||||||
Current portion of derivative assets | $ | (2,554 | ) | $ | 2,554 | $ | — | |||||||||
Long-term portion of derivative assets | (1,124 | ) | 1,124 | — | ||||||||||||
Current portion of derivative liabilities | (1,792 | ) | (1,792 | ) | ||||||||||||
Total derivative liabilities | $ | (5,470 | ) | $ | 3,678 | $ | (1,792 | ) | ||||||||
As of December 31, 2013 | ||||||||||||||||
Current portion of derivative assets | $ | (773 | ) | $ | 773 | $ | — | |||||||||
Long-term portion of derivative assets | (4,062 | ) | 4,062 | — | ||||||||||||
Current portion of derivative liabilities | (10,694 | ) | 4,341 | (6,353 | ) | |||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | |||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | ||||||||
Commodity Derivative Instruments by Type Table | ' | |||||||||||||||
At September 30, 2014, the Partnership had the following commodity derivatives: | ||||||||||||||||
Natural Gas – Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | 15,038,200 | $ | 4.152 | $ | 804 | |||||||||||
2015 | 51,924,500 | $ | 4.239 | 12,192 | ||||||||||||
2016 | 45,746,300 | $ | 4.311 | 10,462 | ||||||||||||
2017 | 24,840,000 | $ | 4.532 | 7,552 | ||||||||||||
2018 | 9,360,000 | $ | 4.619 | 2,590 | ||||||||||||
$ | 33,600 | |||||||||||||||
Natural Gas – Costless Collars | ||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | ||||||||||||
Period Ending | and Cap | Asset/ | ||||||||||||||
December 31, | (Liability) | |||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | Puts purchased | 960,000 | $ | 4.221 | $ | 279 | ||||||||||
2014 | Calls sold | 960,000 | $ | 5.12 | (23 | ) | ||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 1,948 | |||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (452 | ) | ||||||||||
$ | 1,752 | |||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | ||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||
2014 | Puts purchased | 450,000 | $ | 3.8 | $ | 17 | ||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | 550 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 738 | |||||||||||
$ | 1,305 | |||||||||||||||
Natural Gas – WAHA Basis Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset/(Liability) | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(8) | ||||||||||||||
2014 | 2,700,000 | $ | (0.110 | ) | $ | 3 | ||||||||||
2015 | 3,000,000 | $ | (0.068 | ) | (31 | ) | ||||||||||
$ | (28 | ) | ||||||||||||||
Natural Gas – NGPL Basis Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(9) | ||||||||||||||
2014 | 2,250,000 | $ | (0.108 | ) | $ | 1 | ||||||||||
$ | 1 | |||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(10) | ||||||||||||||
2014 | 1,386,000 | $ | 2.123 | $ | 238 | |||||||||||
2015 | 5,040,000 | $ | 1.983 | 570 | ||||||||||||
$ | 808 | |||||||||||||||
Natural Gas Liquids – Ethane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | ||||||||||||||
2014 | 630,000 | $ | 0.303 | $ | 37 | |||||||||||
$ | 37 | |||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | ||||||||||||||
2014 | 3,087,000 | $ | 1 | $ | (144 | ) | ||||||||||
2015 | 8,064,000 | $ | 1.016 | (76 | ) | |||||||||||
$ | (220 | ) | ||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | ||||||||||||||
2014 | 378,000 | $ | 1.308 | $ | 34 | |||||||||||
2015 | 1,512,000 | $ | 1.248 | 98 | ||||||||||||
$ | 132 | |||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(7) | ||||||||||||||
2014 | 378,000 | $ | 1.323 | $ | 32 | |||||||||||
2015 | 1,512,000 | $ | 1.263 | 91 | ||||||||||||
$ | 123 | |||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||
December 31, | ||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | (24 | ) | ||||||||||
2017 | 60,000 | $ | 83.78 | (58 | ) | |||||||||||
$ | (82 | ) | ||||||||||||||
Crude Oil – Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||
December 31, | ||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2014 | 439,500 | $ | 95.09 | $ | 2,144 | |||||||||||
2015 | 1,743,000 | $ | 90.645 | 4,977 | ||||||||||||
2016 | 1,029,000 | $ | 88.65 | 2,731 | ||||||||||||
2017 | 492,000 | $ | 87.752 | 1,409 | ||||||||||||
2018 | 360,000 | $ | 88.283 | 1,302 | ||||||||||||
$ | 12,563 | |||||||||||||||
Crude Oil – Costless Collars | ||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||
Period Ending | Floor | Asset/ | ||||||||||||||
December 31, | and Cap | (Liability) | ||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2014 | Puts purchased | 10,290 | $ | 84.169 | $ | 15 | ||||||||||
2014 | Calls sold | 10,290 | $ | 113.308 | (1 | ) | ||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 110 | |||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (31 | ) | ||||||||||
$ | 93 | |||||||||||||||
Total net assets | $ | 50,084 | ||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | |||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | |||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | |||||||||||||||
(4) | Fair value based on forward Mt. Belvieu ethane prices, as applicable. | |||||||||||||||
-5 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | |||||||||||||||
-6 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | |||||||||||||||
(7) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable | |||||||||||||||
(8) | Fair value based on forward WAHA natural gas prices, as applicable | |||||||||||||||
(9) | Fair value based on forward NGPL natural gas prices, as applicable | |||||||||||||||
(10) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable |
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||
Schedule of Assets/Liabilities at Fair Value | ' | ||||||||||||||||
Information for assets and liabilities measured at fair value at September 30, 2014 and December 31, 2013 was as follows (in thousands): | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of September 30, 2014 | |||||||||||||||||
Derivative assets, gross | |||||||||||||||||
Commodity swaps | $ | — | $ | 51,734 | $ | — | $ | 51,734 | |||||||||
Commodity basis swaps | — | 163 | — | 163 | |||||||||||||
Commodity puts | — | 1,305 | — | 1,305 | |||||||||||||
Commodity options | — | 2,352 | — | 2,352 | |||||||||||||
Total derivative assets, gross | — | 55,554 | — | 55,554 | |||||||||||||
Derivative liabilities, gross | |||||||||||||||||
Commodity swaps | — | (4,773 | ) | — | (4,773 | ) | |||||||||||
Commodity basis swaps | — | (190 | ) | — | (190 | ) | |||||||||||
Commodity options | — | (507 | ) | — | (507 | ) | |||||||||||
Total derivative liabilities, gross | — | (5,470 | ) | — | (5,470 | ) | |||||||||||
Total derivatives, fair value, net | $ | — | $ | 50,084 | $ | — | $ | 50,084 | |||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of December 31, 2013 | |||||||||||||||||
Derivative assets, gross | |||||||||||||||||
Commodity swaps | $ | — | $ | 33,594 | $ | — | $ | 33,594 | |||||||||
Commodity puts | — | 1,374 | — | 1,374 | |||||||||||||
Commodity options | — | 3,305 | — | 3,305 | |||||||||||||
Total derivative assets, gross | — | 38,273 | — | 38,273 | |||||||||||||
Derivative liabilities, gross | |||||||||||||||||
Commodity swaps | — | (14,624 | ) | — | (14,624 | ) | |||||||||||
Commodity options | — | (1,094 | ) | — | (1,094 | ) | |||||||||||
Total derivative liabilities, gross | — | (15,718 | ) | — | (15,718 | ) | |||||||||||
Total derivatives, fair value, net | $ | — | $ | 22,555 | $ | — | $ | 22,555 | |||||||||
Schedule of Assets and Liabilities Measured on Non Recurring Basis | ' | ||||||||||||||||
Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2014 and 2013 were as follows (in thousands): | |||||||||||||||||
Three Months Ended September 30, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 323 | $ | 323 | $ | 14,699 | $ | 14,699 | |||||||||
Total | $ | 323 | $ | 323 | $ | 14,699 | $ | 14,699 | |||||||||
Nine Months Ended September 30, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 8,178 | $ | 8,178 | $ | 15,943 | $ | 15,943 | |||||||||
Total | $ | 8,178 | $ | 8,178 | $ | 15,943 | $ | 15,943 | |||||||||
Cash_Distribution_Distribution
Cash Distribution (Distributions Declared) (Tables) (General Partner and Preferred Partner) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||||
General Partner and Preferred Partner | ' | ||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ' | ||||||||||||||||||
Schedule of Distributions Declared by Partnership | ' | ||||||||||||||||||
Distributions declared by the Partnership for the period from January 1, 2013 through September 30, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash | For | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Distribution | Quarter/Month | Distribution | Distribution | Distribution | Distribution | ||||||||||||||
Paid | Ended | per Common | to Common | To | to the General | ||||||||||||||
Limited | Limited | Preferred | Partner’s | ||||||||||||||||
Partner Unit | Partners | Limited | Class | ||||||||||||||||
Partners | A Units | ||||||||||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.51 | $ | 22,428 | $ | 1,957 | $ | 946 | ||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.54 | $ | 32,097 | $ | 2,072 | $ | 1,884 | ||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.56 | $ | 33,291 | $ | 4,248 | $ | 2,443 | ||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | ||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | ||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | ||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | ||||||||||
Benefit_Plan_Tables
Benefit Plan (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | |||||||||||||||
Phantom Unit Activity | ' | |||||||||||||||
The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated: | ||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Grant Date | Grant Date | |||||||||||||||
Fair Value | Fair Value | |||||||||||||||
Outstanding, beginning of period | 901,207 | $ | 23.29 | 845,932 | $ | 24.51 | ||||||||||
Granted | 9,400 | 19.85 | 37,191 | 21.86 | ||||||||||||
Vested and issued(1) | (115,797 | ) | 24.54 | (33,123 | ) | 24.72 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
Outstanding, end of period(2)(3) | 794,810 | $ | 23.07 | 850,000 | $ | 24.38 | ||||||||||
Vested and not yet issued(4) | 5,412 | $ | 25.25 | 7,749 | $ | 25.51 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,647 | $ | 2,045 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Grant Date | Grant Date | |||||||||||||||
