Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 04, 2015 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Entity Registrant Name | Atlas Resource Partners, L.P. | |
Entity Central Index Key | 1,532,750 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Units Outstanding | 95,208,626 | |
Trading Symbol | ARP |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 607 | $ 15,247 |
Accounts receivable | 89,169 | 114,520 |
Advances to affiliates | 24,856 | |
Current portion of derivative asset | 114,710 | 144,259 |
Subscriptions receivable | 32,398 | |
Prepaid expenses and other | 24,321 | 26,296 |
Total current assets | 253,663 | 332,720 |
Property, plant and equipment, net | 2,226,817 | 2,263,820 |
Goodwill and intangible assets, net | 14,213 | 14,330 |
Long-term derivative asset | 150,162 | 130,602 |
Other assets, net | 56,239 | 50,081 |
Total assets | 2,701,094 | 2,791,553 |
Current liabilities: | ||
Accounts payable | 77,603 | 111,198 |
Advances from affiliates | 2,249 | |
Liabilities associated with drilling contracts | 40,611 | |
Current portion of derivative payable to Drilling Partnerships | 1,441 | 932 |
Accrued well drilling and completion costs | 25,565 | 80,404 |
Accrued interest | 25,863 | 26,452 |
Distribution payable | 13,541 | 20,876 |
Accrued liabilities | 26,746 | 56,851 |
Total current liabilities | 170,759 | 339,573 |
Long-term debt | 1,491,612 | 1,394,460 |
Asset retirement obligations | 110,775 | 107,950 |
Other long-term liabilities | $ 3,647 | $ 2,033 |
Commitments and contingencies | ||
Partners’ Capital: | ||
General partner’s interest | $ (15,474) | $ (13,697) |
Preferred limited partners’ interests | 188,948 | 163,522 |
Common limited partners’ interests | 611,301 | 605,065 |
Accumulated other comprehensive income | 138,350 | 191,471 |
Total partners’ capital | 924,301 | 947,537 |
Total liabilities and partners' capital | 2,701,094 | 2,791,553 |
Common Class C | ||
Partners’ Capital: | ||
Class C common limited partner warrants | $ 1,176 | $ 1,176 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Revenues: | |||||
Gas and oil production | $ 97,260 | $ 108,237 | $ 201,509 | $ 208,494 | |
Well construction and completion | 16,956 | 16,336 | 40,611 | 65,713 | |
Gathering and processing | 2,177 | 3,758 | 4,361 | 8,226 | |
Administration and oversight | 547 | 4,166 | 1,806 | 5,895 | |
Well services | 6,102 | 6,365 | 12,726 | 11,844 | |
Gain (loss) on mark-to-market derivatives | (26,944) | 78,641 | |||
Other, net | 27 | 35 | 60 | 82 | |
Total revenues | 96,125 | 138,897 | 339,714 | 300,254 | |
Costs and expenses: | |||||
Gas and oil production | 43,135 | 43,122 | 88,633 | 81,647 | |
Well construction and completion | 14,745 | 14,206 | 35,315 | 57,142 | |
Gathering and processing | 2,516 | 4,273 | 4,933 | 8,686 | |
Well services | 2,139 | 2,426 | 4,337 | 4,908 | |
General and administrative | [1] | 13,287 | 21,315 | 30,422 | 37,770 |
Depreciation, depletion and amortization | 42,494 | 59,680 | 85,485 | 111,499 | |
Total costs and expenses | 118,316 | 145,022 | 249,125 | 301,652 | |
Operating income (loss) | (22,191) | (6,125) | 90,589 | (1,398) | |
Interest expense | [1] | (24,716) | (13,263) | (49,913) | (26,451) |
Gain (loss) on asset sales and disposal | [1] | 97 | 9 | 86 | (1,594) |
Net income (loss) | (46,810) | (19,379) | 40,762 | (29,443) | |
Preferred limited partner dividends | (4,234) | (4,424) | (7,887) | (8,823) | |
Net income (loss) attributable to common limited partners and the general partner | (51,044) | (23,803) | 32,875 | (38,266) | |
Allocation of net income (loss) attributable to common limited partners and the general partner: | |||||
Common limited partners’ interest | (50,023) | (26,203) | 32,217 | (42,684) | |
General partner’s interest | (1,021) | 2,400 | 658 | 4,418 | |
Net income (loss) attributable to common limited partners and the general partner | $ (51,044) | $ (23,803) | $ 32,875 | $ (38,266) | |
Net income (loss) attributable to common limited partners per unit: | |||||
Basic | $ (0.55) | $ (0.35) | $ 0.36 | $ (0.63) | |
Diluted | $ (0.55) | $ (0.35) | $ 0.36 | $ (0.63) | |
Weighted average common limited partner units outstanding: | |||||
Basic | 90,516 | 73,900 | 88,036 | 67,595 | |
Diluted | 90,516 | 73,900 | 88,616 | 67,595 | |
[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 COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Statement Of Income And Comprehensive Income [Abstract] | ||||
Net income (loss) | $ (46,810) | $ (19,379) | $ 40,762 | $ (29,443) |
Other comprehensive income (loss): | ||||
Changes in fair value of derivative instruments accounted for as cash flow hedges | (28,839) | (65,094) | ||
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net income (loss) | (25,778) | 9,522 | (53,121) | 24,091 |
Total other comprehensive loss | (25,778) | (19,317) | (53,121) | (41,003) |
Comprehensive loss attributable to common and preferred limited partners and the general partner | $ (72,588) | $ (38,696) | $ (12,359) | $ (70,446) |
CONSOLIDATED STATEMENT OF PARTN
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands | Total | Accumulated Other Comprehensive Income | General Partners’ InterestGeneral Class A | Preferred Limited Partners InterestsPreferred Class B | Preferred Limited Partners InterestsPreferred Class C | Preferred Limited Partners InterestsPreferred Class D | Preferred Limited Partners InterestsPreferred Class E | Common Limited Partners’ Interests | Class C Common Limited Partner Warrants |
Balance at Dec. 31, 2014 | $ 947,537 | $ 191,471 | $ (13,697) | $ 983 | $ 85,501 | $ 77,038 | $ 605,065 | $ 1,176 | |
Balance (units) at Dec. 31, 2014 | 1,819,113 | 39,654 | 3,749,986 | 3,200,000 | 85,346,941 | 562,497 | |||
Arkoma transaction adjustment | (35,404) | $ (35,404) | |||||||
Issuance of units | 96,852 | $ 19,978 | $ 6,005 | $ 70,869 | |||||
Issuance of units (units) | 199,953 | 800,000 | 255,000 | 9,385,824 | |||||
Net issued and unissued units under incentive plans | 4,304 | $ 4,304 | |||||||
Net issued and unissued units under incentive plans (units) | 412,627 | ||||||||
Distributions payable | 7,377 | $ 1,155 | $ 2 | $ 100 | $ (182) | $ (173) | $ 6,475 | ||
Distributions paid to common and preferred limited partners and the general partner | (83,596) | (3,590) | (37) | (4,024) | (4,130) | (71,815) | |||
Distribution equivalent rights paid on unissued units under incentive plan | (410) | (410) | |||||||
Net income | 40,762 | 658 | 32 | 3,825 | 3,885 | 145 | 32,217 | ||
Other comprehensive loss | (53,121) | (53,121) | |||||||
Balance at Jun. 30, 2015 | $ 924,301 | $ 138,350 | $ (15,474) | $ 980 | $ 85,402 | $ 96,589 | $ 5,977 | $ 611,301 | $ 1,176 |
Balance (units) at Jun. 30, 2015 | 2,019,066 | 39,654 | 3,749,986 | 4,000,000 | 255,000 | 95,145,392 | 562,467 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ 40,762 | $ (29,443) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 85,485 | 111,499 | |
Unrealized gain on derivatives | (71,808) | ||
(Gain) loss on asset sales and disposal | [1] | (86) | 1,594 |
Non-cash compensation expense | 4,209 | 4,353 | |
Amortization of deferred financing costs | 9,926 | 3,711 | |
Changes in operating assets and liabilities: | |||
Accounts receivable, prepaid expenses and other | 61,803 | (4,192) | |
Accounts payable and accrued liabilities | (77,106) | (34,482) | |
Net cash provided by operating activities | 53,185 | 53,040 | |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures | (69,491) | (94,649) | |
Net cash paid for acquisitions | (36,967) | (517,453) | |
Other | 167 | (148) | |
Net cash used in investing activities | (106,291) | (612,250) | |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under credit facilities | 473,500 | 838,000 | |
Repayments under credit facilities | (377,000) | (676,000) | |
Distributions paid to unitholders | (83,596) | (105,970) | |
Net proceeds from long term debt | 97,500 | ||
Net proceeds from issuance of common limited partner units | 70,869 | 426,393 | |
Net proceeds from issuance of preferred units | 6,005 | ||
Arkoma transaction adjustment | (35,404) | (7,905) | |
Deferred financing costs, distribution equivalent rights and other | (15,908) | (10,643) | |
Net cash provided by financing activities | 38,466 | 561,375 | |
Net change in cash and cash equivalents | (14,640) | 2,165 | |
Cash and cash equivalents, beginning of year | 15,247 | 1,828 | |
Cash and cash equivalents, end of period | $ 607 | $ 3,993 | |
[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 | 6 Months Ended |
Jun. 30, 2015 | |
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. On February 27, 2015, the Partnership’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS) distributed 100% of its common units to existing unitholders of its then parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership (NYSE: ATLS) (Atlas Energy and Atlas Energy Group are collectively referred to as “ATLS”). Atlas Energy Group manages the Partnership’s operations and activities through its ownership of the Partnership’s general partner interest. Concurrent with Atlas Energy Group’s unit distribution, Atlas Energy and its midstream ownership interests merged into Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading. At June 30, 2015, Atlas Energy Group owned 100% of the Partnership’s general partner Class A units, all of the incentive distribution rights through which it manages and effectively controls the Partnership and an approximate 25.0% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in the Partnership. In addition to its general and limited partner interest in the Partnership, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 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, 2014. 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 six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2015 | |
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 June 30, 2015 and December 31, 2014 and the consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 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. On June 5, 2015, the Partnership acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (“Arkoma Acquisition”). Management of the Partnership determined that the Arkoma Acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable Arkoma assets and liabilities based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the acquisition of Arkoma assets would have been included in the Partnership’s consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior period consolidated financial statements to furnish comparative information. As such, the Partnership reflected the impact of the Arkoma Acquisition on its consolidated financial statements in the following manner: · Recognized the assets acquired and liabilities assumed from the Arkoma Acquisition at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital; · Retrospectively adjusted its consolidated financial statements for any date prior to June 5, 2015, the date of acquisition, to reflect its results on a consolidated basis with the results of the Arkoma assets as of or at the beginning of the respective period; and · Adjusted the presentation of the Partnership’s consolidated statements of operations for the three and six months ended June 30, 2014 to reflect the results of operations attributable to the Arkoma assets prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. 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 six months ended June 30, 2015 and 2014 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 accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ 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 June 30, 2015 and December 31, 2014, the Partnership had recorded no Inventory The Partnership had $8.5 million and $8.9 million of inventory at June 30, 2015 and December 31, 2014, 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 that 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 that 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 future 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 operating and administrative fees in addition to their proportionate share of external operating expenses. 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 partnership 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. There were no 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, 2014, the Partnership recognized $555.7 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Partnership for the three and six months ended June 30, 2015 and 2014. The impairment of proved properties during the year ended December 31, 2014 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, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity 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 6.6% and 6.0% for the three months ended June 30, 2015 and 2014, respectively, and 6.4% and 5.8% for the six months ended June 30, 2015 and 2014, respectively. The aggregate amount of interest capitalized by the Partnership was $4.1 million and $3.1 million for the three months ended June 30, 2015 and 2014, respectively, and $8.0 million and $5.7 million for the six months ended June 30, 2015 and 2014, 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 June 30, 2015 and December 31, 2014 (in thousands): March 31, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691 Amortization expense on intangible assets was $0.1 million for both the three and six months ended June 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 Goodwill At June 30, 2015 and December 31, 2014, the Partnership had $13.6 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 six months ended June 30, 2015 and 2014. 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. 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. As a result of its goodwill impairment evaluation at December 31, 2014, the Partnership recognized an $18.1 million non-cash impairment charge within asset impairments on its consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. The Partnership’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. Derivative Instruments The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. 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 reflect 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 six months ended June 30, 2015 and 2014. 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 June 30, 2015. 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 income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Preferred limited partner dividends (4,234 ) (4,424 ) (7,887 ) (8,823 ) Net income (loss) attributable to common limited partners and the general partner (51,044 ) (23,803 ) 32,875 (38,266 ) Less: General partner’s interest 1,021 (2,400 ) (658 ) (4,418 ) Net income (loss) attributable to common limited partners (50,023 ) (26,203 ) 32,217 (42,684 ) Less: Net income attributable to participating securities – phantom units (1) — — (211 ) — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Basic (50,023 ) (26,203 ) 32,006 (42,684 ) Plus: Convertible preferred limited partner dividends — — — — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (50,023 ) $ (26,203 ) $ 32,006 $ (42,684 ) (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 June 30, 2015, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 470,000 phantom units 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 three months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 724,000 phantom units 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 six months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 772,000 phantom units 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 three and six months ended June 30, 2015 and 2014, distributions on the Partnership’s Class B and Class C preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. 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 or if converted methods, as applicable. 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 Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common limited partner units—basic 90,516 73,900 88,036 67,595 Add effect of dilutive incentive awards (1) — — 580 — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 90,516 73,900 88,616 67,595 (1) For the three months ended June 30, 2015, 470,000 phantom 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 months ended June 30, 2014, 724,000 phantom 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 six months ended June 30, 2014, approximately 772,000 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. (2) For the three and six months ended June 30, 2014 and the three and six months ended June 30, |
