Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of outstanding common units of the registrant on May 5, 2014 was 51,878,278.

	March 31,		December 31,
ASSETS	2014		2013
Current assets:
Cash and cash equivalents	$	24,779	$	23,501
Accounts receivable		327,031		279,464
Current portion of derivative asset		161		2,066
Subscriptions receivable		—		47,692
Prepaid expenses and other		42,213		27,612
Total current assets		394,184		380,335
Property, plant and equipment, net		5,024,505		4,910,875
Intangible assets, net		655,679		697,234
Investment in joint ventures		269,058		248,301
Goodwill, net		402,180		400,356
Long-term derivative asset		28,325		30,868
Other assets, net		124,305		124,672
	$	6,898,236	$	6,792,641
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	2,794	$	2,924
Accounts payable		187,899		149,279
Liabilities associated with drilling contracts		—		49,377
Accrued producer liabilities		191,066		152,309
Current portion of derivative liability		36,929		17,630
Accrued interest		21,689		47,402
Accrued well drilling and completion costs		72,158		40,899
Accrued liabilities		76,475		87,435
Total current liabilities		589,010		547,255
Long-term debt, less current portion		2,830,337		2,886,120
Deferred income taxes, net		32,892		33,290
Asset retirement obligations		92,927		91,214
Other long-term liabilities		12,702		11,886
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests		345,045		361,511
Accumulated other comprehensive income		2,140		10,338
		347,185		371,849
Non-controlling interests		2,993,183		2,851,027
Total partners’ capital		3,340,368		3,222,876
	$	6,898,236	$	6,792,641

	Three Months Ended March 31,
	2014			2013
Revenues:
Gas and oil production	$	100,825		$	46,064
Well construction and completion		49,377			56,478
Gathering and processing		710,980			420,087
Administration and oversight		1,729			1,085
Well services		5,479			4,816
Loss on mark-to-market derivatives		(8,671	)		(12,083	)
Other, net		543			5,655
Total revenues		860,262			522,102
Costs and expenses:
Gas and oil production		38,758			15,216
Well construction and completion		42,936			49,112
Gathering and processing		604,954			351,741
Well services		2,482			2,318
General and administrative		48,402			40,658
Depreciation, depletion and amortization		101,278			51,666
Total costs and expenses		838,810			510,711
Operating income		21,452			11,391
Loss on asset sales and disposal		(1,603	)		(702	)
Interest expense		(41,314	)		(25,810	)
Loss on early extinguishment of debt		—			(26,582	)
Net loss before tax		(21,465	)		(41,703	)
Income tax benefit		(398	)		(9	)
Net loss		(21,067	)		(41,694	)
Loss attributable to non-controlling interests		7,142			29,098
Net loss attributable to common limited partners	$	(13,925	)	$	(12,596	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.27	)	$	(0.25	)
Weighted average common limited partner units outstanding:
Basic and Diluted		51,491			51,369

	Common Limited Partners’ Capital					Accumulated Other Comprehensive			Non- Controlling			Total Partners’
	Units		Amount			Income			Interest			Capital
Balance January 1, 2014		51,413,564	$	361,511		$	10,338		$	2,851,027		$	3,222,876
Distributions to non-controlling interests		—		—			—			(80,711	)		(80,711	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—			6,840			6,840
Unissued common units under incentive plan		—		7,601			—			8,645			16,246
Issuance of units under incentive plans		454,251		—			—			87			87
Distributions paid to common limited partners		—		(23,681	)		—			—			(23,681	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(1,011	)		—			(1,524	)		(2,535	)
Distributions payable by Atlas Resource Partners, L.P.		—		—			—			(9,565	)		(9,565	)
Gain on sale of subsidiary unit issuances		—		14,550			—			(14,550	)		—
Non-controlling interests’ capital contributions		—		—			—			253,564			253,564
Other comprehensive loss		—		—			(8,198	)		(13,488	)		(21,686	)
Net loss		—		(13,925	)		—			(7,142	)		(21,067	)
Balance at March 31, 2014		51,867,815	$	345,045		$	2,140		$	2,993,183		$	3,340,368