Fair Value | Fair Value | |||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | ||||||||||
Granted | 236,423 | 20.28 | 128,981 | 22.07 | ||||||||||||
Vested and issued(1) | (262,671 | ) | 24.51 | (204,582 | ) | 24.7 | ||||||||||
Forfeited | (18,750 | ) | 23 | (22,875 | ) | 24.23 | ||||||||||
Outstanding, end of period(2)(3) | 794,810 | $ | 23.07 | 850,000 | $ | 24.38 | ||||||||||
Vested and not yet issued(4) | 5,412 | $ | 25.25 | 7,749 | $ | 25.51 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 4,968 | $ | 7,329 | ||||||||||||
-1 | The intrinsic value of phantom unit awards vested and issued during the three months ended September 30, 2014 and 2013 was $2.8 million and $0.8 million, respectively, and $5.7 million and $5.0 million during the nine months ended September 30, 2014 and 2013, respectively. | |||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2014 was $15.5 million. | |||||||||||||||
-3 | There was $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets representing 29,035 and 16,084 units for the periods ending September 30, 2014 and December 31, 2013, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.09 and $22.15 for the periods ending September 30, 2014 and December 31, 2013, respectively. There was approximately $40,000 recognized as liabilities on the Partnership’s consolidated balance sheet at September 30, 2013, representing 7,939 units due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $25.19 as of September 30, 2013. | |||||||||||||||
-4 | The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2014 and 2013 were $0.1 million and $0.2 million, respectively. | |||||||||||||||
Unit Option Activity | ' | |||||||||||||||
The following table sets forth the 2012 LTIP unit option activity for the periods indicated: | ||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Exercise | Exercise | |||||||||||||||
Price | Price | |||||||||||||||
Outstanding, beginning of period | 1,467,050 | $ | 24.66 | 1,494,750 | $ | 24.67 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised (1) | — | — | — | — | ||||||||||||
Forfeited | (3,750 | ) | 24.67 | (6,250 | ) | 24.67 | ||||||||||
Outstanding, end of period(2)(3) | 1,463,300 | $ | 24.66 | 1,488,500 | $ | 24.67 | ||||||||||
Options exercisable, end of period(4) | 732,025 | $ | 24.67 | 371,375 | $ | 24.67 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 342 | $ | 915 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Number | Weighted | Number | Weighted | |||||||||||||
of Units | Average | of Units | Average | |||||||||||||
Exercise | Exercise | |||||||||||||||
Price | Price | |||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | ||||||||||
Granted | — | — | 2,500 | 22.88 | ||||||||||||
Exercised (1) | — | — | — | — | ||||||||||||
Forfeited | (19,375 | ) | 24.48 | (29,500 | ) | 24.74 | ||||||||||
Outstanding, end of period(2)(3) | 1,463,300 | $ | 24.66 | 1,488,500 | $ | 24.67 | ||||||||||
Options exercisable, end of period(4) | 732,025 | $ | 24.67 | 371,375 | $ | 24.67 | ||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,374 | $ | 2,880 | ||||||||||||
-1 | No options were exercised during the three and nine months ended September 30, 2014 and 2013, respectively. | |||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at September 30, 2014 was 7.6 years. | |||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at September 30, 2014. | |||||||||||||||
-4 | The weighted average remaining contractual lives for exercisable options at September 30, 2014 and 2013 were 7.6 years and 8.6 years, respectively. There were no aggregate intrinsic values of options exercisable at September 30, 2014 and 2013. | |||||||||||||||
Weighted Average Assumptions | ' | |||||||||||||||
The following weighted average assumptions were used for the periods indicated: | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Expected dividend yield | — | % | — | % | — | % | 6.7 | % | ||||||||
Expected unit price volatility | — | % | — | % | — | % | 35.8 | % | ||||||||
Risk-free interest rate | — | % | — | % | — | % | 1.1 | % | ||||||||
Expected term (in years) | — | — | — | 6.35 | ||||||||||||
Fair value of unit options granted | $ | — | $ | — | $ | — | $ | 3.63 | ||||||||
Operating_Segment_Information_
Operating Segment Information (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Operating Segment Data | ' | |||||||||||||||
The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Gas and oil production: | ||||||||||||||||
Revenues | $ | 125,394 | $ | 80,332 | $ | 325,696 | $ | 173,490 | ||||||||
Operating costs and expenses | (49,922 | ) | (29,419 | ) | (128,477 | ) | (63,670 | ) | ||||||||
Depreciation, depletion and amortization expense | (60,103 | ) | (39,900 | ) | (163,663 | ) | (80,176 | ) | ||||||||
Segment income | $ | 15,369 | $ | 11,013 | $ | 33,556 | $ | 29,644 | ||||||||
Well construction and completion: | ||||||||||||||||
Revenues | $ | 61,204 | $ | 10,964 | $ | 126,917 | $ | 92,293 | ||||||||
Operating costs and expenses | (53,221 | ) | (9,534 | ) | (110,363 | ) | (80,255 | ) | ||||||||
Segment income | $ | 7,983 | $ | 1,430 | $ | 16,554 | $ | 12,038 | ||||||||
Other partnership management:(1) | ||||||||||||||||
Revenues | $ | 16,096 | $ | (211 | ) | $ | 42,143 | $ | 20,676 | |||||||
Operating costs and expenses | (5,831 | ) | (6,781 | ) | (19,425 | ) | (20,776 | ) | ||||||||
Depreciation, depletion and amortization expense | (2,749 | ) | (1,756 | ) | (7,427 | ) | (4,885 | ) | ||||||||
Segment income (loss) | $ | 7,516 | $ | (8,748 | ) | $ | 15,291 | $ | (4,985 | ) | ||||||
Reconciliation of segment income (loss) to net income (loss): | ||||||||||||||||
Segment income (loss): | ||||||||||||||||
Gas and oil production | $ | 15,369 | $ | 11,013 | $ | 33,556 | $ | 29,644 | ||||||||
Well construction and completion | 7,983 | 1,430 | 16,554 | 12,038 | ||||||||||||
Other partnership management | 7,516 | (8,748 | ) | 15,291 | (4,985 | ) | ||||||||||
Total segment income | 30,868 | 3,695 | 65,401 | 36,697 | ||||||||||||
General and administrative expenses(2) | (13,124 | ) | (31,983 | ) | (50,894 | ) | (63,767 | ) | ||||||||
Interest expense(2) | (16,577 | ) | (10,748 | ) | (43,028 | ) | (22,145 | ) | ||||||||
Loss on asset sales and disposal(2) | (92 | ) | (661 | ) | (1,686 | ) | (2,035 | ) | ||||||||
Net income (loss) | $ | 1,075 | $ | (39,697 | ) | $ | (30,207 | ) | $ | (51,250 | ) | |||||
Reconciliation of segment revenues to total revenues: | ||||||||||||||||
Segment revenues: | ||||||||||||||||
Gas and oil production | $ | 125,394 | $ | 80,332 | $ | 325,696 | $ | 173,490 | ||||||||
Well construction and completion | 61,204 | 10,964 | 126,917 | 92,293 | ||||||||||||
Other partnership management | 16,096 | (211 | ) | 42,143 | 20,676 | |||||||||||
Total revenues | $ | 202,694 | $ | 91,085 | $ | 494,756 | $ | 286,459 | ||||||||
Capital expenditures: | ||||||||||||||||
Gas and oil production | $ | 50,596 | $ | 64,094 | $ | 134,388 | $ | 186,529 | ||||||||
Other partnership management | 4,097 | 7,753 | 11,637 | 11,798 | ||||||||||||
Corporate and other | 1,237 | 2,097 | 4,460 | 5,669 | ||||||||||||
Total capital expenditures | $ | 55,930 | $ | 73,944 | $ | 150,485 | $ | 203,996 | ||||||||
September 30, | December 31, | |||||||||||||||
2014 | 2013 | |||||||||||||||
Balance sheet | ||||||||||||||||
Goodwill: | ||||||||||||||||
Gas and oil production | $ | 18,145 | $ | 18,145 | ||||||||||||
Well construction and completion | 6,389 | 6,389 | ||||||||||||||
Other partnership management | 7,250 | 7,250 | ||||||||||||||
$ | 31,784 | $ | 31,784 | |||||||||||||
Total assets: | ||||||||||||||||
Gas and oil production | $ | 2,783,035 | $ | 2,170,712 | ||||||||||||
Well construction and completion | 70,021 | 55,031 | ||||||||||||||
Other partnership management | 58,918 | 56,493 | ||||||||||||||
Corporate and other | 74,428 | 61,564 | ||||||||||||||
$ | 2,986,402 | $ | 2,343,800 | |||||||||||||
-1 | Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information. | |||||||||||||||
-2 | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Basis_of_Presentation_Narrativ
Basis of Presentation (Narrative) (Details) | 1 Months Ended | 9 Months Ended |
Feb. 29, 2012 | Sep. 30, 2014 | |
Limited Partner Interest | ' | ' |
Basis Of Presentation [Line Items] | ' | ' |
Board Approval Date For Issuance of Common Units | ' | '2012-02 |
Distribution Made to Member or Limited Partner, Share Distribution | 5,240,000 | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | 13-Mar-12 |
Ratio Of ARP Limited Partner Units | 0.1021 | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | 28-Feb-12 |
Exploration And Production Assets Transferred | ' | 5-Mar-12 |
Atlas Energy, L.P. | ' | ' |
Basis Of Presentation [Line Items] | ' | ' |
General Partner interest in Atlas Resource Partners, L.P | ' | 100.00% |
Common limited partner interest in Atlas Resource Partners, L.P | ' | 27.70% |
Common limited partner interest in Atlas Resource Partners, L.P., Units | ' | 20,962,485 |
Atlas Energy, L.P. | Preferred Limited Partners' Interest | ' | ' |
Basis Of Presentation [Line Items] | ' | ' |
Common limited partner interest in Atlas Resource Partners, L.P., Units | ' | 3,749,986 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Pro-rata share in Drilling Partnerships | ' | ' | 30.00% | ' | ' |
Allowance for Doubtful Accounts Receivable | $0 | ' | $0 | ' | $0 |
Materials, supplies and other inventory | 8,600,000 | ' | 8,600,000 | ' | 4,600,000 |
Impairments of Unproved Gas And Oil Properties | 0 | 0 | 0 | 0 | 13,500,000 |
Impairments Of Proved Gas And Oil Properties | 0 | 0 | 0 | 0 | 24,500,000 |
Weighted Average Interest Rate Used To Capitalize Interest | 5.40% | 6.30% | 5.70% | 6.10% | ' |
Interest Costs Capitalized | 3,700,000 | 3,600,000 | 9,400,000 | 10,500,000 | ' |
Amortization of Intangible Assets | 100,000 | 100,000 | 200,000 | 300,000 | ' |
Future Amortization Expense, 2014 | 300,000 | ' | 300,000 | ' | ' |
Future Amortization Expense, 2015 | 200,000 | ' | 200,000 | ' | ' |
Future Amortization Expense, 2016 | 100,000 | ' | 100,000 | ' | ' |
Future Amortization Expense, 2017 | 100,000 | ' | 100,000 | ' | ' |
Future Amortization Expense, 2018 | 100,000 | ' | 100,000 | ' | ' |
Goodwill, net | 31,784,000 | ' | 31,784,000 | ' | 31,784,000 |