Acquisitions
Acquisitions | 6 Months Ended |
Jun. 30, 2015 | |
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 from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 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 (“7.75% Senior Notes”) (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 year ended December 31, 2014 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 estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 4,041 Property, plant and equipment 405,416 Other assets, net 2,888 Total assets acquired $ 412,345 Liabilities: Accrued liabilities 2,117 Asset retirement obligation 1,305 Total liabilities assumed 3,422 Net assets acquired $ 408,923 Other Acquisitions Arkoma Acquisition On June 5, 2015, the Partnership completed the acquisition of ATLS’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Partnership funded the purchase price through the issuance of 6,500,000 common limited partner units (see Note 12). The Arkoma Acquisition had an effective date of January 1, 2015. The Partnership accounted for the Arkoma Acquisition as a transaction between entities under common control (see Note 2). Eagle Ford Acquisition On November 5, 2014, the Partnership and AGP completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $343.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by the Partnership and $19.9 million was paid by AGP at closing, and approximately $140.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, AGP made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, the Partnership, AGP, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, AGP paid $28.3 million and the Partnership issued $20.0 million of its Class D Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, AGP paid $16.2 million and the Partnership paid $1.3 million to satisfy the third installment related to the Eagle Ford Acquisition. At June 30, 2015, the Partnership’s remaining deferred portion of the purchase price was $2.9 million, which consisted of $1.3 million and $1.6 million payments on September 30, 2015 and December 31, 2015, respectively. The Partnership’s issuance of Class D Preferred Units represents a non-cash transaction for statement of cash flow purposes during the six months ended June 30, 2015. GeoMet Acquisition On May 12, 2014, the Partnership completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 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. |
Property, Plant and Equipment
Property, Plant and Equipment | 6 Months Ended |
Jun. 30, 2015 | |
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): June 30, December 31, Estimated 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 445,644 $ 441,548 Pre-development costs 8,748 7,223 Wells and related equipment 3,036,303 3,026,416 Total proved properties 3,490,695 3,475,187 Unproved properties 239,670 217,321 Support equipment 43,375 37,359 Total natural gas and oil properties 3,773,740 3,729,867 Pipelines, processing and compression facilities 50,738 49,547 2 – 40 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,202 9,160 3 – 40 Other 18,245 17,936 3 – 10 3,852,754 3,807,340 Less – accumulated depreciation, depletion and amortization (1,625,937 ) (1,543,520 ) $ 2,226,817 $ 2,263,820 During both the three and six months ended June 30, 2015, the Partnership recognized a $0.1 million gain on asset sales and disposals. During the six months ended June 30, 2014, the Partnership recognized $1.6 million of loss on asset sales and disposals primarily related to the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farmout agreement. There were no asset impairments for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized $555.7 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. This impairment 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, 2014. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the date of measurement. During the six months ended June 30, 2015 and 2014, the Partnership recognized $28.1 million and $36.5 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. |
Other Assets
Other Assets | 6 Months Ended |
Jun. 30, 2015 | |
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): June 30, December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $28,548 and $18,622 at June 30, 2015 and December 31, 2014, respectively $ 46,917 $ 40,637 Notes receivable 3,886 3,866 Other 5,436 5,578 $ 56,239 $ 50,081 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 $2.9 million and $1.9 million for the three months ended June 30, 2015 and 2014, respectively, and $5.6 million and $3.7 million for the six months ended June 30, 2015 and 2014, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the six months ended June 30, 2015, the Partnership recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under the revolving credit facility. There was no accelerated amortization of deferred financing costs for the Partnership during the three months ended June 30, 2015 and 2014 and the six months ended June 30, 2014. At June 30, 2015 and December 31, 2014, 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 months ended June 30, 2015 and 2014, approximately $22,000 and $23,000, respectively, of interest income was recognized within other, net on the Partnership’s consolidated statements of operations, and approximately $43,000 and $46,000 for the six months ended June 30, 2015 and 2014, respectively. At June 30, 2015 and December 31, 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 | 6 Months Ended |
Jun. 30, 2015 | |
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 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. 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 June 30, 2015, the Drilling Partnerships had $45.4 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 June 30, 2015, the Partnership has withheld $3.3 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 Six Months Ended 2015 2014 2015 2014 Asset retirement obligations, beginning of period $ 109,346 $ 92,818 $ 107,950 $ 91,179 Liabilities incurred 47 7,326 212 7,855 Liabilities settled (199 ) (332 ) (546 ) (549 ) Accretion expense 1,581 1,513 3,159 2,840 Asset retirement obligations, end of period $ 110,775 $ 101,325 $ 110,775 $ 101,325 The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations. During the year ended December 31, 2014, the Partnership incurred $7.0 million of future plugging and abandonment costs related to acquisitions it consummated (see Note 3). During the three and six months ended June 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 and six months ended June 30, 2015. |
Debt
Debt | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Debt | NOTE 7 - DEBT Total debt consists of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Revolving credit facility $ 550,000 $ 696,000 Term loan facility 243,033 — 7.75 % Senior Notes – due 2021 374,581 374,544 9.25 % Senior Notes – due 2021 323,998 323,916 Total debt 1,491,612 1,394,460 Less current maturities — — Total long-term debt $ 1,491,612 $ 1,394,460 Credit Facility The Partnership is a party to its Second Amended and Restated Credit Agreement dated July 31, 2013, as amended, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “Credit Agreement”), which provides for a senior secured revolving credit facility with a borrowing base of $750.0 million as of June 30, 2015. The Partnership’s borrowing base is scheduled for semi-annual redeterminations on July 1, 2015 and November 1, 2015 and thereafter on May 1 and November 1 of each year. In July 2015, the scheduled determination by the lenders reaffirmed the Partnership’s $750.0 million borrowing base. The Credit Agreement also provides that the Partnership’s borrowing base will be reduced by 25% of the stated amount of any senior notes issued, or additional second lien debt incurred, after July 1, 2015. At June 30, 2015, $550.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at June 30, 2015. 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 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% ) The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), 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 Term Loan Facility On February 23, 2015, the Partnership entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020. The Term Loan Facility is presented net of unamortized discount of $7.0 million at June 30, 2015. The Partnership has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. The Partnership is also required to offer to prepay the Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest: · the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date; · 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date; · 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and · no premium for prepayments made following 36 months after the closing date. The Partnership’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee the Partnership’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by the Partnership’s material restricted subsidiaries. Borrowings under the Term Loan Facility bear interest, at the Partnership’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At June 30, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%. The Second Lien Credit Agreement contains customary covenants that limit the Partnership’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in the Partnership’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. The Partnership was in compliance Under the Second Lien Credit Agreement, the Partnership may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020. Senior Notes At June 30, 2015, the Partnership had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% Senior Notes”). The 7.75% Senior Notes were presented net of a $0.4 million unamortized discount as of June 30, 2015. Interest on the 7.75% Senior Notes 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 Partnership may redeem the 7.75% Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (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. 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 7.75% Senior Notes. At June 30, 2015, the Partnership had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% Senior Notes”). The 9.25% Senior Notes were presented net of a $ 1.0 In connection with the issuance of $75.0 million of 9.25% Senior Notes on October 14, 2014, 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 11, 2015. On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015 and expired on May 13, 2015. The 7.75% Senior Notes and 9.25% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 7.75% Senior Notes and 9.25% 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 7.75% Senior Notes and 9.25% Senior Notes contain covenants, including limitations of 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 Total cash payments for interest by the Partnership were $47.3 million and $26.0 million for the six months ended June 30, 2015 and 2014, respectively. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2015 | |
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. On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet, are being reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions settle. 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 $264.9 million and $274.9 million at June 30, 2015 and December 31, 2014, respectively. Of the $138.4 million of deferred gains in accumulated other comprehensive income on the Partnership’s consolidated balance sheet at June 30, 2015, the Partnership will reclassify $ $ The following table summarizes the commodity derivative activity for the three and six months ended June 30, 2015 (in thousands): Three Months Ended Six Months Ended Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ (25,778 ) $ (53,121 ) Portion of settlements attributable to subsequent mark to market gains (14,922 ) (30,125 ) Total cash settlements on commodity derivative contracts (40,700 ) (83,246 ) 2015 Unrealized gains prior to settlement (2) 3,630 6,833 Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year (2) (30,574 ) 71,808 Gains (losses) on mark-to-market derivatives $ (26,944 ) $ 78,641 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. The Partnership had $40.7 million and $9.2 million of cash settlements during the three months ended June 30, 2015 and 2014, respectively, and $83.2 million and $23.2 million during the six months ended June 30, 2015 and 2014, respectively. 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 six months ended June 30, 2015 and 2014 for hedge ineffectiveness. 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 As of June 30, 2015 Current portion of derivative assets $ 114,982 $ (272 ) $ 114,710 Long-term portion of derivative assets 150,601 (439 ) 150,162 Total derivative assets $ 265,583 $ (711 ) $ 264,872 As of December 31, 2014 Current portion of derivative assets $ 144,357 $ (98 ) $ 144,259 Long-term portion of derivative assets 130,972 (370 ) 130,602 Total derivative assets $ 275,329 $ (468 ) $ 274,861 Offsetting Derivative Liabilities Gross Gross Net Amount of As of June 30, 2015 Current portion of derivative liabilities $ (272 ) $ 272 $ — Long-term portion of derivative liabilities (439 ) 439 — Total derivative liabilities $ (711 ) $ 711 $ — As of December 31, 2014 Current portion of derivative liabilities $ (98 ) $ 98 $ — Long-term portion of derivative liabilities (370 ) 370 — Total derivative liabilities $ (468 ) $ 468 $ — 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 were recorded at their fair values. At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 26,832,200 $ 4.193 $ 34,433 2016 53,546,300 $ 4.229 55,981 2017 49,920,000 $ 4.219 41,808 2018 40,800,000 $ 4.170 28,491 2019 15,960,000 $ 4.017 7,636 $ 168,349 Natural Gas – Costless Collars Production Option Type Volumes Average Floor Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 1,560,000 $ 4.157 $ 1,996 2015 Calls sold 1,560,000 $ 5.002 (4 ) $ 1,992 Natural Gas – Put Options – Drilling Partnerships Production Option Type Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 720,000 $ 4.000 $ 795 2016 Puts purchased 1,440,000 $ 4.150 1,519 $ 2,314 Natural Gas – WAHA Basis Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (7) 2015 2,400,000 $ (0.090 ) $ 41 $ 41 Natural Gas Liquids – Natural Gasoline Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (8) 2015 2,520,000 $ 1.936 $ 1,758 $ 1,758 Natural Gas Liquids – Propane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (4) 2015 4,032,000 $ 1.016 $ 2,133 $ 2,133 Natural Gas Liquids – Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (5) 2015 756,000 $ 1.248 $ 467 $ 467 Natural Gas Liquids – Iso Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (6) 2015 756,000 $ 1.263 $ 460 $ 460 Natural Gas Liquids – Crude Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 1,960 2017 60,000 $ 83.780 1,183 $ 3,143 Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 966,000 $ 87.653 $ 26,301 2016 1,557,000 $ 81.471 29,889 2017 1,140,000 $ 77.285 15,237 2018 1,080,000 $ 76.281 11,561 2019 540,000 $ 68.371 993 $ 83,981 Crude Oil – Costless Collars Production Option Type Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 Puts purchased 9,750 $ 83.846 $ 234 2015 Calls sold 9,750 $ 110.654 — $ 234 Total net assets $ 264,872 (1) (2) (3) (4) (5) (6) (7) (8) 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 June 30, 2015, net unrealized derivative assets of $2.3 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. At June 30, 2015, 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 Instrum
Fair Value of Financial Instruments | 6 Months Ended |
Jun. 30, 2015 | |
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 June 30, 2015 and December 31, 2014 was as follows (in thousands): As of June 30, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 261,039 $ — $ 261,039 Commodity puts — 2,314 — 2,314 Commodity options — 2,230 — 2,230 Total derivative assets, gross — 265,583 — 265,583 Derivative liabilities, gross Commodity swaps — (707 ) — (707 ) Commodity options — (4 ) — (4 ) Total derivative liabilities, gross — (711 ) — (711 ) Total derivatives, fair value, net $ — $ 264,872 $ — $ 264,872 As of December 31, 2014 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 267,242 $ — $ 267,242 Commodity puts — 2,767 — 2,767 Commodity options — 5,320 — 5,320 Total derivative assets, gross — 275,329 — 275,329 Derivative liabilities, gross Commodity swaps — (401 ) — (401 ) Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total derivatives, fair value, net $ — $ 274,861 $ — $ 274,861 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 values of the Partnership’s long-term debt at June 30, 2015 and December 31, 2014, which consist of its Senior Notes and outstanding borrowings under its revolving credit and term loan facilities (see Note 7), were $1,307.7 million and $1,219.8 million, respectively, compared with the carrying amounts of $1,491.6 million and $1,394.5 million, respectively. At June 30, 2015 and December 31 2014, the carrying values of outstanding borrowings under the Partnership’s respective revolving and term loan credit facilities (see Note 7), which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the Partnership’s Senior Notes were based upon the market approach and calculated using yields of the Partnership Senior Notes 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 the Partnership’s 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 six months June 30, 2015 and 2014 were as follows (in thousands): Three Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 47 $ 47 $ 7,326 $ 7,326 Total $ 47 $ 47 $ 7,326 $ 7,326 Six Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 212 $ 212 $ 7,855 $ 7,855 Total $ 212 $ 212 $ 7,855 $ 7,855 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. No impairments were recognized during the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership completed the Eagle Ford, Rangely and GeoMet acquisitions (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 Eagle Ford Acquisition as of the acquisition date, which are reflected in the Partnership’s consolidated balance sheet as of June 30, 2015, are subject to change as the final valuation has 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. |
Certain Relationships and Relat
Certain Relationships and Related Party Transactions | 6 Months Ended |
Jun. 30, 2015 | |
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, sponsorship of 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 Partnership’s revenue and costs and expenses according to the respective partnership agreements. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
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. The Partnership has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, the Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and the Partnership may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by the Partnership to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of June 30, 2015, the management of the Partnership believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. While its historical structure has varied, the Partnership has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. The Partnership periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, the Partnership recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which the Partnership has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, the Partnership will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the three months ended June 30, 2015 and 2014, $0.5 million and $0.4 million, respectively, of the Partnership’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. For the six months ended June 30, 2015 and 2014, $1.1 million and $3.8 million, respectively, of the Partnership’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. In connection with the Eagle Ford Acquisition (see Note 3), the Partnership guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by AGP. Pursuant to the agreement between the Partnership and AGP, the Partnership will have the right to receive some or all of the assets acquired by AGP in the event of its failure to contribute its portion of any deferred payments. The Partnership’s deferred purchase obligation is included within accrued liabilities on the Partnership’s consolidated balance sheets at June 30, 2015 and December 31, 2014. In connection with the GeoMet 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 June 30, 2015 were as follows: 2015— $2.3 million; 2016— $2.3 million; 2017— $1.9 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.5 million. In connection with the Partnership’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), the Partnership acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of the Partnership’s firm transportation obligations as of June 30, 2015 were as follows: 2015— $4.2 million; 2016— $2.1 million; and 2017 to 2019— none. As of June 30, 2015, the Partnership is committed to expend approximately $8.2 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 | 6 Months Ended |
Jun. 30, 2015 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 12 –ISSUANCES OF UNITS In May 2015, in connection with the Arkoma Acquisition (see Note 3), the Partnership issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of approximately $49.5 million. The Partnership used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under the Partnership’s revolving credit facility. In April 2015, the Partnership issued 255,000 of its newly created 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E Preferred Units”) at a public offering price of $25.00 per unit for net proceeds of approximately $6.0 million. T pays distributions on the Class E Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00. In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), the Partnership issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D Preferred Unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. The Partnership used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford Acquisition, the Partnership issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit. On January 15, 2015, the Partnership paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 13). The Partnership pays future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. The Class D and Class E Preferred Units rank senior to the Partnership’s common units and Class C Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change in control. At any time on or after October 15, 2019 for the Class D Preferred Units and April 15, 2020 for the Class E Preferred Units, the Partnership may, at its option, redeem such preferred units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If the Partnership does not exercise this redemption option upon a change of control, then holders of such preferred units will have the option to convert the preferred units into a number of Partnership common units as set forth in the respective Certificates of Designation. If the Partnership exercises any of its redemption rights relating to the preferred units, the holders of such preferred units will not have the conversion right described above with respect to the preferred units called for redemption. 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 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. During the six months ended June 30, 2015, the Partnership issued 2,885,824 common limited partner units under the equity distribution program for net proceeds of $21.4 million, net of $0.6 million in commissions paid. In May 2014, in connection with 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 $297.3 million. In March 2014, in connection with the GeoMet Acquisition (see Note 3), 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 $129.0 million. |
Cash Distributions
Cash Distributions | 6 Months Ended |
Jun. 30, 2015 | |
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 whereby it distributes 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. While outstanding, the Class B Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. While outstanding, the Class C Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. The Partnership will pay distributions on the Class E Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00, or $0.671875 per unit paid on a quarterly basis. Distributions declared by the Partnership for the period from January 1, 2014 through June 30, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash Total Cash March 17, 2014 January 31, 2014 $ 0.1933 $ 12,718 $ 1,467 $ 1,055 April 14, 2014 February 28, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,055 May 15, 2014 March 31, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,054 June 13, 2014 April 30, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 July 15, 2014 May 31, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 August 14, 2014 June 30, 2014 $ 0.1966 $ 16,029 $ 1,492 $ 1,377 September 12, 2014 July 31, 2014 $ 0.1966 $ 16,028 $ 1,493 $ 1,378 October 15, 2014 August 31, 2014 $ 0.1966 $ 16,032 $ 1,491 $ 1,378 November 14, 2014 September 30, 2014 $ 0.1966 $ 16,032 $ 1,492 $ 1,378 December 15, 2014 October 31, 2014 $ 0.1966 $ 16,033 $ 1,491 $ 1,378 January 14, 2015 November 30, 2014 $ 0.1966 $ 16,779 $ 745 (1) $ 1,378 February 13, 2015 December 31, 2014 $ 0.1966 $ 16,782 $ 745 (1) $ 1,378 March 17, 2015 January 31, 2015 $ 0.1083 $ 9,284 $ 643 (1) $ 203 April 14, 2015 February 28, 2015 $ 0.1083 $ 9,347 $ 643 (1) $ 204 May 15, 2015 March 31, 2015 $ 0.1083 $ 9,444 $ 643 (1) $ 206 June 12, 2015 April 30, 2015 $ 0.1083 $ 10,179 $ 642 (1) $ 221 July 15, 2015 May 31, 2015 $ 0.1083 $ 10,304 $ 643 (1) $ 223 (1) Includes payments for the Class B and Class C preferred unit monthly distributions. Date Cash Distribution Paid For the Period Cash Total Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 $ — April 15, 2015 Quarter Ended March 31, 2015 $ 0.539063 $ 2,156 $ — On July 15, 2015, the Partnership paid a quarterly distribution of $0.5390625 per Class D Preferred Unit, or $2.2 million, for the second quarter of 2015 to holders of record as of July 1, 2015. On July 22, 2015, the Partnership declared a monthly distribution of $ $ On July 15, 2015, the Partnership paid an initial quarterly distribution of $0.6793 per Class E Preferred Unit, or $0.2 million, for the second quarter of 2015 to Class E Preferred Unitholders of record as of July 1, 2015. |
Benefit Plan
Benefit Plan | 6 Months Ended |
Jun. 30, 2015 | |
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 and 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 June 30, 2015, the Partnership had 1,864,057 phantom units, restricted units and restricted options outstanding under the 2012 LTIP with 134,308 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 consolidated 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 upon vesting. 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 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 June 30, 2015, 191,408 The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 632,010 $ 22.37 812,308 $ 24.35 Granted 9,730 8.50 223,523 20.29 Vested and issued (1) (222,358 ) 24.07 (131,374 ) 24.69 Forfeited (8,125 ) 23.04 (3,250 ) 24.80 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 803 $ 1,590 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 Granted 9,730 8.50 227,023 20.30 Vested and issued (1) (389,540 ) 24.02 (146,874 ) 24.48 Forfeited (8,125 ) 23.04 (18,750 ) 23.00 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 3,317 $ 3,321 (1) The intrinsic values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 2.6 (3) There were approximately $24,000 and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 (4) The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively. At June 30, 2015, the Partnership had approximately $ 3.2 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 106,949 unit options outstanding under the 2012 LTIP at June 30, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the three and six months ended June 30, 2015 and 2014. The following table sets forth the 2012 LTIP unit option activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 1,453,300 $ 24.66 1,472,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (500 ) 25.14 (3,750 ) 24.67 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 61 $ 420 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (5,500 ) 24.71 (13,750 ) 24.40 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 892 $ 1,033 (1) No options were exercised during the three and six months ended June 30, 2015 and 2014. (2) The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 (3) There was no aggregate intrinsic value of options outstanding at June 30, 2015. The aggregate intrinsic value of options outstanding at June 30, 2014 was approximately $2,000. (4) The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 no At June 30, 2015, the Partnership had approximately $0.1 million in unrecognized compensation expense related to unvested unit options outstanding under the 2012 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.8 years. 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. Restricted Units Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. |
Operating Segment Information
Operating Segment Information | 6 Months Ended |
Jun. 30, 2015 | |
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 Six Months Ended 2015 2014 2015 2014 Gas and oil production: Revenues $ 70,316 $ 108,237 $ 280,150 $ 208,494 Operating costs and expenses (43,135 ) (43,122 ) (88,633 ) (81,647 ) Depreciation, depletion and amortization expense (39,362 ) (57,194 ) (79,480 ) (106,789 ) Segment income (loss) $ (12,181 ) $ 7,921 $ 112,037 $ 20,058 Well construction and completion: Revenues $ 16,956 $ 16,336 $ 40,611 $ 65,713 Operating costs and expenses (14,745 ) (14,206 ) (35,315 ) (57,142 ) Segment income $ 2,211 $ 2,130 $ 5,296 $ 8,571 Other partnership management: (1) Revenues $ 8,853 $ 14,324 $ 18,953 $ 26,047 Operating costs and expenses (4,655 ) (6,699 ) (9,270 ) (13,594 ) Depreciation, depletion and amortization expense (3,132 ) (2,486 ) (6,005 ) (4,710 ) Segment income $ 1,066 $ 5,139 $ 3,678 $ 7,743 Reconciliation of segment income (loss) to net income (loss): Segment income (loss): Gas and oil production $ (12,181 ) $ 7,921 $ 112,037 $ 20,058 Well construction and completion 2,211 2,130 5,296 8,571 Other partnership management 1,066 5,139 3,678 7,743 Total segment income (loss) (8,904 ) 15,190 121,011 36,372 General and administrative expenses (2) (13,287 ) (21,315 ) (30,422 ) (37,770 ) Interest expense (2) (24,716 ) (13,263 ) (49,913 ) (26,451 ) Gain/(loss) on asset sales and disposal (2) 97 9 86 (1,594 ) Net income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Reconciliation of segment revenues to total revenues: Segment revenues: Gas and oil production $ 70,316 $ 108,237 $ 280,150 $ 208,494 Well construction and completion 16,956 16,336 40,611 65,713 Other partnership management 8,853 14,324 18,953 26,047 Total revenues $ 96,125 $ 138,897 $ 339,714 $ 300,254 Capital expenditures: Gas and oil production $ 24,041 $ 48,810 $ 56,233 $ 83,794 Other partnership management 2,700 4,259 12,794 7,632 Corporate and other 252 1,649 464 3,223 Total capital expenditures $ 26,993 $ 54,718 $ 69,491 $ 94,649 June 30, December 31, 2015 2014 Balance sheet: Goodwill: Gas and oil production $ — $ — Well construction and completion 6,389 6,389 Other partnership management 7,250 7,250 $ 13,639 $ 13,639 Total assets: Gas and oil production $ 2,522,853 $ 2,601,171 Well construction and completion 7,133 39,558 Other partnership management 66,752 65,896 Corporate and other 104,356 84,928 $ 2,701,094 $ 2,791,553 (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 | 6 Months Ended |