Goodwill, Period Increase (Decrease) | 0 | 0 | 0 | 0 | ' |
Goodwill, Impairment Loss | 0 | 0 | 0 | 0 | ' |
Entity Not Subject to Income Taxes, Policy | ' | ' | 'The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated financial statements. | ' | ' |
Deferred income tax expense (benefit) | ' | ' | 0 | 0 | ' |
Income Tax Examination, Penalties and Interest Expense | 0 | 0 | 0 | 0 | ' |
Income Tax Examination, Description | ' | ' | 'The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2014. | ' | ' |
Unbilled Contracts Receivable | $83,200,000 | ' | $83,200,000 | ' | $55,300,000 |
Gathering Fee Percentage | ' | ' | 16.00% | ' | ' |
Gathering Fee Percentage Net Margin | ' | ' | 3.00% | ' | ' |
Drilling Partnership wells | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Gathering Fee Percentage | ' | ' | 13.00% | ' | ' |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2014 | Dec. 31, 2013 |
Accounting Policies [Abstract] | ' | ' |
Gross Carrying Amount | $14,344 | $14,344 |
Accumulated Amortization | -13,585 | -13,381 |
Net Carrying Amount | $759 | $963 |
Estimated Useful Lives In Years | '13 years | ' |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, except Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Accounting Policies [Abstract] | ' | ' | ' | ' | ||||
Net income (loss) | $1,075 | ($39,697) | ($30,207) | ($51,250) | ||||
Preferred limited partner dividends | -4,475 | -3,564 | -13,298 | -7,592 | ||||
Net loss attributable to common limited partners and the general partner | -3,400 | -43,261 | -43,505 | -58,842 | ||||
Less: General partner’s interest | -2,993 | -812 | -7,374 | -2,135 | ||||
Net loss attributable to common limited partners | -6,393 | -44,073 | -50,879 | -60,977 | ||||
Less: Net income attributable to participating securities – phantom units | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] |
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | ($6,393) | ($44,073) | ($50,879) | ($60,977) | ||||
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 797,000 | 835,000 | 780,000 | 918,000 | ||||
[1] | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 797,000 and 835,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the nine months ended September 30, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 780,000 and 918,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Limited Partner Units) (Details) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |||||
Accounting Policies [Abstract] | ' | ' | ' | ' | ||||
Weighted average number of common limited partner units - basic | 81,522,000 | 59,440,000 | 72,288,000 | 50,197,000 | ||||
Add effect of dilutive incentive awards | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] |
Add effect of dilutive convertible preferred limited partner units and warrants | 0 | [2] | 0 | [2] | 0 | [2] | 0 | [2] |
Weighted average number of common limited partner units - diluted | 81,522,000 | 59,440,000 | 72,288,000 | 50,197,000 | ||||
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 797,000 | 835,000 | 780,000 | 918,000 | ||||
[1] | For the three months ended September 30, 2014 and 2013, approximately 797,000 units and 835,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the nine months ended September 30, 2014 and 2013, approximately 780,000 units and 918,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | |||||||
[2] | For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2014 and 2013, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Acquisitions_Rangely_Acquisiti
Acquisitions (Rangely Acquisition) (Narrative) (Details) (USD $) | 3 Months Ended | 1 Months Ended | ||||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Sep. 30, 2014 | Jan. 23, 2013 | Jun. 30, 2014 | 31-May-14 | Jun. 30, 2014 |
7.75% Senior Notes | 7.75% Senior Notes | Rangely Acquisition | Rangely Acquisition | Rangely Acquisition | ||
7.75% Senior Notes | ||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' |
Business Acquisition, Percentage of Voting Interests Acquired | ' | ' | ' | 25.00% | ' | ' |
Business Acquisition, Cost of Acquired Entity, Cash Paid | ' | ' | ' | $407.80 | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | 7.75% | 7.75% | ' | ' | 7.75% |
Proceed from additional senior notes | ' | ' | ' | ' | ' | 100 |
Partners' Capital Account, Units, Sale of Units | 6,325,000 | ' | ' | 15,525,000 | 15,525,000 | ' |
Business Acquisition, Purchase Price Allocation, Methodology | ' | ' | ' | 'The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). | ' | ' |
Business Acquisition, Purchase Price Allocation, Status | ' | ' | ' | 'In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $11.6 million of transaction fees, which were included with common limited partners’ interests for the nine months ended September 30, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date. | ' | ' |
Business Acquisition, Cost of Acquired Entity, Transaction Costs | ' | ' | ' | $11.60 | ' | ' |
Acquisitions_Rangely_Acquisiti1
Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Rangely Acquisition, USD $) | Jun. 30, 2014 |
In Thousands, unless otherwise specified | |
Rangely Acquisition | ' |
Business Acquisition [Line Items] | ' |
Prepaid expenses and other | $4,041 |
Property, plant and equipment | 405,065 |
Other assets, net | 2,944 |
Total current assets | 412,050 |
Accrued liabilities | 2,936 |
Asset retirement obligation | 1,305 |
Total liabilities assumed | 4,241 |
Net assets acquired | $407,809 |
Acquisitions_EP_Energy_Acquisi
Acquisitions (EP Energy Acquisition) (Narrative) (Details) (USD $) | 3 Months Ended | 1 Months Ended | 1 Months Ended | 1 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Jun. 30, 2014 | Jul. 31, 2013 | Dec. 31, 2013 | Jul. 31, 2013 | Sep. 30, 2014 | Jul. 31, 2013 |
EP Energy Acquisition | EP Energy Acquisition | EP Energy Acquisition | Atlas Parent Company "ATLS" | 9.25% Senior Notes | 9.25% Senior Notes | ||
EP Energy Acquisition | EP Energy Acquisition | ||||||
Class C Convertible Preferred Units | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Cost of Acquired Entity, Cash Paid | ' | ' | $709.60 | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | 9.25% | 9.25% |
Debt Instrument, Maturity Date | ' | ' | ' | ' | ' | ' | 15-Aug-21 |
Business Acquisition, Effective Date of Acquisition | ' | ' | 1-May-13 | ' | ' | ' | ' |
Partners' Capital Account, Units, Sale of Units | 6,325,000 | 14,950,000 | 14,950,000 | ' | 3,749,986 | ' | ' |
Business Acquisition, Purchase Price Allocation, Methodology | ' | ' | 'The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). | ' | ' | ' | ' |
Business Acquisition, Cost of Acquired Entity, Transaction Costs | ' | ' | ' | $12.10 | ' | ' | ' |
Business Acquisition, Purchase Price Allocation, Status | ' | ' | 'All other costs associated with the acquisition of assets were expensed as incurred. | ' | ' | ' | ' |
Acquisitions_EP_Energy_Acquisi1
Acquisitions (EP Energy Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (EP Energy Acquisition, USD $) | Jul. 31, 2013 |
In Thousands, unless otherwise specified | |
EP Energy Acquisition | ' |
Business Acquisition [Line Items] | ' |
Prepaid expenses and other | $5,268 |
Property, plant and equipment | 723,842 |
Total current assets | 729,110 |
Accounts payable | 2,747 |
Asset retirement obligation | 16,728 |
Total liabilities assumed | 19,475 |
Net assets acquired | $709,635 |
Acquisitions_Pro_Forma_Financi
Acquisitions (Pro Forma Financial Information) (Narrative) (Details) | 9 Months Ended |
Sep. 30, 2014 | |
Business Combinations [Abstract] | ' |
Business Acquisition, Pro Forma Information, Description | 'The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Rangely and EP Energy acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred units had occurred on January 1, 2013. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods |
Acquisitions_Pro_Forma_Financi1
Acquisitions (Pro Forma Financial Information) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Business Combinations [Abstract] | ' | ' | ' | ' |
Total revenues and other | $202,694 | $127,652 | $540,757 | $445,018 |
Net income (loss) | -3,400 | -10,900 | -12,617 | 15,678 |
Net income (loss) attributable to common limited partners | ($6,393) | ($12,359) | ($20,609) | $12,053 |
Basic | ($0.08) | ($0.15) | ($0.26) | $0.15 |
Diluted | ($0.08) | ($0.15) | ($0.26) | $0.15 |
Acquisitions_Other_Acquisition
Acquisitions (Other Acquisition) (Narrative) (Details) (USD $) | 1 Months Ended | |
In Millions, unless otherwise specified | 12-May-14 | Sep. 20, 2013 |
GeoMet Acquisition | Norwood Natural Resources | |
Business Acquisition [Line Items] | ' | ' |
Cash Consideration | $99.30 | $5.40 |
Business Acquisition, Effective Date of Acquisition | 1-Jan-14 | 1-Jun-13 |
Business Acquisition, Description of Acquired Entity | 'The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia | 'The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale |
Property_Plant_and_Equipment_S
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property Plant And Equipment [Abstract] | ' | ' |
Proved properties: Leasehold interests | $401,509 | $320,459 |
Proved Properties: Pre-development costs | 6,092 | 4,367 |
Proved Properties: Wells and related equipment | 2,762,577 | 2,164,760 |
Total proved properties | 3,170,178 | 2,489,586 |
Unproved properties | 214,874 | 211,536 |
Support equipment | 34,692 | 23,005 |
Total natural gas and oil properties | 3,419,744 | 2,724,127 |
Pipelines, processing and compression facilities | 43,719 | 42,949 |
Rights of way | 830 | 830 |
Land, buildings and improvements | 9,072 | 9,462 |
Other | 17,538 | 15,318 |
Total gross property, plant and equipment | 3,490,903 | 2,792,686 |
Less – accumulated depreciation, depletion and amortization | -833,843 | -671,868 |
Property, plant and equipment, Net, Total | $2,657,060 | $2,120,818 |
Property_Plant_and_Equipment_U
Property, Plant and Equipment (Useful Life Narrative) (Details) | 9 Months Ended |
Sep. 30, 2014 | |
Pipelines, processing and compression facilities | Minimum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '2 years |
Pipelines, processing and compression facilities | Maximum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '40 years |
Rights of way | Minimum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '20 years |