Jun. 30, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 16 — SUBSEQUENT EVENTS Cash Distributions. On July 22, 2015, the Partnership declared a monthly distribution of $ 0.1083 per common unit for the month of June 30, 2015. The $ 11.2 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on August 14, 2015 to unitholders of record at the close of business on August 7, 2015. On July 15, 2015, the Partnership paid a quarterly distribution of $0.5390625 per Class D Preferred Unit, or $2.2 million, for the second quarter of 2015 to Class D Preferred Unitholders of record as of July 1, 2015. On July 15, 2015, the Partnership paid an initial quarterly distribution of $0.6793 per Class E Preferred Unit, or $0.2 million, for the period from April 14, 2015 through July 15, 2015 to Class E Preferred Unitholders of record as of July 1, 2015. |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The Partnership’s consolidated balance sheets at June 30, 2015 and December 31, 2014 and the consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 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. On June 5, 2015, the Partnership acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (“Arkoma Acquisition”). Management of the Partnership determined that the Arkoma Acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable Arkoma assets and liabilities based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the acquisition of Arkoma assets would have been included in the Partnership’s consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior period consolidated financial statements to furnish comparative information. As such, the Partnership reflected the impact of the Arkoma Acquisition on its consolidated financial statements in the following manner: · Recognized the assets acquired and liabilities assumed from the Arkoma Acquisition at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital; · Retrospectively adjusted its consolidated financial statements for any date prior to June 5, 2015, the date of acquisition, to reflect its results on a consolidated basis with the results of the Arkoma assets as of or at the beginning of the respective period; and · Adjusted the presentation of the Partnership’s consolidated statements of operations for the three and six months ended June 30, 2014 to reflect the results of operations attributable to the Arkoma assets prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. 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 six months ended June 30, 2015 and 2014 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 accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ 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 June 30, 2015 and December 31, 2014, the Partnership had recorded no |
Inventory | Inventory The Partnership had $8.5 million and $8.9 million of inventory at June 30, 2015 and December 31, 2014, 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 that 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 that 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 future 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 operating and administrative fees in addition to their proportionate share of external operating expenses. 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 partnership 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. There were no 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, 2014, the Partnership recognized $555.7 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Partnership for the three and six months ended June 30, 2015 and 2014. The impairment of proved properties during the year ended December 31, 2014 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, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity 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 6.6% and 6.0% for the three months ended June 30, 2015 and 2014, respectively, and 6.4% and 5.8% for the six months ended June 30, 2015 and 2014, respectively. The aggregate amount of interest capitalized by the Partnership was $4.1 million and $3.1 million for the three months ended June 30, 2015 and 2014, respectively, and $8.0 million and $5.7 million for the six months ended June 30, 2015 and 2014, 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 June 30, 2015 and December 31, 2014 (in thousands): March 31, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691 Amortization expense on intangible assets was $0.1 million for both the three and six months ended June 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 |
Goodwill | Goodwill At June 30, 2015 and December 31, 2014, the Partnership had $13.6 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 six months ended June 30, 2015 and 2014. 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. 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. As a result of its goodwill impairment evaluation at December 31, 2014, the Partnership recognized an $18.1 million non-cash impairment charge within asset impairments on its consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. The Partnership’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. |
Derivative Instruments | Derivative Instruments The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. |
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 reflect 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 six months ended June 30, 2015 and 2014. 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 June 30, 2015. |
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 income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Preferred limited partner dividends (4,234 ) (4,424 ) (7,887 ) (8,823 ) Net income (loss) attributable to common limited partners and the general partner (51,044 ) (23,803 ) 32,875 (38,266 ) Less: General partner’s interest 1,021 (2,400 ) (658 ) (4,418 ) Net income (loss) attributable to common limited partners (50,023 ) (26,203 ) 32,217 (42,684 ) Less: Net income attributable to participating securities – phantom units (1) — — (211 ) — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Basic (50,023 ) (26,203 ) 32,006 (42,684 ) Plus: Convertible preferred limited partner dividends — — — — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (50,023 ) $ (26,203 ) $ 32,006 $ (42,684 ) (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 June 30, 2015, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 470,000 phantom units 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 three months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 724,000 phantom units 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 six months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 772,000 phantom units 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 three and six months ended June 30, 2015 and 2014, distributions on the Partnership’s Class B and Class C preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. 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 or if converted methods, as applicable. 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 Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common limited partner units—basic 90,516 73,900 88,036 67,595 Add effect of dilutive incentive awards (1) — — 580 — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 90,516 73,900 88,616 67,595 (1) For the three months ended June 30, 2015, 470,000 phantom 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 months ended June 30, 2014, 724,000 phantom 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 six months ended June 30, 2014, approximately 772,000 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. (2) For the three and six months ended June 30, 2014 and the three and six months ended June 30, 2015, 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 six months ended June 30, 2014 and the three and six months ended June 30, 2015, potential common limited partner units issuable upon (a) conversion of the Partnership’s Class C preferred units and (b) 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. As the Class D and Class E preferred units are convertible only upon a change of control event, they are not considered dilutive securities for earnings per unit purposes. |
Revenue Recognition | Revenue Recognition Natural gas and oil production. 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. Drilling Partnerships. Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by the Partnership is deployed to drill and complete wells included within the partnership. As the Partnership deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if the Partnership has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, the Partnership is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, the Partnership is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. The Partnership recognizes its Drilling Partnership management fees in the following manner: · Well construction and completion . For each well that is drilled by a Drilling Partnership, the Partnership receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method. · Administration and oversight . For each well drilled by a Drilling Partnership, the Partnership receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays the Partnership a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. · Well services . Each Drilling Partnership pay the Partnership a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. While the historical structure has varied, the Partnership has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. The Partnership periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, the Partnership recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which the Partnership has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, the Partnership will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. Gathering and processing revenue . 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 and the Chattanooga Shales. 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%. The Partnership’s gas and oil production operations accrue 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 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 |
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 for all periods presented, 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 Issued Accounting Standards | Recently Issued Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation Topic 718 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Property, Plant and Equipment, Intangibles – Goodwill and Other . |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Schedule of the Components of Intangible Assets Being Amortized | The following table reflects the components of intangible assets being amortized at June 30, 2015 and December 31, 2014 (in thousands): March 31, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691 |
Reconciliation of Net Income (Loss) | The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Preferred limited partner dividends (4,234 ) (4,424 ) (7,887 ) (8,823 ) Net income (loss) attributable to common limited partners and the general partner (51,044 ) (23,803 ) 32,875 (38,266 ) Less: General partner’s interest 1,021 (2,400 ) (658 ) (4,418 ) Net income (loss) attributable to common limited partners (50,023 ) (26,203 ) 32,217 (42,684 ) Less: Net income attributable to participating securities – phantom units (1) — — (211 ) — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Basic (50,023 ) (26,203 ) 32,006 (42,684 ) Plus: Convertible preferred limited partner dividends — — — — Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (50,023 ) $ (26,203 ) $ 32,006 $ (42,684 ) (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 June 30, 2015, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 470,000 phantom units 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 three months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 724,000 phantom units 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 six months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 772,000 phantom units 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 three and six months ended June 30, 2015 and 2014, distributions on the Partnership’s Class B and Class C preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. |
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 Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common limited partner units—basic 90,516 73,900 88,036 67,595 Add effect of dilutive incentive awards (1) — — 580 — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 90,516 73,900 88,616 67,595 (1) For the three months ended June 30, 2015, 470,000 phantom 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 months ended June 30, 2014, 724,000 phantom 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 six months ended June 30, 2014, approximately 772,000 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. (2) For the three and six months ended June 30, 2014 and the three and six months ended June 30, 2015, 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 six months ended June 30, 2014 and the three and six months ended June 30, 2015, potential common limited partner units issuable upon (a) conversion of the Partnership’s Class C preferred units and (b) 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. As the Class D and Class E preferred units are convertible only upon a change of control event, they are not considered dilutive securities for earnings per unit purposes. |
Acquisitions (Tables)
Acquisitions (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Rangely 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 estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 4,041 Property, plant and equipment 405,416 Other assets, net 2,888 Total assets acquired $ 412,345 Liabilities: Accrued liabilities 2,117 Asset retirement obligation 1,305 Total liabilities assumed 3,422 Net assets acquired $ 408,923 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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): June 30, December 31, Estimated 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 445,644 $ 441,548 Pre-development costs 8,748 7,223 Wells and related equipment 3,036,303 3,026,416 Total proved properties 3,490,695 3,475,187 Unproved properties 239,670 217,321 Support equipment 43,375 37,359 Total natural gas and oil properties 3,773,740 3,729,867 Pipelines, processing and compression facilities 50,738 49,547 2 – 40 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,202 9,160 3 – 40 Other 18,245 17,936 3 – 10 3,852,754 3,807,340 Less – accumulated depreciation, depletion and amortization (1,625,937 ) (1,543,520 ) $ 2,226,817 $ 2,263,820 |
Other Assets (Tables)
Other Assets (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Other Assets Noncurrent Disclosure [Abstract] | |
Schedule of Other Assets | The following is a summary of other assets at the dates indicated (in thousands): June 30, December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $28,548 and $18,622 at June 30, 2015 and December 31, 2014, respectively $ 46,917 $ 40,637 Notes receivable 3,886 3,866 Other 5,436 5,578 $ 56,239 $ 50,081 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 Six Months Ended 2015 2014 2015 2014 Asset retirement obligations, beginning of period $ 109,346 $ 92,818 $ 107,950 $ 91,179 Liabilities incurred 47 7,326 212 7,855 Liabilities settled (199 ) (332 ) (546 ) (549 ) Accretion expense 1,581 1,513 3,159 2,840 Asset retirement obligations, end of period $ 110,775 $ 101,325 $ 110,775 $ 101,325 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Revolving credit facility $ 550,000 $ 696,000 Term loan facility 243,033 — 7.75 % Senior Notes – due 2021 374,581 374,544 9.25 % Senior Notes – due 2021 323,998 323,916 Total debt 1,491,612 1,394,460 Less current maturities — — Total long-term debt $ 1,491,612 $ 1,394,460 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Cash Settlements on Commodity Derivatives | The following table summarizes the commodity derivative activity for the three and six months ended June 30, 2015 (in thousands): Three Months Ended Six Months Ended Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ (25,778 ) $ (53,121 ) Portion of settlements attributable to subsequent mark to market gains (14,922 ) (30,125 ) Total cash settlements on commodity derivative contracts (40,700 ) (83,246 ) 2015 Unrealized gains prior to settlement (2) 3,630 6,833 Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year (2) (30,574 ) 71,808 Gains (losses) on mark-to-market derivatives $ (26,944 ) $ 78,641 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. |