Rights of way | Maximum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '40 years |
Land, buildings and improvements | Minimum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '3 years |
Land, buildings and improvements | Maximum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '40 years |
Other | Minimum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '3 years |
Other | Maximum | ' |
Property Plant And Equipment [Line Items] | ' |
Property, Plant and Equipment, Useful Life | '10 years |
Property_Plant_and_Equipment_N
Property, Plant and Equipment (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |||||
Property Plant And Equipment [Abstract] | ' | ' | ' | ' | ' | ||||
Non-cash property plant and equipment additions | ' | ' | $42,800,000 | $23,800,000 | ' | ||||
Gain (loss) on asset sales | -92,000 | [1] | -661,000 | [1] | -1,686,000 | [1] | -2,035,000 | [1] | ' |
Long-lived asset impairment | $0 | $0 | $0 | $0 | $38,000,000 | ||||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Other_Assets_Summary_of_Other_
Other Assets (Summary of Other Assets) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred Costs Capitalized Prepaid And Other Assets Disclosure [Abstract] | ' | ' |
Accumulated amortization | $18,046 | $11,948 |
Deferred financing costs, net of accumulated amortization | 40,553 | 35,292 |
Notes receivable | 3,754 | 3,978 |
Long-term derivative asset receivable from Drilling Partnerships | 622 | 863 |
Other | 7,548 | 2,688 |
Total Other Assets | $52,477 | $42,821 |
Other_Assets_Narrative_Details
Other Assets (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |
Other Assets [Line Items] | ' | ' | ' | ' | ' |
Amortization of financing costs | $2,400,000 | $2,800,000 | $6,098,000 | $5,400,000 | ' |
Accelerated amortization of deferred financing costs | 0 | 0 | 0 | 3,200,000 | ' |
Amortization of deferred financing costs | ' | ' | 6,098,000 | 8,608,000 | ' |
Notes Receivable | ' | ' | ' | ' | ' |
Other Assets [Line Items] | ' | ' | ' | ' | ' |
Note Agreement, Maturity Date | ' | ' | 31-Mar-22 | ' | 31-Mar-22 |
Note Agreement, Interest Rate Per Annum | ' | ' | 2.25% | ' | 2.25% |
Note Agreement, Extension Fee Percent | ' | ' | 1.00% | ' | 1.00% |
Other Interest and Dividend Income | 22,000 | 25,000 | 68,000 | 50,000 | ' |
Note Receivable, Allowance for Credit Losses | 0 | ' | 0 | ' | ' |
Note Agreement, Option to Extend Maturity Date | ' | ' | ' | ' | ' |
Other Assets [Line Items] | ' | ' | ' | ' | ' |
Note Agreement, Maturity Date | ' | ' | 31-Mar-27 | ' | 31-Mar-27 |
Rangely Acquisition | ' | ' | ' | ' | ' |
Other Assets [Line Items] | ' | ' | ' | ' | ' |
Amortization of deferred financing costs | $200,000 | ' | $8,400,000 | ' | ' |
Asset_Retirement_Obligations_R
Asset Retirement Obligations (Reconciliation of Liability For Well Plugging And Abandonment Costs) (Narrative) (Details) (USD $) | Sep. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2014 |
Series of Individually Immaterial Business Acquisitions | Series of Individually Immaterial Business Acquisitions | Series of Individually Immaterial Business Acquisitions | Relationship With Drilling Partnerships | Relationship With Drilling Partnerships | |||||||
Common Limited Partners’ Interests | |||||||||||
Asset Retirement Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset retirement obligations | $101,474,000 | $100,002,000 | $89,776,000 | $83,567,000 | $67,732,000 | $64,794,000 | ' | ' | ' | ' | $56,000,000 |
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,300,000 | ' |
Oil and gas reclamation liabilities noncurrent | ' | ' | ' | ' | ' | ' | $0 | $6,600,000 | $16,700,000 | ' | ' |
Asset_Retirement_Obligations_R1
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Asset Retirement Obligation Roll Forward Analysis Roll Forward | ' | ' | ' | ' |
Asset retirement obligations, beginning of period | $100,002 | $67,732 | $89,776 | $64,794 |
Liabilities incurred | 323 | 14,699 | 8,178 | 15,943 |
Liabilities settled | -270 | -158 | -688 | -381 |
Accretion expense | 1,419 | 1,294 | 4,208 | 3,211 |
Asset retirement obligations, end of period | $101,474 | $83,567 | $101,474 | $83,567 |
Debt_Schedule_of_Total_Debt_Ou
Debt (Schedule of Total Debt Outstanding) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ' | ' |
Revolving credit facility | $660,000 | $419,000 |
Total debt | 1,283,022 | 942,334 |
Less current maturities | 0 | 0 |
Long-term debt | 1,283,022 | 942,334 |
7.75% Senior Notes | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Senior Notes | 374,525 | 275,000 |
9.25% Senior Notes | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Senior Notes | $248,497 | $248,334 |
Debt_Credit_Facility_Details
Debt (Credit Facility) (Details) (USD $) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2014 | Dec. 31, 2013 | |
Line Of Credit Facility [Line Items] | ' | ' |
Revolving credit facility | $660,000,000 | 419,000,000 |
Revolving Credit Facility | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Line of Credit Facility, Expiration Date | 1-Jul-18 | ' |
Letters Of Credit Outstanding Maximum | 20,000,000 | ' |
Line of Credit Facility, Collateral | 'The Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of the Partnership’s material subsidiaries, and any non-guarantor subsidiaries of the Partnership are minor. | ' |
Line of Credit Facility, Current Borrowing Capacity | 825,000,000 | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,500,000,000 | ' |
Line of Credit Facility, Interest Rate Description | 'at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At September 30, 2014, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 2.5%. | ' |
Revolving credit facility | $4,400,000 | ' |
Line of Credit Facility, Weighted Average Interest Rate | 2.50% | ' |
Line of Credit Facility, Covenant Terms | 'The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of September 30, 2014. The Credit Agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended through December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter, and a ratio of current assets (as defined in the Credit Agreement) to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. | ' |
Line of Credit Facility, Covenant Compliance | 'The Partnership was in compliance with these covenants as of September 30, 2014. | ' |
Required Total Funded Debt To EBITDA Ratio | 4.50% | 4.50% |
Required Current Assets To Current Liabilities Ratio | 1.00% | ' |
Total Funded Debt to EBITDA Ratio | 4.00% | ' |
Current Assets To Current Liabilities Ratio | 1.20% | ' |
Revolving Credit Facility | Quarter ended June 30, 2014 | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Required Total Funded Debt To EBITDA Ratio | 4.50% | ' |
Revolving Credit Facility | Quarter ended September 30, 2014 | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Required Total Funded Debt To EBITDA Ratio | 4.50% | ' |
Revolving Credit Facility | Quarter ended December 31, 2014 | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Required Total Funded Debt To EBITDA Ratio | 4.50% | ' |
Revolving Credit Facility | Quarter ended March 31, 2015 | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Required Total Funded Debt To EBITDA Ratio | 4.25% | ' |
Revolving Credit Facility | Fiscal quarters ending thereafter | ' | ' |
Line Of Credit Facility [Line Items] | ' | ' |
Required Total Funded Debt To EBITDA Ratio | 4.00% | ' |
Debt_Senior_Notes_Details
Debt (Senior Notes) (Details) (USD $) | 9 Months Ended | 0 Months Ended | 9 Months Ended | 9 Months Ended | |||
Sep. 30, 2014 | Sep. 30, 2013 | Jun. 02, 2014 | Sep. 30, 2014 | Jan. 23, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | |
7.75% Senior Notes | 7.75% Senior Notes | 7.75% Senior Notes | 7.75% Senior Notes | 9.25% Senior Notes | |||
Maximum | |||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | 2-Jun-14 | ' | ' | ' | 30-Sep-14 |
Senior notes, Face Amount | ' | ' | $100,000,000 | $374,500,000 | $275,000,000 | ' | $248,500,000 |
Senior notes, maturity | ' | ' | ' | '2021 | ' | ' | '2021 |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | 7.75% | 7.75% | ' | 9.25% |
Offering price as a percentage of par value | ' | ' | 99.50% | ' | ' | ' | ' |
Proceeds from Debt, Net of Issuance Costs | ' | ' | 97,400,000 | ' | ' | ' | ' |
Debt Instrument, Unamortized Discount | ' | ' | ' | 500,000 | ' | ' | 1,500,000 |
Repurchase, Make Whole and Redemption Terms And Description | ' | ' | ' | 'At any time prior to January 15, 2016, the 7.75% Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. | ' | ' | ' |
Completion of exchange offer period | ' | ' | ' | ' | ' | '270 days | ' |
Debt Instrument, Call Feature | ' | ' | ' | ' | ' | ' | 'At any time on or after August 15, 2017, the Partnership may redeem some or all of the 9.25% Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, the Partnership may redeem up to 35% of the 9.25% Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 9.25% Senior Notes. |
Registration Rights Agreement, Description And Terms | ' | ' | ' | ' | ' | ' | 'On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014. |
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor | ' | ' | ' | 0 | ' | ' | ' |
Debt Instrument, Restrictive Covenants | 'The indentures governing the 9.25% Senior Notes and 7.75% Senior Notes contain covenants, including limitations on the Partnership’s ability to incur certain liens; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of the Partnership’s assets. | ' | ' | ' | ' | ' | ' |
Debt Instrument, Covenant Compliance | 'The Partnership was in compliance with these covenants as of September 30, 2014. | ' | ' | ' | ' | ' | ' |
Cash Payments For Interest On Debt | $55,200,000 | $15,200,000 | ' | ' | ' | ' | ' |
Derivative_Instruments_Narrati
Derivative Instruments (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 |
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' | ' |
Cash Flow Hedges Derivative Assets at Fair Value, Net | ' | $50.10 | ' | $50.10 | $22.60 |
Net gain in accumulated other comprehensive income | 53.3 | ' | 53.3 | ' | ' |
Cash Flow Hedge Gain (Losses) to be Reclassified within Twelve Months | ' | ' | ' | 21 | ' |
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods | ' | ' | ' | 32.3 | ' |
Derivative Instruments, Gains Reclassified from Accumulated OCI into Income, Effective Portion | 0.3 | 1.3 | 0.8 | 0.8 | ' |
Hedge Monetization Cash Proceeds | 0.8 | ' | 0.8 | ' | ' |
Net Unrealized Derivative Assets Payable To Limited Partners | 1.3 | ' | 1.3 | ' | ' |
Gas And Oil Production Revenue | ' | ' | ' | ' | ' |
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' | ' |
Gains recognized on settled contracts covering commodity production | 1.3 | 1.1 | ' | 4.4 | ' |
Loss recognized on settled contracts covering commodity production | ' | ' | 21.9 | ' | ' |
Gain (Loss) Recognized for Hedge Ineffectiveness or as a Result of Discontinuance of Cash Flow Hedges | 0 | 0 | 0 | 0 | ' |
EP Energy Acquisition | ' | ' | ' | ' | ' |
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' | ' |
Premiums Paid On Swaption Contracts | ' | ' | ' | 14.5 | ' |
Amortization Expense On Swaption Contracts | ' | $13.20 | ' | $14.50 | ' |
Derivative_Instruments_Summary
Derivative Instruments (Summary of Gains or Losses Derivative Instruments Recognized In Statements of Operations) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' |
(Gain) loss reclassified from accumulated other comprehensive income (loss) | ($1,304) | ($1,145) | $21,924 | ($4,424) |
Gas And Oil Production Revenue | ' | ' | ' | ' |
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' |
(Gain) loss reclassified from accumulated other comprehensive income (loss) | ($1,304) | ($1,145) | $21,924 | ($4,424) |
Derivative_Instruments_Fair_Va
Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | $55,554 | $38,273 |
Gross Amounts of Recognized Liabilities | -5,470 | -15,718 |
Current portion of derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 23,604 | 2,664 |
Gross Amounts Offset in the Consolidated Balance Sheets | -2,554 | -773 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 21,050 | 1,891 |
Gross Amounts of Recognized Liabilities | -2,554 | -773 |
Gross Amounts Offset in the Consolidated Balance Sheets | 2,554 | 773 |
Long-term portion of derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 31,950 | 31,146 |
Gross Amounts Offset in the Consolidated Balance Sheets | -1,124 | -4,062 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 30,826 | 27,084 |
Gross Amounts of Recognized Liabilities | -1,124 | -4,062 |
Gross Amounts Offset in the Consolidated Balance Sheets | 1,124 | 4,062 |
Total derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 55,554 | 38,273 |
Gross Amounts Offset in the Consolidated Balance Sheets | -3,678 | -9,298 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 51,876 | 28,975 |
Current portion of derivative liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | ' | 4,341 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | -4,341 |
Gross Amounts of Recognized Liabilities | -1,792 | -10,694 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 4,341 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -1,792 | -6,353 |
Long-term portion of derivative liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | ' | 122 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | -122 |
Gross Amounts of Recognized Liabilities | ' | -189 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 122 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ' | -67 |
Total derivative liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Liabilities | -5,470 | -15,718 |
Gross Amounts Offset in the Consolidated Balance Sheets | 3,678 | 9,298 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($1,792) | ($6,420) |
Derivative_Instruments_Commodi
Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) (USD $) | Sep. 30, 2014 | |
In Thousands, unless otherwise specified | ||
Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | $33,600 | [1] |
Natural Gas - Costless Collars | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 1,752 | [1] |
Natural Gas - Put Options - Drilling Partnerships | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 1,305 | [1] |
Natural Gas - WAHA Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | -28 | [2] |
Natural Gas - NGPL Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 1 | [3] |
Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 808 | [4] |
Natural Gas Liquids - Ethane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 37 | [5] |
Natural Gas Liquids - Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | -220 | [6] |
Natural Gas Liquids - Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 132 | [7] |
Natural Gas Liquids - Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 123 | [8] |
Natural Gas Liquids – Crude Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | -82 | [9] |
Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 12,563 | [9] |
Crude Oil - Costless Collars | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset | 93 | [9] |
Cash Flow Hedges Derivative Instruments at Fair Value, Net | 50,084 | [9] |
Production Period Ending December 31 2014 | Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 15,038,200 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.152 | [10] |
Fair Value Asset | 804 | [1] |
Production Period Ending December 31 2014 | Natural Gas - Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 960,000 | [10] |
Fair Value Asset | 279 | [1] |
Average Floor And Cap | 4.221 | [10] |
Production Period Ending December 31 2014 | Natural Gas - Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 960,000 | [10] |
Fair Value Asset | -23 | [1] |
Average Floor And Cap | 5.12 | [10] |
Production Period Ending December 31 2014 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 450,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 3.8 | [10] |
Fair Value Asset | 17 | [1] |
Production Period Ending December 31 2014 | Natural Gas - WAHA Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 2,700,000 | [10] |
Derivative, Swap Type, Average Fixed Price | -0.11 | [10] |
Fair Value Asset | 3 | [2] |
Production Period Ending December 31 2014 | Natural Gas - NGPL Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 2,250,000 | [10] |
Derivative, Swap Type, Average Fixed Price | -0.108 | [10] |
Fair Value Asset | 1 | [3] |
Production Period Ending December 31 2014 | Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,386,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 2.123 | [10] |
Fair Value Asset | 238 | [4] |
Production Period Ending December 31 2014 | Natural Gas Liquids - Ethane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 630,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 0.303 | [10] |
Fair Value Asset | 37 | [5] |
Production Period Ending December 31 2014 | Natural Gas Liquids - Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 3,087,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1 | [10] |
Fair Value Asset | -144 | [6] |
Production Period Ending December 31 2014 | Natural Gas Liquids - Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 378,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.308 | [10] |
Fair Value Asset | 34 | [7] |
Production Period Ending December 31 2014 | Natural Gas Liquids - Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 378,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.323 | [10] |
Fair Value Asset | 32 | [8] |
Production Period Ending December 31 2014 | Natural Gas Liquids – Crude Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 84,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 85.651 | [10] |
Fair Value Asset | -24 | [9] |
Production Period Ending December 31 2014 | Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 439,500 | [10] |
Derivative, Swap Type, Average Fixed Price | 95.09 | [10] |
Fair Value Asset | 2,144 | [9] |
Production Period Ending December 31 2014 | Crude Oil - Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 10,290 | [10] |
Fair Value Asset | 15 | [9] |
Average Floor And Cap | 84.169 | [10] |
Production Period Ending December 31 2014 | Crude Oil - Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 10,290 | [10] |
Fair Value Asset | -1 | [9] |
Average Floor And Cap | 113.308 | [10] |
Production Period Ending December 31 2015 | Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 51,924,500 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.239 | [10] |
Fair Value Asset | 12,192 | [1] |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 3,480,000 | [10] |
Fair Value Asset | 1,948 | [1] |
Average Floor And Cap | 4.234 | [10] |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 3,480,000 | [10] |
Fair Value Asset | -452 | [1] |
Average Floor And Cap | 5.129 | [10] |
Production Period Ending December 31 2015 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,440,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 4 | [10] |
Fair Value Asset | 550 | [1] |
Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 3,000,000 | [10] |
Derivative, Swap Type, Average Fixed Price | -0.068 | [10] |
Fair Value Asset | -31 | [2] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 5,040,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.983 | [10] |
Fair Value Asset | 570 | [4] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 8,064,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.016 | [10] |
Fair Value Asset | -76 | [6] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,512,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.248 | [10] |
Fair Value Asset | 98 | [7] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,512,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 1.263 | [10] |
Fair Value Asset | 91 | [8] |
Production Period Ending December 31 2015 | Natural Gas Liquids – Crude Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 60,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 83.78 | [10] |
Fair Value Asset | -58 | [9] |
Production Period Ending December 31 2015 | Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,743,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 90.645 | [10] |
Fair Value Asset | 4,977 | [9] |
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 29,250 | [10] |
Fair Value Asset | 110 | [9] |
Average Floor And Cap | 83.846 | [10] |
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 29,250 | [10] |
Fair Value Asset | -31 | [9] |
Average Floor And Cap | 110.654 | [10] |
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 45,746,300 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.311 | [10] |