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 As of June 30, 2015 Current portion of derivative assets $ 114,982 $ (272 ) $ 114,710 Long-term portion of derivative assets 150,601 (439 ) 150,162 Total derivative assets $ 265,583 $ (711 ) $ 264,872 As of December 31, 2014 Current portion of derivative assets $ 144,357 $ (98 ) $ 144,259 Long-term portion of derivative assets 130,972 (370 ) 130,602 Total derivative assets $ 275,329 $ (468 ) $ 274,861 Offsetting Derivative Liabilities Gross Gross Net Amount of As of June 30, 2015 Current portion of derivative liabilities $ (272 ) $ 272 $ — Long-term portion of derivative liabilities (439 ) 439 — Total derivative liabilities $ (711 ) $ 711 $ — As of December 31, 2014 Current portion of derivative liabilities $ (98 ) $ 98 $ — Long-term portion of derivative liabilities (370 ) 370 — Total derivative liabilities $ (468 ) $ 468 $ — |
Commodity Derivative Instruments by Type Table | At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 26,832,200 $ 4.193 $ 34,433 2016 53,546,300 $ 4.229 55,981 2017 49,920,000 $ 4.219 41,808 2018 40,800,000 $ 4.170 28,491 2019 15,960,000 $ 4.017 7,636 $ 168,349 Natural Gas – Costless Collars Production Option Type Volumes Average Floor Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 1,560,000 $ 4.157 $ 1,996 2015 Calls sold 1,560,000 $ 5.002 (4 ) $ 1,992 Natural Gas – Put Options – Drilling Partnerships Production Option Type Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 720,000 $ 4.000 $ 795 2016 Puts purchased 1,440,000 $ 4.150 1,519 $ 2,314 Natural Gas – WAHA Basis Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (7) 2015 2,400,000 $ (0.090 ) $ 41 $ 41 Natural Gas Liquids – Natural Gasoline Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (8) 2015 2,520,000 $ 1.936 $ 1,758 $ 1,758 Natural Gas Liquids – Propane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (4) 2015 4,032,000 $ 1.016 $ 2,133 $ 2,133 Natural Gas Liquids – Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (5) 2015 756,000 $ 1.248 $ 467 $ 467 Natural Gas Liquids – Iso Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (6) 2015 756,000 $ 1.263 $ 460 $ 460 Natural Gas Liquids – Crude Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 1,960 2017 60,000 $ 83.780 1,183 $ 3,143 Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 966,000 $ 87.653 $ 26,301 2016 1,557,000 $ 81.471 29,889 2017 1,140,000 $ 77.285 15,237 2018 1,080,000 $ 76.281 11,561 2019 540,000 $ 68.371 993 $ 83,981 Crude Oil – Costless Collars Production Option Type Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 Puts purchased 9,750 $ 83.846 $ 234 2015 Calls sold 9,750 $ 110.654 — $ 234 Total net assets $ 264,872 (1) (2) (3) (4) (5) (6) (7) (8) |
Fair Value of Financial Instr31
Fair Value of Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets/Liabilities at Fair Value | Information for assets and liabilities measured at fair value at June 30, 2015 and December 31, 2014 was as follows (in thousands): As of June 30, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 261,039 $ — $ 261,039 Commodity puts — 2,314 — 2,314 Commodity options — 2,230 — 2,230 Total derivative assets, gross — 265,583 — 265,583 Derivative liabilities, gross Commodity swaps — (707 ) — (707 ) Commodity options — (4 ) — (4 ) Total derivative liabilities, gross — (711 ) — (711 ) Total derivatives, fair value, net $ — $ 264,872 $ — $ 264,872 As of December 31, 2014 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 267,242 $ — $ 267,242 Commodity puts — 2,767 — 2,767 Commodity options — 5,320 — 5,320 Total derivative assets, gross — 275,329 — 275,329 Derivative liabilities, gross Commodity swaps — (401 ) — (401 ) Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total derivatives, fair value, net $ — $ 274,861 $ — $ 274,861 |
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 six months June 30, 2015 and 2014 were as follows (in thousands): Three Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 47 $ 47 $ 7,326 $ 7,326 Total $ 47 $ 47 $ 7,326 $ 7,326 Six Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 212 $ 212 $ 7,855 $ 7,855 Total $ 212 $ 212 $ 7,855 $ 7,855 |
Cash Distribution (Distribution
Cash Distribution (Distributions Declared) (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Distributions Made To Members Or Limited Partners [Abstract] | |
Schedule of Distributions Declared by Partnership | Distributions declared by the Partnership for the period from January 1, 2014 through June 30, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash Total Cash March 17, 2014 January 31, 2014 $ 0.1933 $ 12,718 $ 1,467 $ 1,055 April 14, 2014 February 28, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,055 May 15, 2014 March 31, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,054 June 13, 2014 April 30, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 July 15, 2014 May 31, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 August 14, 2014 June 30, 2014 $ 0.1966 $ 16,029 $ 1,492 $ 1,377 September 12, 2014 July 31, 2014 $ 0.1966 $ 16,028 $ 1,493 $ 1,378 October 15, 2014 August 31, 2014 $ 0.1966 $ 16,032 $ 1,491 $ 1,378 November 14, 2014 September 30, 2014 $ 0.1966 $ 16,032 $ 1,492 $ 1,378 December 15, 2014 October 31, 2014 $ 0.1966 $ 16,033 $ 1,491 $ 1,378 January 14, 2015 November 30, 2014 $ 0.1966 $ 16,779 $ 745 (1) $ 1,378 February 13, 2015 December 31, 2014 $ 0.1966 $ 16,782 $ 745 (1) $ 1,378 March 17, 2015 January 31, 2015 $ 0.1083 $ 9,284 $ 643 (1) $ 203 April 14, 2015 February 28, 2015 $ 0.1083 $ 9,347 $ 643 (1) $ 204 May 15, 2015 March 31, 2015 $ 0.1083 $ 9,444 $ 643 (1) $ 206 June 12, 2015 April 30, 2015 $ 0.1083 $ 10,179 $ 642 (1) $ 221 July 15, 2015 May 31, 2015 $ 0.1083 $ 10,304 $ 643 (1) $ 223 (1) Includes payments for the Class B and Class C preferred unit monthly distributions. Date Cash Distribution Paid For the Period Cash Total Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 $ — April 15, 2015 Quarter Ended March 31, 2015 $ 0.539063 $ 2,156 $ — |
Benefit Plan (Tables)
Benefit Plan (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 632,010 $ 22.37 812,308 $ 24.35 Granted 9,730 8.50 223,523 20.29 Vested and issued (1) (222,358 ) 24.07 (131,374 ) 24.69 Forfeited (8,125 ) 23.04 (3,250 ) 24.80 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 803 $ 1,590 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 Granted 9,730 8.50 227,023 20.30 Vested and issued (1) (389,540 ) 24.02 (146,874 ) 24.48 Forfeited (8,125 ) 23.04 (18,750 ) 23.00 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 3,317 $ 3,321 (1) The intrinsic values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 2.6 (3) There were approximately $24,000 and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 (4) The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively. |
Unit Option Activity | The following table sets forth the 2012 LTIP unit option activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 1,453,300 $ 24.66 1,472,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (500 ) 25.14 (3,750 ) 24.67 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 61 $ 420 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (5,500 ) 24.71 (13,750 ) 24.40 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 892 $ 1,033 (1) No options were exercised during the three and six months ended June 30, 2015 and 2014. (2) The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 (3) There was no aggregate intrinsic value of options outstanding at June 30, 2015. The aggregate intrinsic value of options outstanding at June 30, 2014 was approximately $2,000. (4) The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 no |
Operating Segment Information (
Operating Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 Six Months Ended 2015 2014 2015 2014 Gas and oil production: Revenues $ 70,316 $ 108,237 $ 280,150 $ 208,494 Operating costs and expenses (43,135 ) (43,122 ) (88,633 ) (81,647 ) Depreciation, depletion and amortization expense (39,362 ) (57,194 ) (79,480 ) (106,789 ) Segment income (loss) $ (12,181 ) $ 7,921 $ 112,037 $ 20,058 Well construction and completion: Revenues $ 16,956 $ 16,336 $ 40,611 $ 65,713 Operating costs and expenses (14,745 ) (14,206 ) (35,315 ) (57,142 ) Segment income $ 2,211 $ 2,130 $ 5,296 $ 8,571 Other partnership management: (1) Revenues $ 8,853 $ 14,324 $ 18,953 $ 26,047 Operating costs and expenses (4,655 ) (6,699 ) (9,270 ) (13,594 ) Depreciation, depletion and amortization expense (3,132 ) (2,486 ) (6,005 ) (4,710 ) Segment income $ 1,066 $ 5,139 $ 3,678 $ 7,743 Reconciliation of segment income (loss) to net income (loss): Segment income (loss): Gas and oil production $ (12,181 ) $ 7,921 $ 112,037 $ 20,058 Well construction and completion 2,211 2,130 5,296 8,571 Other partnership management 1,066 5,139 3,678 7,743 Total segment income (loss) (8,904 ) 15,190 121,011 36,372 General and administrative expenses (2) (13,287 ) (21,315 ) (30,422 ) (37,770 ) Interest expense (2) (24,716 ) (13,263 ) (49,913 ) (26,451 ) Gain/(loss) on asset sales and disposal (2) 97 9 86 (1,594 ) Net income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Reconciliation of segment revenues to total revenues: Segment revenues: Gas and oil production $ 70,316 $ 108,237 $ 280,150 $ 208,494 Well construction and completion 16,956 16,336 40,611 65,713 Other partnership management 8,853 14,324 18,953 26,047 Total revenues $ 96,125 $ 138,897 $ 339,714 $ 300,254 Capital expenditures: Gas and oil production $ 24,041 $ 48,810 $ 56,233 $ 83,794 Other partnership management 2,700 4,259 12,794 7,632 Corporate and other 252 1,649 464 3,223 Total capital expenditures $ 26,993 $ 54,718 $ 69,491 $ 94,649 June 30, December 31, 2015 2014 Balance sheet: Goodwill: Gas and oil production $ — $ — Well construction and completion 6,389 6,389 Other partnership management 7,250 7,250 $ 13,639 $ 13,639 Total assets: Gas and oil production $ 2,522,853 $ 2,601,171 Well construction and completion 7,133 39,558 Other partnership management 66,752 65,896 Corporate and other 104,356 84,928 $ 2,701,094 $ 2,791,553 (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) - Atlas Energy, L.P. - shares | Feb. 27, 2015 | Jun. 30, 2015 |
Basis Of Presentation [Line Items] | ||
Percentage of interest represented by common units which is distributed | 100.00% | |
General Partner interest in Atlas Resource Partners, L.P | 100.00% | |
Common limited partner interest in Atlas Resource Partners, L.P | 25.00% | |
Common limited partner interest in Atlas Resource Partners, L.P., Units | 20,962,485 | |
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 Accoun36
Summary of Significant Accounting Policies (Narrative) (Details) - Reclassification out of Accumulated Other Comprehensive Income - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
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 | 8,500,000 | 8,500,000 | 8,900,000 | ||
Impairments of Unproved Gas And Oil Properties | 0 | $ 0 | 0 | $ 0 | |
Asset impairment | 0 | 0 | 0 | 0 | |
Impairment of proved oil and gas properties | $ 0 | $ 0 | $ 0 | $ 0 | |
Weighted Average Interest Rate Used To Capitalize Interest | 6.60% | 6.00% | 6.40% | 5.80% | |
Interest Costs Capitalized | $ 4,100,000 | $ 3,100,000 | $ 8,000,000 | $ 5,700,000 | |
Amortization of Intangible Assets | 100,000 | 100,000 | 100,000 | 100,000 | |
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 | |||
Future Amortization Expense, 2019 | 100,000 | 100,000 | |||
Goodwill, net | 13,639,000 | 13,639,000 | 13,639,000 | ||
Goodwill, Period Increase (Decrease) | 0 | 0 | $ 0 | 0 | |
Goodwill, Impairment Loss | 18,100,000 | ||||
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 June 30, 2015. | ||||
Proportion of amount received on cost incurred to drill | 15.00% | ||||
Monthly administrative fee per well | $ 75 | ||||
Gathering Fee Percentage | 16.00% | ||||
Gathering Fee Percentage Net Margin | 3.00% | ||||
Unbilled Contracts Receivable | $ 51,700,000 | $ 51,700,000 | 84,700,000 | ||
Drilling Partnership wells | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Gathering Fee Percentage | 13.00% | ||||
Minimum | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Recognition period to receive fees | 60 days | ||||
Amount of fixed fees received by each well drilled | $ 100,000 | ||||
Monthly operating fee paid per well | $ 1,000 | ||||
Return on unhedged revenue percentage | 10.00% | ||||
Period of return on unhedged revenue | 5 years | ||||
Maximum | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Recognition period to receive fees | 270 days | ||||
Amount of fixed fees received by each well drilled | $ 500,000 | ||||
Monthly operating fee paid per well | $ 2,000 | ||||
Percentage on unhedged revenue | 50.00% | ||||
Return on unhedged revenue percentage | 12.00% | ||||
Period of return on unhedged revenue | 8 years | ||||
Appalachian Basin | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Asset impairment | 555,700,000 | ||||
Future hedge gains reclassified from accumulated other comprehensive income | $ 82,300,000 |
Summary of Significant Accoun37
Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Jun. 30, 2015 | |
Accounting Policies [Abstract] | ||
Gross Carrying Amount | $ 14,344 | $ 14,344 |
Accumulated Amortization | (13,653) | (13,770) |
Net Carrying Amount | $ 691 | $ 574 |
Estimated Useful Lives In Years | 13 years |
Summary of Significant Accoun38
Summary of Significant Accounting Policies (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Accounting Policies [Abstract] | |||||
Net income (loss) | $ (46,810) | $ (19,379) | $ 40,762 | $ (29,443) | |
Preferred limited partner dividends | (4,234) | (4,424) | (7,887) | (8,823) | |
Net income (loss) attributable to common limited partners and the general partner | (51,044) | (23,803) | 32,875 | (38,266) | |
Less: General partner’s interest | 1,021 | (2,400) | (658) | (4,418) | |
Net income (loss) attributable to common limited partners | (50,023) | (26,203) | 32,217 | (42,684) | |
Less: Net income attributable to participating securities – phantom units | [1] | (211) | |||
Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Basic | (50,023) | (26,203) | 32,006 | (42,684) | |
Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Diluted | $ (50,023) | $ (26,203) | $ 32,006 | $ (42,684) | |
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 470,000 | 724,000 | 772,000 | ||
[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 June 30, 2015, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 470,000 phantom units 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 three months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 724,000 phantom units 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 six months ended June 30, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 772,000 phantom units 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 three and six months ended June 30, 2015 and 2014, distributions on the Partnership’s Class B and Class C preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. |
Summary of Significant Accoun39
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Limited Partner Units) (Details) - shares | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Accounting Policies [Abstract] | |||||
Weighted average number of common limited partner units—basic | 90,516,000 | 73,900,000 | 88,036,000 | 67,595,000 | |
Add effect of dilutive incentive awards | [1] | 580,000 | |||
Weighted average number of common limited partner units—diluted | 90,516,000 | 73,900,000 | 88,616,000 | 67,595,000 | |
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 470,000 | 724,000 | 772,000 | ||
[1] | For the three months ended June 30, 2015, 470,000 phantom 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 months ended June 30, 2014, 724,000 phantom 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 six months ended June 30, 2014, approximately 772,000 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 ($) $ in Millions | 1 Months Ended | 6 Months Ended | ||
Jun. 30, 2014 | May. 31, 2014 | Jun. 30, 2015 | Dec. 31, 2014 | |
7.75% Senior Notes | ||||
Business Acquisition [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | |||