Fair Value Asset | 10,462 | [1] |
Production Period Ending December 31 2016 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,440,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.15 | [10] |
Fair Value Asset | 738 | [1] |
Production Period Ending December 31 2016 | Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 1,029,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 88.65 | [10] |
Fair Value Asset | 2,731 | [9] |
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 24,840,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.532 | [10] |
Fair Value Asset | 7,552 | [1] |
Production Period Ending December 31 2017 | Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 492,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 87.752 | [10] |
Fair Value Asset | 1,409 | [9] |
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 9,360,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 4.619 | [10] |
Fair Value Asset | 2,590 | [1] |
Production Period Ending December 31 2018 | Crude Oil - Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount | 360,000 | [10] |
Derivative, Swap Type, Average Fixed Price | 88.283 | [10] |
Fair Value Asset | $1,302 | [9] |
[1] | Fair value based on forward NYMEX natural gas prices, as applicable. | |
[2] | Fair value based on forward WAHA natural gas prices, as applicable | |
[3] | Fair value based on forward NGPL natural gas prices, as applicable | |
[4] | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable | |
[5] | Fair value based on forward Mt. Belvieu ethane prices, as applicable. | |
[6] | Fair value based on forward Mt. Belvieu propane prices, as applicable. | |
[7] | Fair value based on forward Mt. Belvieu butane prices, as applicable. | |
[8] | Fair value based on forward Mt. Belvieu iso butane prices, as applicable | |
[9] | Fair value based on forward WTI crude oil prices, as applicable. | |
[10] | “MMBtu†represents million British Thermal Units; “Bbl†represents barrels; “Gal†represents gallons. |
Fair_Value_of_Financial_Instru2
Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Gross Amounts of Recognized Assets | $55,554 | $38,273 |
Gross Amounts of Recognized Liabilities | -5,470 | -15,718 |
Total derivatives, fair value, net | 50,084 | 22,555 |
Level 2 | ' | ' |
Gross Amounts of Recognized Assets | 55,554 | 38,273 |
Gross Amounts of Recognized Liabilities | -5,470 | -15,718 |
Total derivatives, fair value, net | 50,084 | 22,555 |
Commodity Swaps | ' | ' |
Gross Amounts of Recognized Assets | 51,734 | 33,594 |
Gross Amounts of Recognized Liabilities | -4,773 | -14,624 |
Commodity Swaps | Level 2 | ' | ' |
Gross Amounts of Recognized Assets | 51,734 | 33,594 |
Gross Amounts of Recognized Liabilities | -4,773 | -14,624 |
Commodity Basis Swaps | ' | ' |
Gross Amounts of Recognized Assets | 163 | ' |
Gross Amounts of Recognized Liabilities | -190 | ' |
Commodity Basis Swaps | Level 2 | ' | ' |
Gross Amounts of Recognized Assets | 163 | ' |
Gross Amounts of Recognized Liabilities | -190 | ' |
Commodity Puts | ' | ' |
Gross Amounts of Recognized Assets | 1,305 | 1,374 |
Commodity Puts | Level 2 | ' | ' |
Gross Amounts of Recognized Assets | 1,305 | 1,374 |
Commodity Option | ' | ' |
Gross Amounts of Recognized Assets | 2,352 | 3,305 |
Gross Amounts of Recognized Liabilities | -507 | -1,094 |
Commodity Option | Level 2 | ' | ' |
Gross Amounts of Recognized Assets | 2,352 | 3,305 |
Gross Amounts of Recognized Liabilities | ($507) | ($1,094) |
Fair_Value_of_Financial_Instru3
Fair Value of Financial Instruments - Additional Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |
Long-term Debt, Fair Value | $1,297,800,000 | ' | $1,297,800,000 | ' | $938,600,000 |
Long-term debt | 1,283,022,000 | ' | 1,283,022,000 | ' | 942,334,000 |
Asset impairment | $0 | $0 | $0 | $0 | $38,000,000 |
Level 3 | ' | ' | ' | ' | ' |
Conversion of Stock Conversion Price | $23.10 | ' | $23.10 | ' | ' |
Fair Value Inputs, Discount Rate | ' | ' | 0.21% | ' | ' |
Fair Value Assumptions, Expected Volatility Rate | ' | ' | 35.00% | ' | ' |
Fair_Value_of_Financial_Instru4
Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Fair value, liabilities | $323 | $14,699 | $8,178 | $15,943 |
Level 3 | ' | ' | ' | ' |
Fair value, liabilities | 323 | 14,699 | 8,178 | 15,943 |
Asset Retirement Obligations | ' | ' | ' | ' |
Fair value, liabilities | 323 | 14,699 | 8,178 | 15,943 |
Asset Retirement Obligations | Level 3 | ' | ' | ' | ' |
Fair value, liabilities | $323 | $14,699 | $8,178 | $15,943 |
Certain_Relationships_and_Rela1
Certain Relationships and Related Party Transactions (Narrative) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Relationship With Drilling Partnerships | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Related Party Transaction, Description of Transaction | ' | ' | 'The Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership is entitled to receive management fees, reimbursement for administrative costs incurred and to share in the Drilling Partnerships’ revenues and costs and expenses according to the respective partnership agreements. | ' |
Relationship With APL | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Related Party Transaction, Description of Transaction | ' | ' | 'In the Chattanooga Shale, a portion of the natural gas produced by the Partnership is gathered and processed by APL. For each of the three month periods ended September 30, 2014 and 2013, $0.1 million of gathering fees were paid by the Partnership to APL. For each of the nine month periods ended September 30, 2014 and 2013, $0.2 million of gathering fees were paid by the Partnership to APL. | ' |
Related Party Transaction, Amounts of Transaction | $0.10 | $0.10 | $0.20 | $0.20 |
Commitments_and_Contingencies_
Commitments and Contingencies (General Commitments) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Net partnership revenues subordinated | $0.90 | $2.20 | $4.70 | $6.50 |
Long-term Purchase Commitment, Amount | ' | ' | 65.4 | ' |
EP Energy Acquisition | ' | ' | ' | ' |
Contractual Obligation, Due in Next Twelve Months | 2.1 | ' | 2.1 | ' |
Contractual Obligation, Due in Second Year | 8.6 | ' | 8.6 | ' |
Contractual Obligation, Due in Third Year | 2.1 | ' | 2.1 | ' |
Contractual Obligation, Due in Fourth Year | 0 | ' | 0 | ' |
Contractual Obligation, Due in Fifth Year | $0 | ' | $0 | ' |
Minimum | ' | ' | ' | ' |
Partnership obligations to purchase units from investor partners | ' | ' | 5.00% | ' |
Percent of net partnership revenues subordinated | ' | ' | 10.00% | ' |
Maximum | ' | ' | ' | ' |
Partnership obligations to purchase units from investor partners | ' | ' | 10.00% | ' |
Percent of net partnership revenues subordinated | ' | ' | 12.00% | ' |
Issuances_of_Units_Details
Issuances of Units (Details) (USD $) | 3 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 1 Months Ended | ||||||
Mar. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2013 | Jun. 30, 2014 | 31-May-14 | Sep. 30, 2014 | Jun. 30, 2014 | Jul. 31, 2013 | Sep. 30, 2014 | Aug. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | 31-May-14 | Jun. 30, 2014 | Jul. 31, 2014 | Jul. 31, 2013 | |
Rangely Acquisition | Rangely Acquisition | Rangely Acquisition | EP Energy Acquisition | EP Energy Acquisition | EP Energy Acquisition | Equity Distribution Agreement with Deutsche Bank Securities Inc. | Equity Distribution Agreement with Deutsche Bank Securities Inc. | Equity Distribution Agreement with Deutsche Bank Securities Inc. | Over Allotment Units Issued | Over Allotment Units Issued | Over Allotment Units Issued | Class C Convertible Preferred Units | Class C Convertible Preferred Units | ||||
Rangely Acquisition | EP Energy Acquisition | EP Energy Acquisition | EP Energy Acquisition | ||||||||||||||
Atlas Parent Company "ATLS" | Atlas Parent Company "ATLS" | ||||||||||||||||
Capital Unit [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate Offering Price Of Common Units (Maximum) | ' | ' | ' | ' | ' | ' | ' | ' | ' | $100,000,000 | $25,000,000 | ' | ' | ' | ' | ' | ' |
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sale of Units | 6,325,000 | ' | ' | 15,525,000 | 15,525,000 | ' | 14,950,000 | 14,950,000 | ' | ' | 0 | 309,174 | 825,000 | 2,025,000 | 1,950,000 | ' | 3,749,986 |
Partners' Capital Account, Units, Date Of Sale | ' | 'March 2014 | ' | ' | ' | 'May 2014 | ' | ' | 'June 2013 | ' | ' | ' | ' | ' | ' | ' | ' |
Subsidiary or Equity Method Investee, Price-Per-Share | $21.18 | ' | ' | ' | $19.90 | ' | $21.75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $23.10 |
Partners' Capital Account, Sale of Units | 129,100,000 | ' | ' | ' | 297,500,000 | ' | 313,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sold in Private Placement | ' | 426,253,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 86,600,000 |
Preferred Units, Description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. |
Warrants Received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 562,497 |
Registration Rights Agreement, Description And Terms | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'Upon issuance of the Class C preferred units and warrants on July 31, 2013, the Partnership entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. The Partnership agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. | ' |
Equity Distribution Agreement Commencement Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-May-13 | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Limited Partners Units | ' | 426,253,000 | 320,092,000 | ' | ' | ' | ' | ' | ' | ' | ' | 6,900,000 | ' | ' | ' | ' | ' |
Payments for Commissions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $400,000 | ' | ' | ' | ' | ' |
Equity Distribution Agreement Effective Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 27-Dec-13 | ' | ' | ' | ' | ' | ' |
Cash_Distributions_Additional_
Cash Distributions - Additional Information (Details) (USD $) | 1 Months Ended | 3 Months Ended | 0 Months Ended | 9 Months Ended | ||||||||||||||
In Millions, except Per Share data, unless otherwise specified | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Feb. 28, 2014 | Jan. 31, 2014 | Jun. 30, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Oct. 29, 2014 | Oct. 29, 2014 | Oct. 29, 2014 | Oct. 29, 2014 | Sep. 30, 2014 | Sep. 30, 2014 |