Rangely Acquisition | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 25.00% | |||
Business Acquisition, Cost of Acquired Entity, Cash Paid | $ 408.9 | |||
Business Acquisition, Effective Date of Acquisition | Apr. 1, 2014 | |||
Partners' Capital Account, Units, Sale of Units | 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 year ended December 31, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | |||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | $ 11.6 | |||
Rangely Acquisition | 7.75% Senior Notes | ||||
Business Acquisition [Line Items] | ||||
Proceed from additional senior notes | $ 100 | |||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% |
Acquisitions (Rangely Acquisi41
Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) - Rangely Acquisition $ in Thousands | Jun. 30, 2015USD ($) |
Business Acquisition [Line Items] | |
Prepaid expenses and other | $ 4,041 |
Property, plant and equipment | 405,416 |
Other assets, net | 2,888 |
Total assets acquired | 412,345 |
Accrued liabilities | 2,117 |
Asset retirement obligation | 1,305 |
Total liabilities assumed | 3,422 |
Net assets acquired | $ 408,923 |
Acquisitions (Other Acquisition
Acquisitions (Other Acquisition) (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 05, 2015 | Nov. 05, 2014 | May. 12, 2014 | Dec. 31, 2014 | Oct. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2015 | Jun. 30, 2015 |
Arkoma Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash Consideration | $ 31.5 | |||||||||
Issuances of Partnership Units to Fund the Purchase Price | 6,500,000 | |||||||||
Business Acquisition, Effective Date of Acquisition | Jan. 1, 2015 | |||||||||
Eagle Ford Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash Consideration | $ 183.1 | |||||||||
Business Acquisition, Date of Acquisition Agreement | Nov. 5, 2014 | |||||||||
Net cash acquired | 343 | |||||||||
Deferred portion of purchase price | 140 | |||||||||
Purchase price represent non-cash transaction | $ 2.9 | |||||||||
Eagle Ford Acquisition | Class D Preferred Units | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Issuances of Partnership Units to Fund the Purchase Price | 3,200,000 | 800,000 | ||||||||
Eagle Ford Acquisition | Atlas Growth Partners L P | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Deferred portion of purchase price | $ 19.9 | $ 35 | $ 28.3 | 16.2 | ||||||
Eagle Ford Acquisition | Atlas Resource Partners L P | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Deferred portion of purchase price | $ 1.3 | |||||||||
Eagle Ford Acquisition | Atlas Resource Partners L P | Class D Preferred Units | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Deferred portion of purchase price by issuing preferred units | $ 20 | |||||||||
Eagle Ford Acquisition | Scenario Forecast | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Total payments of purchase price represent non-cash transaction | $ 1.6 | $ 1.3 | ||||||||
GeoMet Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash Consideration | $ 97.9 | |||||||||
Issuances of Partnership Units to Fund the Purchase Price | 6,325,000 | |||||||||
Business Acquisition, Effective Date of Acquisition | Jan. 1, 2014 | |||||||||
Business Acquisition, Description of Acquired Entity | The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. |
Property, Plant and Equipment43
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Property Plant And Equipment [Abstract] | ||
Proved properties: Leasehold interests | $ 445,644 | $ 441,548 |
Proved Properties: Pre-development costs | 8,748 | 7,223 |
Proved Properties: Wells and related equipment | 3,036,303 | 3,026,416 |
Total proved properties | 3,490,695 | 3,475,187 |
Unproved properties | 239,670 | 217,321 |
Support equipment | 43,375 | 37,359 |
Total natural gas and oil properties | 3,773,740 | 3,729,867 |
Pipelines, processing and compression facilities | 50,738 | 49,547 |
Rights of way | 829 | 830 |
Land, buildings and improvements | 9,202 | 9,160 |
Other | 18,245 | 17,936 |
Total gross property, plant and equipment | 3,852,754 | 3,807,340 |
Less – accumulated depreciation, depletion and amortization | (1,625,937) | (1,543,520) |
Property, plant and equipment, Net, Total | $ 2,226,817 | $ 2,263,820 |
Property, Plant and Equipment44
Property, Plant and Equipment (Useful Life Narrative) (Details) | 6 Months Ended |
Jun. 30, 2015 | |
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 Equipment45
Property, Plant and Equipment (Narrative) (Details) - Reclassification out of Accumulated Other Comprehensive Income - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | ||
Property Plant And Equipment [Line Items] | ||||||
Gain (loss) on asset sales | [1] | $ 97,000 | $ 9,000 | $ 86,000 | $ (1,594,000) | |
Asset impairment | $ 0 | $ 0 | 0 | 0 | ||
Non-cash property plant and equipment additions | $ 28,100,000 | $ 36,500,000 | ||||
Appalachian Basin | ||||||
Property Plant And Equipment [Line Items] | ||||||
Asset impairment | $ 555,700,000 | |||||
Future hedge gains reclassified from accumulated other comprehensive income | $ 82,300,000 | |||||
[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 ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Deferred Costs Capitalized Prepaid And Other Assets Disclosure [Abstract] | ||
Accumulated amortization | $ 28,548 | $ 18,622 |
Deferred financing costs, net of accumulated amortization | 46,917 | 40,637 |
Notes receivable | 3,886 | 3,866 |
Other | 5,436 | 5,578 |
Total Other Assets | $ 56,239 | $ 50,081 |
Other Assets (Narrative) (Detai
Other Assets (Narrative) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Other Assets [Line Items] | |||||
Amortization of financing costs | $ 2,900,000 | $ 1,900,000 | $ 5,600,000 | $ 3,700,000 | |
Accelerated amortization of deferred financing costs | 0 | 0 | $ 4,300,000 | 0 | |
Notes Receivable | |||||
Other Assets [Line Items] | |||||
Note Agreement, Maturity Date | Mar. 31, 2022 | ||||
Note Agreement, Interest Rate Per Annum | 2.25% | ||||
Note Agreement, Extension Fee Percent | 1.00% | ||||
Other Interest and Dividend Income | 22,000 | $ 23,000 | $ 43,000 | $ 46,000 | |
Note Receivable, Allowance for Credit Losses | $ 0 | $ 0 | $ 0 | ||
Note Agreement, Option to Extend Maturity Date | |||||
Other Assets [Line Items] | |||||
Note Agreement, Maturity Date | Mar. 31, 2027 |
Asset Retirement Obligations (R
Asset Retirement Obligations (Reconciliation of Liability For Well Plugging And Abandonment Costs) (Narrative) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligations [Line Items] | ||||||||
Asset retirement obligations, end of year | $ 110,775,000 | $ 101,325,000 | $ 110,775,000 | $ 101,325,000 | $ 107,950,000 | $ 109,346,000 | $ 92,818,000 | $ 91,179,000 |
Series of Individually Immaterial Business Acquisitions | ||||||||
Asset Retirement Obligations [Line Items] | ||||||||
Oil and gas reclamation liabilities noncurrent | 0 | $ 6,600,000 | 0 | $ 6,600,000 | $ 7,000,000 | |||
Relationship With Drilling Partnerships | ||||||||
Asset Retirement Obligations [Line Items] | ||||||||
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships | 3,300,000 | |||||||
Relationship With Drilling Partnerships | Common Limited Partners’ Interests | ||||||||
Asset Retirement Obligations [Line Items] | ||||||||
Asset retirement obligations, end of year | $ 45,400,000 | $ 45,400,000 |
Asset Retirement Obligations 49
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Asset Retirement Obligation Roll Forward Analysis Roll Forward | ||||
Asset retirement obligations, beginning of period | $ 109,346 | $ 92,818 | $ 107,950 | $ 91,179 |
Liabilities incurred | 47 | 7,326 | 212 | 7,855 |
Liabilities settled | (199) | (332) | (546) | (549) |
Accretion expense | 1,581 | 1,513 | 3,159 | 2,840 |
Asset retirement obligations, end of period | $ 110,775 | $ 101,325 | $ 110,775 | $ 101,325 |
Debt (Schedule of Total Debt Ou
Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Revolving credit facility | $ 550,000 | $ 696,000 |
Total debt | 1,491,612 | 1,394,460 |
Long-term debt | 1,491,612 | 1,394,460 |
Term Loan | ||
Debt Instrument [Line Items] | ||
Term loan facility | 243,033 | |
7.75% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | 374,581 | 374,544 |
9.25% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | $ 323,998 | $ 323,916 |
Debt (Credit Facility) (Details
Debt (Credit Facility) (Details) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Dec. 31, 2014 | |
Line Of Credit Facility [Line Items] | ||
Revolving credit facility | $ 550,000,000 | $ 696,000,000 |
Revolving Credit Facility | ||
Line Of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | $ 750,000,000 | |
Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced | 25.00% | |
Revolving credit facility | $ 550,000,000 | |
Letters Of Credit Outstanding Maximum | 20,000,000 | |
Letters Of Credit Outstanding Amount | $ 4,300,000 | |
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 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. If the borrowing base utilization (as defined in the Credit Agreement) is less than 90%, the applicable margin on Eurodollar loans and ABR loans will be increased by 0.25%. The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum 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 June 30, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.5%. | |
Line of Credit Facility, Weighted Average Interest Rate | 2.50% | |
Aggregate Principal Amount of Second Lien Debt | $ 300,000,000 | |
Line of Credit Facility, Covenant Terms | The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), 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 June 30, 2015. 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 (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter 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 June 30, 2015. | |
Required Current Assets To Current Liabilities Ratio | 100.00% | |
Total Funded Debt to EBITDA Ratio | 450.00% | |
Current Assets To Current Liabilities Ratio | 200.00% | |
Revolving Credit Facility | Borrowing base utilization is less than 90% | ||
Line Of Credit Facility [Line Items] | ||
Percentage of borrowing base utilized | 90.00% | |
Revolving Credit Facility | Borrowing base utilization is less than 90% | Eurodollar | ||
Line Of Credit Facility [Line Items] | ||
Increase in applicable margin | 0.25% | |
Revolving Credit Facility | Borrowing base utilization is less than 90% | Alternate Base Rate | ||
Line Of Credit Facility [Line Items] | ||
Increase in applicable margin | 0.25% |
Debt (Term Loan Facility) (Deta
Debt (Term Loan Facility) (Details) - Second Lien Term Loan Facility - USD ($) $ in Millions | Feb. 23, 2015 | Jun. 30, 2015 |
Debt Instrument [Line Items] | ||
Increase in borrowing base under revolving credit facility | $ 250 | |
Line of Credit Facility, Expiration Date | Feb. 23, 2020 | |
Debt Instrument, Unamortized Discount | $ 7 | |
Percentage of net cash proceeds from the issuance or incurrence of debt used to prepay Term Loan Facility | 100.00% | |
Percentage of excess net cash proceeds from certain asset sales and condemnation recoveries used to prepay Term Loan Facility | 100.00% | |
Line Of Credit Facility Interest Rate Description | Borrowings under the Term Loan Facility bear interest, at the Partnership’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. | |
Line of Credit Facility, Weighted Average Interest Rate | 10.00% | |
Aggregate outstanding principal amount of Term Loan Facility plus principal amount of incremental term loan | $ 300 | |
Incremental Term Loans | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Expiration Date | Feb. 23, 2020 | |
London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 9.00% | |
Federal Funds Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 0.50% | |
One-month LIBOR | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 1.00% | |
Base Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 2.00% | |
Alternate Base Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 8.00% | |
Between 12 months and 24 months after closing date | ||
Debt Instrument [Line Items] | ||
Percentage of principal amount prepaid for repayments | 4.50% | |
Between 24 months and 36 months after closing date | ||
Debt Instrument [Line Items] | ||
Percentage of principal amount prepaid for repayments | 2.25% | |
Following 36 months after closing date | ||
Debt Instrument [Line Items] | ||
Percentage of principal amount prepaid for repayments | 0.00% |
Debt (Senior Notes) (Details)
Debt (Senior Notes) (Details) - USD ($) | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Oct. 14, 2014 | |
Debt Instrument [Line Items] | |||
Debt Instrument, Restrictive Covenants | The indentures governing the 7.75% Senior Notes and 9.25% Senior Notes contain covenants, including limitations of 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 June 30, 2015. | ||
Cash Payments For Interest On Debt | $ 47,300,000 | $ 26,000,000 | |
7.75% Senior Notes | |||
Debt Instrument [Line Items] | |||
Senior notes, Face Amount | $ 374,600,000 | ||
Senior notes, maturity | 2,021 | ||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | ||
Debt Instrument, Unamortized Discount | $ 400,000 | ||
Senior Notes Interest Payment Dates and Terms | Interest on the 7.75% Senior Notes is payable semi-annually on January 15 and July 15. | ||
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 Partnership may redeem the 7.75% Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (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. 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 7.75% Senior Notes. | ||
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor | $ 0 | ||
9.25% Senior Notes | |||
Debt Instrument [Line Items] | |||
Senior notes, Face Amount | $ 324,000,000 | $ 75,000,000 | |
Senior notes, maturity | 2,021 | ||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | ||
Debt Instrument, Unamortized Discount | $ 1,000,000 | ||
Senior Notes Interest Payment Dates and Terms | Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. | ||
Debt Instrument, Call Feature | At any time prior to August 15, 2017, the Partnership may redeem the 9.25% Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. 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%. 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 April 15, 2015, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015 and expired on May 13, 2015. |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||||
Cash Flow Hedges Derivative Assets at Fair Value, Net | $ 264,900,000 | $ 264,900,000 | $ 274,900,000 | ||
Net gain in accumulated other comprehensive income | 138,400,000 | 138,400,000 | |||
Cash Flow Hedge Gain (Losses) to be Reclassified within Twelve Months | 74,300,000 | ||||
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods | 64,100,000 | ||||
Derivative Instruments, Gains Reclassified from Accumulated OCI into Income, Effective Portion | $ 0 | $ 0 | |||
Cash settlements gain loss on commodity derivatives | (40,700,000) | 9,200,000 | (83,246,000) | 23,200,000 | |
Gains or losses recognized during the period | 0 | $ 0 | 0 | $ 0 | |
Net Unrealized Derivative Assets Payable To Limited Partners | $ 2,300,000 | $ 2,300,000 |
Derivative Instruments (Summary
Derivative Instruments (Summary of Cash Settlements on Commodity Derivatives) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets | [1] | $ (25,778) | $ (53,121) | ||
Portion of settlements attributable to subsequent mark to market gains | (14,922) | (30,125) | |||
Total cash settlements on commodity derivative contracts | (40,700) | $ 9,200 | (83,246) | $ 23,200 | |
2015 Unrealized gains prior to settlement | [2] | 3,630 | 6,833 | ||
Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year | [2] | (30,574) | 71,808 | ||
Gains (losses) on mark-to-market derivatives | $ (26,944) | $ 78,641 | |||
[1] | Recognized in gas and oil production revenue. | ||||
[2] | Recognized in gain on mark-to-market derivatives. |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $ 265,583 | $ 275,329 |
Gross Amounts of Recognized Liabilities | (711) | (468) |
Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | (272) | (98) |
Gross Amounts Offset in the Consolidated Balance Sheets | 272 | 98 |
Long-term portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | (439) | (370) |
Gross Amounts Offset in the Consolidated Balance Sheets | 439 | 370 |
Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | (711) | (468) |
Gross Amounts Offset in the Consolidated Balance Sheets | 711 | 468 |
Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 114,982 | 144,357 |
Gross Amounts Offset in the Consolidated Balance Sheets | (272) | (98) |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 114,710 | 144,259 |
Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 150,601 | 130,972 |
Gross Amounts Offset in the Consolidated Balance Sheets | (439) | (370) |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 150,162 | 130,602 |
Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 265,583 | 275,329 |
Gross Amounts Offset in the Consolidated Balance Sheets | (711) | (468) |
Net Amount of Assets Presented in the Consolidated Balance Sheets | $ 264,872 | $ 274,861 |
Derivative Instruments (Commodi
Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) - Jun. 30, 2015 $ in Thousands | USD ($)MMBTUgalbbl$ / MMBTU$ / gal$ / bbl | |
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [1] | $ 264,872 |
Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [2] | 168,349 |
Natural Gas - Costless Collars | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [2] | 1,992 |
Natural Gas - Put Options - Drilling Partnerships | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [2] | 2,314 |
Natural Gas - WAHA Basis Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [3] | 41 |
Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [4] | 1,758 |
Natural Gas Liquids - Propane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [5] | 2,133 |
Natural Gas Liquids - Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [6] | 467 |
Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [7] | 460 |
Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [1] | 3,143 |
Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [1] | 83,981 |
Crude Oil Costless Collars | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | [1] | $ 234 |
Production Period Ending December 31 2015 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 26,832,200 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.193 |
Fair Value Asset | [2] | $ 34,433 |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 1,560,000 |
Fair Value Asset | [2] | $ 1,996 |
Average Floor And Cap | $ / MMBTU | [8] | 4.157 |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Calls Sold | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 1,560,000 |
Fair Value Asset | [2] | $ (4) |
Average Floor And Cap | $ / MMBTU | [8] | 5.002 |
Production Period Ending December 31 2015 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 720,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4 |
Fair Value Asset | [2] | $ 795 |
Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 2,400,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | (0.090) |
Fair Value Asset | [3] | $ 41 |
Production Period Ending December 31 2015 | Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | gal | [8] | 2,520,000 |
Derivative, Swap Type, Average Fixed Price | $ / gal | [8] | 1.936 |
Fair Value Asset | [4] | $ 1,758 |
Production Period Ending December 31 2015 | Natural Gas Liquids - Propane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | gal | [8] | 4,032,000 |
Derivative, Swap Type, Average Fixed Price | $ / gal | [8] | 1.016 |
Fair Value Asset | [5] | $ 2,133 |
Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | gal | [8] | 756,000 |
Derivative, Swap Type, Average Fixed Price | $ / gal | [8] | 1.248 |
Fair Value Asset | [6] | $ 467 |
Production Period Ending December 31 2015 | Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | gal | [8] | 756,000 |
Derivative, Swap Type, Average Fixed Price | $ / gal | [8] | 1.263 |
Fair Value Asset | [7] | $ 460 |
Production Period Ending December 31 2015 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 966,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 87.653 |
Fair Value Asset | [1] | $ 26,301 |
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 9,750 |
Fair Value Asset | [1] | $ 234 |
Average Floor And Cap | $ / bbl | [8] | 83.846 |
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Calls Sold | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 9,750 |
Average Floor And Cap | $ / bbl | [8] | 110.654 |
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 53,546,300 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.229 |
Fair Value Asset | [2] | $ 55,981 |
Production Period Ending December 31 2016 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 1,440,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.150 |
Fair Value Asset | [2] | $ 1,519 |
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 84,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 85.651 |
Fair Value Asset | [1] | $ 1,960 |
Production Period Ending December 31 2016 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 1,557,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 81.471 |
Fair Value Asset | [1] | $ 29,889 |
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 49,920,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.219 |
Fair Value Asset | [2] | $ 41,808 |
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 60,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 83.780 |
Fair Value Asset | [1] | $ 1,183 |
Production Period Ending December 31 2017 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 1,140,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 77.285 |
Fair Value Asset | [1] | $ 15,237 |
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 40,800,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.170 |
Fair Value Asset | [2] | $ 28,491 |
Production Period Ending December 31 2018 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 1,080,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 76.281 |
Fair Value Asset | [1] | $ 11,561 |
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | [8] | 15,960,000 |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | [8] | 4.017 |
Fair Value Asset | [2] | $ 7,636 |
Production Period Ending December 31 2019 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | [8] | 540,000 |
Derivative, Swap Type, Average Fixed Price | $ / bbl | [8] | 68.371 |
Fair Value Asset | [1] | $ 993 |
[1] | Fair value based on forward WTI crude oil prices, as applicable. | |
[2] | Fair value based on forward NYMEX natural gas prices, as applicable. | |
[3] | Fair value based on forward WAHA 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 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] | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. |
Fair Value of Financial Instr58
Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | $ 265,583 | $ 275,329 |
Gross Amounts of Recognized Liabilities | (711) | (468) |
Total derivatives, fair value, net | 264,872 | 274,861 |
Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 265,583 | 275,329 |
Gross Amounts of Recognized Liabilities | (711) | (468) |
Total derivatives, fair value, net | 264,872 | 274,861 |
Commodity Swaps | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 261,039 | 267,242 |
Gross Amounts of Recognized Liabilities | (707) | (401) |
Commodity Swaps | Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 261,039 | 267,242 |
Gross Amounts of Recognized Liabilities | (707) | (401) |
Commodity Puts | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 2,314 | 2,767 |
Commodity Puts | Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 2,314 | 2,767 |
Commodity Option | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 2,230 | 5,320 |
Gross Amounts of Recognized Liabilities | (4) | (67) |
Commodity Option | Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Gross Amounts of Recognized Assets | 2,230 | 5,320 |
Gross Amounts of Recognized Liabilities | $ (4) | $ (67) |
Fair Value of Financial Instr59
Fair Value of Financial Instruments - Additional Information (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Fair Value Disclosures [Abstract] | |||||
Long-term Debt, Fair Value | $ 1,307,700,000 | $ 1,307,700,000 | $ 1,219,800,000 | ||
Long-term debt | 1,491,612,000 | 1,491,612,000 | $ 1,394,460,000 | ||
Asset impairment | $ 0 | $ 0 | $ 0 | $ 0 |
Fair Value of Financial Instr60
Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||||
Fair value, liabilities | $ 47 | $ 7,326 | $ 212 | $ 7,855 |
Level 3 | ||||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||||
Fair value, liabilities | 47 | 7,326 | 212 | 7,855 |
Asset Retirement Obligations | ||||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||||
Fair value, liabilities | 47 | 7,326 | 212 | 7,855 |
Asset Retirement Obligations | Level 3 | ||||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||||
Fair value, liabilities | $ 47 | $ 7,326 | $ 212 | $ 7,855 |
Commitments and Contingencies (
Commitments and Contingencies (General Commitments) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Percentage of present value of future cash flows | 10.00% | |||
Net partnership revenues subordinated | $ 500,000 | $ 400,000 | $ 1,100,000 | $ 3,800,000 |
Long-term purchase commitment, amount | 8,200,000 | |||
GeoMet Acquisition | ||||
Contractual obligation, due in remainder of fiscal Year | 2,300,000 | 2,300,000 | ||
Contractual obligation, due in second year | 2,300,000 | 2,300,000 | ||
Contractual obligation, due in third year | 1,900,000 | 1,900,000 | ||
Contractual obligation, due in fourth year | 1,800,000 | 1,800,000 | ||
Contractual obligation, due in fifth year | 1,800,000 | 1,800,000 | ||
Contractual Obligation, Due in thereafter | 6,500,000 | 6,500,000 | ||
EP Energy Acquisition | ||||
Contractual obligation, due in remainder of fiscal Year | 4,200,000 | 4,200,000 | ||
Contractual obligation, due in second year | 2,100,000 | 2,100,000 | ||
Contractual obligation, due in third year | 0 | 0 | ||
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% | |||
Investor partners return on investment | 10.00% | |||
Maximum | ||||
Partnership obligations to purchase units from investor partners | 10.00% | |||
Percentage on unhedged revenue | 50.00% | |||
Investor partners return on investment | 12.00% |
Issuances of Units (Details)
Issuances of Units (Details) - USD ($) | Apr. 30, 2015 | Jan. 15, 2015 | May. 31, 2015 | Oct. 31, 2014 | Aug. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2015 | Jun. 30, 2015 | Jun. 30, 2014 |
Capital Unit [Line Items] | |||||||||||
Net proceeds from issuance of common limited partner units | $ 70,869,000 | $ 426,393,000 | |||||||||
Class D Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Redemption price per unit | $ 25 | ||||||||||
Class E Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Redemption price per unit | $ 25 | ||||||||||
Class E Cumulative Redeemable Perpetual Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Sale of Units | 255,000 | ||||||||||
Partners' Capital Account, Sale of Units | $ 6,000,000 | ||||||||||
Dividend percentage | 10.75% | ||||||||||
Public offer price per share | $ 25 | ||||||||||
Preferred Stock, Liquidation Preference Per Share | $ 25 | ||||||||||
Equity Distribution Agreement with Deutsche Bank Securities Inc. | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Sale of Units | 2,885,824 | ||||||||||
Aggregate Offering Price Of Common Units (Maximum) | $ 100,000,000 | ||||||||||
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | 2.00% | ||||||||||
Net proceeds from issuance of common limited partner units | $ 21,400,000 | ||||||||||
Payments for Commissions | $ 600,000 | ||||||||||
Arkoma Acquisition | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Date Of Sale | May 2,015 | ||||||||||
Partners' Capital Account, Units, Sale of Units | 6,500,000 | ||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 7.97 | ||||||||||
Partners' Capital Account, Sale of Units | $ 49,500,000 | ||||||||||
Eagle Ford Acquisition | Class D Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Date Of Sale | October 2,014 | ||||||||||
Partners' Capital Account, Units, Sale of Units | 3,200,000 | 800,000 | |||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 25 | $ 25 | |||||||||
Partners' Capital Account, Sale of Units | $ 77,300,000 | ||||||||||
Partners' Capital Account, Units, Percentage | 8.625% | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.616927 | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $ 2.15625 | ||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.625% | ||||||||||
Rangely Acquisition | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Date Of Sale | May 2,014 | ||||||||||
Partners' Capital Account, Units, Sale of Units | 15,525,000 | 15,525,000 | |||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 19.90 | ||||||||||
Partners' Capital Account, Sale of Units | $ 297,300,000 | ||||||||||
Rangely Acquisition | Over Allotment Units Issued | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Sale of Units | 2,025,000 | ||||||||||
GeoMet Acquisition | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Date Of Sale | March 2,014 | ||||||||||
Partners' Capital Account, Units, Sale of Units | 6,325,000 | ||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 21.18 | ||||||||||
Partners' Capital Account, Sale of Units | $ 129,000,000 | ||||||||||
GeoMet Acquisition | Over Allotment Units Issued | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners' Capital Account, Units, Sale of Units | 825,000 |
Cash Distributions - Additional
Cash Distributions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions | Jul. 31, 2015 | Jul. 22, 2015 | Jul. 15, 2015 | May. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Mar. 31, 2015 | Jan. 14, 2015 | Jun. 30, 2015 |
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | ||||||
Preferred Limited Partners' Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.539063 | $ 0.616927 | |||||||||||||||||||||
Subsequent Event | Cash Distribution Declared | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.1083 | $ 0.1083 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | Jul. 22, 2015 | Jul. 22, 2015 | |||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 11.2 | $ 11.2 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Aug. 14, 2015 | Aug. 14, 2015 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | Aug. 7, 2015 | Aug. 7, 2015 | |||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | General Partners’ Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 0.2 | $ 0.2 | |||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | Preferred Limited Partners' Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 0.6 | $ 0.6 | |||||||||||||||||||||
Minimum | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 13.00% | ||||||||||||||||||||||
Maximum | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 48.00% | ||||||||||||||||||||||
Preferred Class B | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | $ 0.1333 | ||||||||||||||||||||||
Preferred Class B | Minimum | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | 0.40 | ||||||||||||||||||||||
Preferred Class C | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | 0.17 | ||||||||||||||||||||||
Preferred Class C | Minimum | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | 0.51 | ||||||||||||||||||||||
Preferred Class D | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.616927 | 0.5390625 | |||||||||||||||||||||
Preferred Unit Regular Annually Cash Distributions Per Unit | $ 2.15625 | ||||||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.625% | ||||||||||||||||||||||
Preferred Class D | Subsequent Event | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.5390625 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions | $ 2.2 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions, Date of Record | Jul. 1, 2015 | ||||||||||||||||||||||
Preferred Class E | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.671875 | ||||||||||||||||||||||
Preferred Unit Regular Annually Cash Distributions Per Unit | $ 25 | ||||||||||||||||||||||
Partners' Capital Account, Units, Percentage | 10.75% | ||||||||||||||||||||||