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Minimum | Maximum | |||||||||||||
Cash Distribution Declared | Cash Distribution Paid | Cash Distribution Paid | Cash Distribution Paid | |||||||||||||||
General Partners’ Interest | Preferred Limited Partners' Interest | |||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of Distributions in Excess of Targets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.00% | 48.00% |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.20 | $0.19 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | $0.20 | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29-Oct-14 | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $18.90 | $1.40 | $1.50 | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Nov-14 | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10-Nov-14 | ' | ' | ' | ' |
Cash_Distributions_Schedule_of
Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||||
In Thousands, except Per Share data, unless otherwise specified | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Feb. 28, 2014 | Jan. 31, 2014 | Jun. 30, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2014 |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.20 | $0.19 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | ' |
Common Limited Partners’ Interests | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13-Mar-12 |
Distribution Made to Limited Partner, Cash Distributions Paid | $16,032 | $16,028 | $15,752 | $12,719 | $12,718 | $16,029 | $15,752 | $12,719 | $34,489 | $33,291 | $32,097 | $22,428 | ' |
Preferred Limited Partners' Interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Limited Partner, Cash Distributions Paid | 1,491 | 1,493 | 1,466 | 1,466 | 1,467 | 1,492 | 1,466 | 1,466 | 4,400 | 4,248 | 2,072 | 1,957 | ' |
General Partners’ Interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Limited Partner, Cash Distributions Paid | $1,378 | $1,378 | $1,279 | $1,055 | $1,055 | $1,377 | $1,279 | $1,054 | $2,891 | $2,443 | $1,884 | $946 | ' |
Quarter Ended March31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-May-13 |
Quarter Ended June30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Aug-13 |
Quarter Ended September30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Nov-13 |
Quarter Ended December31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Feb-14 |
Quarter Ended January31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17-Mar-14 |
Quarter Ended February28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Apr-14 |
Quarter Ended March312014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-May-14 |
Quarter Ended April30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13-Jun-14 |
Quarter Ended May31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Jul-14 |
Quarter ended June 30, 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Aug-14 |
Quarter Ended July31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12-Sep-14 |
Quarter Ended August31 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made To Limited Partner [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Oct-14 |
Benefit_Plan_2012_Long_Term_In
Benefit Plan (2012 Long Term Incentive Plan Narrative) (Details) (2012 Long-Term Incentive Plan) | 9 Months Ended |
Sep. 30, 2014 | |
2012 Long-Term Incentive Plan | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Description | 'The Partnership’s 2012 Long-Term Incentive Plan (“2012 LTIPâ€), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners (collectively, the “Participantsâ€), who perform services for the Partnership. The 2012 LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “LTIP Committeeâ€). Under the 2012 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 2,900,000 common limited partner units. |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 2,900,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 2,258,110 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 148,663 |
Benefit_Plan_2012_LTIP_Phantom
Benefit Plan (2012 LTIP Phantom Units Activity) (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ' | ||||
Distribution equivalent rights paid on unissued units under incentive plans | ' | ' | $1,696,000 | ' | ' | ||||
Partnership 2012 Long Term Incentive Plans - Phantom Units | ' | ' | ' | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ' | ||||
Distribution equivalent rights paid on unissued units under incentive plans | 500,000 | 500,000 | 1,500,000 | 1,500,000 | ' | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | ' | ' | 'Phantom units granted under the 2012 LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 314,775 | ' | 314,775 | ' | ' | ||||
Outstanding, beginning of year (Units) | 901,207 | 845,932 | 839,808 | 948,476 | ' | ||||
Granted (Units) | 9,400 | 37,191 | 236,423 | 128,981 | ' | ||||
Vested and issued (Units) | -115,797 | [1] | -33,123 | [1] | -262,671 | [1] | -204,582 | [1] | ' |
Forfeited (Units) | 0 | 0 | -18,750 | -22,875 | ' | ||||
Outstanding, end of period (Units) | 794,810 | [2],[3] | 850,000 | [2],[3] | 794,810 | [2],[3] | 850,000 | [2],[3] | ' |
Vested and not yet issued (Units) | 5,412 | [4] | 7,749 | [4] | 5,412 | [4] | 7,749 | [4] | ' |
Outstanding, beginning of year | $23.29 | $24.51 | $24.31 | $24.76 | ' | ||||
Granted | $19.85 | $21.86 | $20.28 | $22.07 | ' | ||||
Vested and issued | $24.54 | [1] | $24.72 | [1] | $24.51 | [1] | $24.70 | [1] | ' |
Forfeited | $0 | $0 | $23 | $24.23 | ' | ||||
Outstanding, end of period | $23.07 | [2],[3] | $24.38 | [2],[3] | $23.07 | [2],[3] | $24.38 | [2],[3] | ' |
Vested and not yet issued | $25.25 | [4] | $25.51 | [4] | $25.25 | [4] | $25.51 | [4] | ' |
Non-cash compensation expense recognized | 1,647,000 | 2,045,000 | 4,968,000 | 7,329,000 | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 2,800,000 | 800,000 | 5,700,000 | 5,000,000 | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 15,500,000 | ' | 15,500,000 | ' | ' | ||||
Liabilities Related to Outstanding Phantom Units | 200,000 | ' | 200,000 | ' | 100,000 | ||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 29,035 | ' | 29,035 | ' | 16,084 | ||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $21.09 | ' | $21.09 | ' | $22.15 | ||||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Vested Not Yet Issued Weighted Average Grant Date Fair Value | 100,000 | 200,000 | ' | ' | ' | ||||
Unrecognized compensation expense related to unvested units | $8,300,000 | ' | $8,300,000 | ' | ' | ||||
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | Partnership 2012 Long Term Incentive Plans - Phantom Units | ' | ' | ' | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | ' | ' | 25.00% | ' | ' | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | ' | ' | '4 years | ' | ' | ||||
[1] | The intrinsic value of phantom unit awards vested and issued during the three months ended September 30, 2014 and 2013 was $2.8 million and $0.8 million, respectively, and $5.7 million and $5.0 million during the nine months ended September 30, 2014 and 2013, respectively. | ||||||||
[2] | The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2014 was $15.5 million. | ||||||||
[3] | There was $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets representing 29,035 and 16,084 units for the periods ending September 30, 2014 and December 31, 2013, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.09 and $22.15 for the periods ending September 30, 2014 and December 31, 2013, respectively. There was approximately $40,000 recognized as liabilities on the Partnership’s consolidated balance sheet at September 30, 2013, representing 7,939 units due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $25.19 as of September 30, 2013. | ||||||||
[4] | The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2014 and 2013 were $0.1 million and $0.2 million, respectively. |
Benefit_Plan_2012_Unit_Option_
Benefit Plan (2012 Unit Option Activity) (Details) (Partnership 2012 Long Term Incentive Plans - Unit Options, USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | ' | ' | 'The LTIP Committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method by which the exercise price may be paid by the Participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the 2012 LTIP generally will vest 25% on each of the next four anniversaries of the date of grant | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months | 362,888 | ' | 362,888 | ' | ||||
Proceeds from Stock Options Exercised | $0 | $0 | $0 | $0 | ||||
Years From Date Of Grant Unit Option Awards Expire | '10 years | ' | ' | ' | ||||
Outstanding, beginning of year (Units) | 1,467,050 | 1,494,750 | 1,482,675 | 1,515,500 | ||||
Granted (Units) | 0 | 0 | 0 | 2,500 | ||||
Exercised (Units) | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] |
Forfeited (Units) | -3,750 | -6,250 | -19,375 | -29,500 | ||||
Outstanding, end of period (Units) | 1,463,300 | [2],[3] | 1,488,500 | [2],[3] | 1,463,300 | [2],[3] | 1,488,500 | [2],[3] |
Options exercisable (Units) | 732,025 | [4] | 371,375 | [4] | 732,025 | [4] | 371,375 | [4] |
Outstanding, beginning of year | $24.66 | $24.67 | $24.66 | $24.68 | ||||
Granted | $0 | $0 | $0 | $22.88 | ||||
Exercised | $0 | [1] | $0 | [1] | $0 | [1] | $0 | [1] |
Forfeited | $24.67 | $24.67 | $24.48 | $24.74 | ||||
Outstanding, end of period | $24.66 | [2],[3] | $24.67 | [2],[3] | $24.66 | [2],[3] | $24.67 | [2],[3] |
Options exercisable | $24.67 | [4] | $24.67 | [4] | $24.67 | [4] | $24.67 | [4] |
Non-cash compensation expense recognized | 342,000 | 915,000 | 1,374,000 | 2,880,000 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value | 0 | 0 | 0 | 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term | ' | ' | '7 years 7 months 6 days | ' | ||||
Aggregate Intrinsic Value Of Options Outstanding | 0 | ' | 0 | ' | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | ' | ' | '7 years 7 months 6 days | '8 years 7 months 6 days | ||||
Unrecognized compensation expense related to unvested unit options | $1,400,000 | ' | $1,400,000 | ' | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used | ' | ' | 'The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ' | ||||
Expected dividend yield | ' | ' | ' | 6.70% | ||||
Expected unit price volatility | ' | ' | ' | 35.80% | ||||
Risk-free interest rate | ' | ' | ' | 1.10% | ||||
Expected term (in years) | '0 years | '0 years | '0 years | '6 years 4 months 6 days | ||||
Fair value of unit options granted | ' | ' | ' | $3.63 | ||||
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | ' | ' | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ||||
Share Based Compensation Arrangement By Share Based Payment Award Options Vesting Period Percentage | ' | ' | 25.00% | ' | ||||
[1] | No options were exercised during the three and nine months ended September 30, 2014 and 2013, respectively. | |||||||
[2] | The weighted average remaining contractual life for outstanding options at September 30, 2014 was 7.6 years. | |||||||
[3] | There was no aggregate intrinsic value of options outstanding at September 30, 2014. | |||||||
[4] | The weighted average remaining contractual lives for exercisable options at September 30, 2014 and 2013 were 7.6 years and 8.6 years, respectively. There were no aggregate intrinsic values of options exercisable at September 30, 2014 and 2013. |
Operating_Segment_Information_1
Operating Segment Information (Narrative) (Details) | 9 Months Ended |
Sep. 30, 2014 | |
Segment | |
Segment Reporting [Abstract] | ' |
Number of reportable operating segments | 3 |
Operating_Segment_Information_2
Operating Segment Information (Operating Segment Data) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | $202,694 | $91,085 | $494,756 | $286,459 | ||||
Depreciation, depletion and amortization expense | -62,852 | -41,656 | -171,090 | -85,061 | ||||
Segment income (loss) | 30,868 | 3,695 | 65,401 | 36,697 | ||||
Gas And Oil Production | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 125,394 | 80,332 | 325,696 | 173,490 | ||||
Operating costs and expenses | -49,922 | -29,419 | -128,477 | -63,670 | ||||
Depreciation, depletion and amortization expense | -60,103 | -39,900 | -163,663 | -80,176 | ||||
Segment income (loss) | 15,369 | 11,013 | 33,556 | 29,644 | ||||
Well Construction And Completion | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 61,204 | 10,964 | 126,917 | 92,293 | ||||
Operating costs and expenses | -53,221 | -9,534 | -110,363 | -80,255 | ||||
Segment income (loss) | 7,983 | 1,430 | 16,554 | 12,038 | ||||
Other Partnership Management | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Revenues | 16,096 | [1] | -211 | [1] | 42,143 | [1] | 20,676 | [1] |
Operating costs and expenses | -5,831 | [1] | -6,781 | [1] | -19,425 | [1] | -20,776 | [1] |
Depreciation, depletion and amortization expense | -2,749 | [1] | -1,756 | [1] | -7,427 | [1] | -4,885 | [1] |
Segment income (loss) | $7,516 | [1] | ($8,748) | [1] | $15,291 | [1] | ($4,985) | [1] |
[1] | Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating_Segment_Information_3
Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Income (Loss)) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total segment income (loss) | $30,868 | $3,695 | $65,401 | $36,697 | ||||
General and administrative expenses | -13,124 | [1] | -31,983 | [1] | -50,894 | [1] | -63,767 | [1] |
Interest expense | -16,577 | [1] | -10,748 | [1] | -43,028 | [1] | -22,145 | [1] |
Loss on asset sales and disposal | -92 | [1] | -661 | [1] | -1,686 | [1] | -2,035 | [1] |
Net income (loss) | 1,075 | -39,697 | -30,207 | -51,250 | ||||
Gas And Oil Production | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total segment income (loss) | 15,369 | 11,013 | 33,556 | 29,644 | ||||
Well Construction And Completion | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total segment income (loss) | 7,983 | 1,430 | 16,554 | 12,038 | ||||
Other Partnership Management | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total segment income (loss) | $7,516 | [2] | ($8,748) | [2] | $15,291 | [2] | ($4,985) | [2] |
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. | |||||||
[2] | Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating_Segment_Information_4
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total revenues | $202,694 | $91,085 | $494,756 | $286,459 | ||||
Gas And Oil Production | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total revenues | 125,394 | 80,332 | 325,696 | 173,490 | ||||
Well Construction And Completion | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total revenues | 61,204 | 10,964 | 126,917 | 92,293 | ||||
Other Partnership Management | ' | ' | ' | ' | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ||||
Total revenues | $16,096 | [1] | ($211) | [1] | $42,143 | [1] | $20,676 | [1] |
[1] | Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating_Segment_Information_5
Operating Segment Information (Capital Expenditures) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Capital expenditures | $55,930 | $73,944 | $150,485 | $203,996 |
Gas And Oil Production | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Capital expenditures | 50,596 | 64,094 | 134,388 | 186,529 |
Other Partnership Management | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Capital expenditures | 4,097 | 7,753 | 11,637 | 11,798 |
Corporate and Other | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Capital expenditures | $1,237 | $2,097 | $4,460 | $5,669 |
Operating_Segment_Information_6
Operating Segment Information (Balance Sheet) (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | $31,784 | $31,784 |
Total assets | 2,986,402 | 2,343,800 |
Gas And Oil Production | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 18,145 | 18,145 |
Total assets | 2,783,035 | 2,170,712 |
Well Construction And Completion | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 6,389 | 6,389 |
Total assets | 70,021 | 55,031 |
Other Partnership Management | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 7,250 | 7,250 |
Total assets | 58,918 | 56,493 |
Corporate and Other | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Total assets | $74,428 | $61,564 |
Subsequent_Events_Eagle_Ford_S
Subsequent Events (Eagle Ford Shale Asset Acquisition) (Details) (Eagle Ford Shale Asset Acquisition, USD $) | 9 Months Ended | 0 Months Ended | |||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Nov. 05, 2014 | Nov. 05, 2014 | Nov. 05, 2014 | Nov. 05, 2014 |
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | ||
Atlas Resource Partners L P | Atlas Resource Partners L P | Development Subsidiary | |||
Class D Preferred Units | |||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' |
Business Acquisition, Date of Acquisition Agreement | 5-Nov-14 | ' | ' | ' | ' |
Cash Consideration | ' | $199 | ' | ' | ' |
Deferred portion of purchase price | ' | 140 | 24 | ' | 116 |
Deferred portion of purchase price by issuing preferred units | ' | ' | ' | 20 | ' |
Public offer price per share | ' | ' | ' | $25 | ' |
Increase in borrowing base under revolving credit facility | ' | ' | $900 | ' | ' |
Subsequent_Events_Targa_Resour
Subsequent Events (Targa Resources Acquisition and ATLS Spin-Off) (Details) | 9 Months Ended | 0 Months Ended | |
Sep. 30, 2014 | Sep. 30, 2014 | Oct. 13, 2014 | |
Targa Resources Corp and ATLS Spin-Off | Subsequent Event | ||
Targa Resources Corp and ATLS Spin-Off | |||
Subsequent Event [Line Items] | ' | ' | ' |
Business Acquisition, Date of Acquisition Agreement | ' | 13-Oct-14 | ' |
Pro-rata share in Drilling Partnerships | 30.00% | ' | 100.00% |
Subsequent_Events_Cash_Distrib
Subsequent Events (Cash Distribution) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 0 Months Ended | |||||||||||||
In Millions, except Per Share data, unless otherwise specified | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Feb. 28, 2014 | Jan. 31, 2014 | Jun. 30, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Oct. 29, 2014 | Oct. 29, 2014 | Oct. 29, 2014 | Oct. 29, 2014 |
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | |||||||||||||
Cash Distribution Declared | Cash Distribution Paid | Cash Distribution Paid | Cash Distribution Paid | |||||||||||||
General Partners’ Interest | Preferred Limited Partners' Interest | |||||||||||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29-Oct-14 | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.20 | $0.19 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | $0.20 | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $18.90 | $1.40 | $1.50 |
Distribution Made to Member or Limited Partner, Distribution Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14-Nov-14 | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10-Nov-14 | ' | ' |
Subsequent_Events_Issuance_of_
Subsequent Events (Issuance of Preferred Units) (Details) (Subsequent Event, Eagle Ford Asset, Class D Cumulative Redeemable Perpetual Preferred Units, USD $) | 0 Months Ended |
Oct. 02, 2014 | |
Subsequent Event | Eagle Ford Asset | Class D Cumulative Redeemable Perpetual Preferred Units | ' |
Subsequent Event [Line Items] | ' |
Partners' capital account, public offer of units | 3,200,000 |
Dividend percentage | 8.63% |
Public offer price per share | $25 |
Distribution of cash on quarterly basis | $2.16 |
Subsequent_Events_925_Senior_N
Subsequent Events (9.25% Senior Notes) (Details) (9.25% Senior Notes, USD $) | 9 Months Ended | 0 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2014 | Oct. 14, 2014 |
Subsequent Event | ||
Eagle Ford Asset | ||
Subsequent Event [Line Items] | ' | ' |
Senior notes, Face Amount | $248.50 | $75 |
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% |
Offering price as a percentage of par value | ' | 100.50% |
Proceeds from Debt, Net of Issuance Costs | ' | $73.60 |
Registration Rights Agreement, Description And Terms | 'On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014. | 'In connection with the issuance, the Partnership also entered into a registration rights agreement. Under the registration rights agreement, the Partnership agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by no later than 270 days after the issuance of the 9.25% Senior Notes. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, the Partnership agreed to file a shelf registration statement with respect to the issuance. If the Partnership fails to comply with its obligations to register the notes within the specified time periods, the Partnership will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration is declared effective, as applicable. |