Preferred Class E | Subsequent Event | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.6793 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions | $ 0.2 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions, Date of Record | Jul. 1, 2015 |
Cash Distributions (Schedule of
Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | |||||||||||||||||
May. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Mar. 31, 2015 | Jan. 14, 2015 | Jun. 30, 2015 | |
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | |||
Common Limited Partners’ Interests | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 10,304 | $ 10,179 | $ 9,444 | $ 9,347 | $ 9,284 | $ 16,782 | $ 16,779 | $ 16,033 | $ 16,032 | $ 16,032 | $ 16,028 | $ 16,029 | $ 15,752 | $ 15,752 | $ 12,719 | $ 12,719 | $ 12,718 | |||
Preferred Limited Partners' Interest | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.539063 | $ 0.616927 | ||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 643 | 642 | 643 | 643 | 643 | 745 | 745 | 1,491 | 1,492 | 1,491 | 1,493 | 1,492 | 1,466 | 1,466 | 1,466 | 1,466 | 1,467 | |||
General Partners’ Interest | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 223 | $ 221 | $ 206 | $ 204 | $ 203 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,377 | $ 1,279 | $ 1,279 | $ 1,054 | $ 1,055 | $ 1,055 | |||
Class D Preferred Limited Partners | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,156 | $ 1,974 | ||||||||||||||||||
Month Ended January 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Mar. 17, 2014 | |||||||||||||||||||
Month Ended February 28, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Apr. 14, 2014 | |||||||||||||||||||
Month Ended March 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | May 15, 2014 | |||||||||||||||||||
Month Ended April 30, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jun. 13, 2014 | |||||||||||||||||||
Month Ended May 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jul. 15, 2014 | |||||||||||||||||||
Month Ended June 30, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Aug. 14, 2014 | |||||||||||||||||||
Month Ended July 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Sep. 12, 2014 | |||||||||||||||||||
Month Ended August 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Oct. 15, 2014 | |||||||||||||||||||
Month Ended September 30, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Nov. 14, 2014 | |||||||||||||||||||
Month Ended October 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Dec. 15, 2014 | |||||||||||||||||||
Month Ended November 30, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jan. 14, 2015 | |||||||||||||||||||
Month Ended December 31, 2014 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Feb. 13, 2015 | |||||||||||||||||||
Month Ended January 31, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Mar. 17, 2015 | |||||||||||||||||||
Month Ended February 28, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Apr. 14, 2015 | |||||||||||||||||||
Month Ended March 31, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | May 15, 2015 | |||||||||||||||||||
Month Ended April 30, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jun. 12, 2015 | |||||||||||||||||||
Month Ended May 31, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jul. 15, 2015 | |||||||||||||||||||
October 2, 2014 to January 14, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Jan. 15, 2015 | |||||||||||||||||||
Quarter ended March 31, 2015 | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Apr. 15, 2015 |
Benefit Plan (2012 Long Term In
Benefit Plan (2012 Long Term Incentive Plan Narrative) (Details) - Jun. 30, 2015 - 2012 Long-Term Incentive Plan - shares | Total |
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 LTIP”), effective March 2012, provides incentive awards to officers, employees and directors and 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. |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 2,900,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 1,864,057 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 134,308 |
Benefit Plan (2012 LTIP Phantom
Benefit Plan (2012 LTIP Phantom Units Activity) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | $ 410,000 | |||||||||
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 | $ 200,000 | $ 400,000 | $ 500,000 | $ 1,100,000 | ||||||
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 | 191,408 | 191,408 | ||||||||
Outstanding, beginning of year (Units) | 632,010 | 812,308 | 799,192 | 839,808 | 839,808 | |||||
Granted (Units) | 9,730 | 223,523 | 9,730 | 227,023 | ||||||
Vested and issued (Units) | [1] | (222,358) | (131,374) | (389,540) | (146,874) | |||||
Forfeited (Units) | (8,125) | (3,250) | (8,125) | (18,750) | ||||||
Outstanding, end of year (Units) | 411,257 | [2],[3] | 901,207 | [2],[3] | 411,257 | [2],[3] | 901,207 | [2],[3] | 799,192 | |
Vested and not yet issued (Units) | [4] | 24,750 | 74,850 | 24,750 | 74,850 | |||||
Non-cash compensation expense recognized | $ 803,000 | $ 1,590,000 | $ 3,317,000 | $ 3,321,000 | ||||||
Outstanding, beginning of period | $ 22.37 | $ 24.35 | $ 22.70 | $ 24.31 | $ 24.31 | |||||
Granted | 8.50 | 20.29 | 8.50 | 20.30 | ||||||
Vested and issued | [1] | 24.07 | 24.69 | 24.02 | 24.48 | |||||
Forfeited | 23.04 | 24.80 | 23.04 | 23 | ||||||
Outstanding, end of period | 21.10 | [2],[3] | 23.29 | [2],[3] | 21.10 | [2],[3] | 23.29 | [2],[3] | $ 22.70 | |
Vested and not yet issued | [4] | $ 20.39 | $ 24.49 | $ 20.39 | $ 24.49 | |||||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | $ 2,000,000 | $ 2,500,000 | $ 3,600,000 | $ 2,900,000 | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 2,600,000 | 2,600,000 | ||||||||
Liabilities Related to Outstanding Phantom Units | $ 24,000 | $ 200,000 | $ 24,000 | $ 200,000 | $ 100,000 | |||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 14,005 | 25,432 | 14,005 | 25,432 | 26,579 | |||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $ 21.38 | $ 13.39 | $ 21.16 | |||||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Vested Not Issued Intrinsic Value | $ 200,000 | $ 1,500,000 | ||||||||
Unrecognized compensation expense related to unvested units | $ 3,200,000 | $ 3,200,000 | ||||||||
Unrecognized compensation expenses related to unvested, expected weighted average period | 1 year 9 months 18 days | |||||||||
Partnership 2012 Long Term Incentive Plans - Phantom Units | 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 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 values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively. | |||||||||
[2] | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 was $2.6 million. | |||||||||
[3] | There were approximately $24,000 and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 units, 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 $13.39 and $21.16 at June 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Partnership’s consolidated balance sheet at the period ended June 30, 2014 representing 25,432 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.38 at June 30, 2014. | |||||||||
[4] | The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively. |
Benefit Plan (2012 Unit Option
Benefit Plan (2012 Unit Option Activity) (Details) - Partnership 2012 Long Term Incentive Plans - Unit Options - USD ($) | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |||
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 | 106,949 | 106,949 | ||||
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) | 1,453,300 | 1,472,675 | 1,458,300 | 1,482,675 | ||
Forfeited (Units) | (500) | (3,750) | (5,500) | (13,750) | ||
Outstanding, end of period (Units) | [1],[2] | 1,452,800 | 1,468,925 | 1,452,800 | 1,468,925 | |
Options exercisable (Units) | [3] | 1,342,976 | 734,400 | 1,342,976 | 734,400 | |
Non-cash compensation expense recognized | $ 61,000 | $ 420,000 | $ 892,000 | $ 1,033,000 | ||
Outstanding, beginning of year | $ 24.66 | $ 24.66 | $ 24.66 | $ 24.66 | [1],[2] | |
Forfeited | 25.14 | 24.67 | 24.71 | 24.40 | ||
Outstanding, end of period | [1],[2] | 24.66 | 24.66 | 24.66 | 24.66 | |
Options exercisable, end of period | [3] | $ 24.67 | $ 24.67 | $ 24.67 | $ 24.67 | |
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 | 6 years 10 months 24 days | |||||
Aggregate Intrinsic Value Of Options Outstanding | 0 | 2,000 | $ 0 | 2,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 6 years 10 months 24 days | |||||
Aggregate Intrinsic Value Of Options Exercisable | 0 | $ 0 | $ 0 | $ 0 | ||
Unrecognized compensation expense related to unvested unit options | $ 100,000 | $ 100,000 | ||||
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. | |||||
Unrecognized compensation expenses related to unvested, expected weighted average period | 9 months 18 days | |||||
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] | The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 years | |||||
[2] | There was no aggregate intrinsic value of options outstanding at June 30, 2015. The aggregate intrinsic value of options outstanding at June 30, 2014 was approximately $2,000. | |||||
[3] | The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 years. There were no intrinsic values for options exercisable at June 30, 2015 and 2014 |
Operating Segment Information68
Operating Segment Information (Narrative) (Details) | 6 Months Ended |
Jun. 30, 2015Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating Segment Information69
Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Segment Reporting Information [Line Items] | |||||
Revenues | $ 96,125 | $ 138,897 | $ 339,714 | $ 300,254 | |
Depreciation, depletion and amortization expense | (42,494) | (59,680) | (85,485) | (111,499) | |
Segment income (loss) | (8,904) | 15,190 | 121,011 | 36,372 | |
Gas And Oil Production | |||||
Segment Reporting Information [Line Items] | |||||
Revenues | 70,316 | 108,237 | 280,150 | 208,494 | |
Operating costs and expenses | (43,135) | (43,122) | (88,633) | (81,647) | |
Depreciation, depletion and amortization expense | (39,362) | (57,194) | (79,480) | (106,789) | |
Segment income (loss) | (12,181) | 7,921 | 112,037 | 20,058 | |
Well Construction And Completion | |||||
Segment Reporting Information [Line Items] | |||||
Revenues | 16,956 | 16,336 | 40,611 | 65,713 | |
Operating costs and expenses | (14,745) | (14,206) | (35,315) | (57,142) | |
Segment income (loss) | 2,211 | 2,130 | 5,296 | 8,571 | |
Other Partnership Management | |||||
Segment Reporting Information [Line Items] | |||||
Revenues | [1] | 8,853 | 14,324 | 18,953 | 26,047 |
Operating costs and expenses | [1] | (4,655) | (6,699) | (9,270) | (13,594) |
Depreciation, depletion and amortization expense | [1] | (3,132) | (2,486) | (6,005) | (4,710) |
Segment income (loss) | [1] | $ 1,066 | $ 5,139 | $ 3,678 | $ 7,743 |
[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 Information70
Operating Segment Information (Reconciliation of Segment Income (loss) to Net Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Segment Reporting Information [Line Items] | |||||
Total segment income (loss) | $ (8,904) | $ 15,190 | $ 121,011 | $ 36,372 | |
General and administrative expenses | [1] | (13,287) | (21,315) | (30,422) | (37,770) |
Interest expense | [1] | (24,716) | (13,263) | (49,913) | (26,451) |
Gain (loss) on asset sales and disposal | [1] | 97 | 9 | 86 | (1,594) |
Net income (loss) | (46,810) | (19,379) | 40,762 | (29,443) | |
Gas And Oil Production | |||||
Segment Reporting Information [Line Items] | |||||
Total segment income (loss) | (12,181) | 7,921 | 112,037 | 20,058 | |
Well Construction And Completion | |||||
Segment Reporting Information [Line Items] | |||||
Total segment income (loss) | 2,211 | 2,130 | 5,296 | 8,571 | |
Other Partnership Management | |||||
Segment Reporting Information [Line Items] | |||||
Total segment income (loss) | [2] | $ 1,066 | $ 5,139 | $ 3,678 | $ 7,743 |
[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 Information71
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Segment Reporting Information [Line Items] | |||||
Total revenues | $ 96,125 | $ 138,897 | $ 339,714 | $ 300,254 | |
Gas And Oil Production | |||||
Segment Reporting Information [Line Items] | |||||
Total revenues | 70,316 | 108,237 | 280,150 | 208,494 | |
Well Construction And Completion | |||||
Segment Reporting Information [Line Items] | |||||
Total revenues | 16,956 | 16,336 | 40,611 | 65,713 | |
Other Partnership Management | |||||
Segment Reporting Information [Line Items] | |||||
Total revenues | [1] | $ 8,853 | $ 14,324 | $ 18,953 | $ 26,047 |
[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 Information72
Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Segment Reporting Information [Line Items] | ||||
Capital expenditures | $ 26,993 | $ 54,718 | $ 69,491 | $ 94,649 |
Gas And Oil Production | ||||
Segment Reporting Information [Line Items] | ||||
Capital expenditures | 24,041 | 48,810 | 56,233 | 83,794 |
Other Partnership Management | ||||
Segment Reporting Information [Line Items] | ||||
Capital expenditures | 2,700 | 4,259 | 12,794 | 7,632 |
Corporate and Other | ||||
Segment Reporting Information [Line Items] | ||||
Capital expenditures | $ 252 | $ 1,649 | $ 464 | $ 3,223 |
Operating Segment Information73
Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Goodwill, net | $ 13,639 | $ 13,639 |
Total assets | 2,701,094 | 2,791,553 |
Gas And Oil Production | ||
Segment Reporting Information [Line Items] | ||
Total assets | 2,522,853 | 2,601,171 |
Well Construction And Completion | ||
Segment Reporting Information [Line Items] | ||
Goodwill, net | 6,389 | 6,389 |
Total assets | 7,133 | 39,558 |
Other Partnership Management | ||
Segment Reporting Information [Line Items] | ||
Goodwill, net | 7,250 | 7,250 |
Total assets | 66,752 | 65,896 |
Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | $ 104,356 | $ 84,928 |
Subsequent Events (Cash Distrib
Subsequent Events (Cash Distribution) (Details) - USD ($) $ / shares in Units, $ in Thousands | Jul. 31, 2015 | Jul. 22, 2015 | Jul. 15, 2015 | Jul. 15, 2015 | May. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Mar. 31, 2015 | Jan. 14, 2015 |
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1966 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | $ 0.1933 | ||||||
Cash Distribution Declared | Subsequent Event | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | Jul. 22, 2015 | Jul. 22, 2015 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.1083 | $ 0.1083 | |||||||||||||||||||||
Cash Distribution Paid | Subsequent Event | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 11,200 | $ 11,200 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | Aug. 14, 2015 | Aug. 14, 2015 | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | Aug. 7, 2015 | Aug. 7, 2015 | |||||||||||||||||||||
Cash Distribution Paid | Subsequent Event | Class D Cumulative Redeemable Perpetual Preferred Units | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | Jul. 1, 2015 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.5390625 | ||||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,200 | ||||||||||||||||||||||
Cash Distribution Paid | Subsequent Event | Class E Cumulative Redeemable Perpetual Preferred Units | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | Jul. 1, 2015 | ||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.6793 | ||||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 200 | ||||||||||||||||||||||
General Partners’ Interest | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 223 | $ 221 | $ 206 | $ 204 | $ 203 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,378 | $ 1,377 | $ 1,279 | $ 1,279 | $ 1,054 | $ 1,055 | $ 1,055 | ||||||
General Partners’ Interest | Cash Distribution Paid | Subsequent Event | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 200 | $ 200 | |||||||||||||||||||||
Preferred Limited Partners' Interest | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ 0.539063 | $ 0.616927 | |||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 643 | $ 642 | $ 643 | $ 643 | $ 643 | $ 745 | $ 745 | $ 1,491 | $ 1,492 | $ 1,491 | $ 1,493 | $ 1,492 | $ 1,466 | $ 1,466 | $ 1,466 | $ 1,466 | $ 1,467 | ||||||
Preferred Limited Partners' Interest | Cash Distribution Paid | Subsequent Event | |||||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 600 | $ 600 |