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(21,067	)	$	(41,694	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		101,278			51,666
Amortization of deferred financing costs		4,109			6,246
Non-cash compensation expense		16,805			14,153
Loss on asset sales and disposal		1,603			702
Deferred income tax benefit		(398	)		(9	)
Loss on early extinguishment of debt		—			26,582
Distributions paid to non-controlling interests		(82,235	)		(47,998	)
Equity (income) loss in unconsolidated companies		1,683			(2,039	)
Distributions received from unconsolidated companies		2,311			1,804
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(15,501	)		53,580
Accounts payable and accrued liabilities		(9,031	)		(84,766	)
Net cash used in operating activities		(443	)		(21,773	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(172,750	)		(167,003	)
Investment in joint venture		(1,903	)		—
Other		(2,519	)		(1,498	)
Net cash used in investing activities		(177,172	)		(168,501	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		484,500			400,000
Repayments under credit facilities		(540,100	)		(743,925	)
Net proceeds from issuance of subsidiary long-term debt		—			905,016
Repayments of subsidiary long-term debt		—			(365,822	)
Net proceeds from subsidiary equity offerings		253,564			14,144
Distributions paid to unitholders		(23,681	)		(15,410	)
Contributions from non-controlling interests		6,840			—
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt		—			(25,562	)
Deferred financing costs, distribution equivalent rights and other		(2,230	)		(3,539	)
Net cash provided by financing activities		178,893			164,902
Net change in cash and cash equivalents		1,278			(25,372	)
Cash and cash equivalents, beginning of year		23,501			36,780
Cash and cash equivalents, end of period	$	24,779		$	11,408

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS). At March 31, 2014, the Partnership’s operations primarily consisted of its ownership interests in the following:

In February 2012, the board of directors (“the Board”) of the Partnership’s General Partner (“the General Partner”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2013 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014.

The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at March 31, 2014, except for ARP, APL and the Development Subsidiary, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP, APL and the Development Subsidiary, the Partnership consolidates the financial statements of ARP, APL and the Development Subsidiary into its consolidated financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP, APL and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP 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 ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated financial statements include APL’s 95% ownership interest in joint ventures, which individually own a 100% ownership interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided interest in the WestTX natural gas gathering system and processing plants. These joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE).

APL consolidates 100% of these joint ventures and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint venture as a component of partners’ capital on its consolidated balance sheets (see Note 4).

The West TX joint venture has a 72.8% undivided joint venture interest in the WestTX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the WestTX system’s status as an undivided joint venture, the WestTX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the WestTX system.

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 months ended March 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”).

Accounts receivable on the consolidated balance sheets consist primarily of the trade accounts receivable associated with the Partnership and its subsidiaries. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership and its subsidiaries extend credit on sales on an unsecured basis to many of its customers. At March 31, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

The Partnership had $32.0 million and $19.7 million of inventory at March 31, 2014 and December 31, 2013, respectively, which were included within prepaid expenses and other current assets on its consolidated balance sheets. The Partnership and its subsidiaries value inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price.

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components, is recorded to accumulated depreciation. 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 consolidated statements of operations.

The Partnership and ARP follow 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 natural gas liquids 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 and ARP’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 ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP 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 proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon 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.

The Partnership and its subsidiaries review their 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 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 and ARP’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 and ARP estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’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 ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’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 and ARP cannot predict what reserve revisions may be required in future periods.

ARP’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 ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP 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 ARP 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 ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’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 that the Partnership and ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by ARP for the three months ended March 31, 2014 and 2013.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. There were no impairments of proved gas and oil properties recorded by ARP for the three months ended March 31, 2014 and 2013.

The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

ARP and APL capitalize 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 rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 5.6% and 6.1% for the three months ended March 31, 2014 and 2013, respectively. The aggregate amounts of interest capitalized by ARP and APL were $5.5 million and $5.9 million for the three months ended March 31, 2014 and 2013, respectively.

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, including the TEAK acquisition (see Note 3), over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess of or less than the average length. As part of the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 3), APL recognized $450.0 million of customer relationships with an estimated useful life of 13 years.

Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP 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 March 31, 2014 and December 31, 2013 (in thousands):

	March 31, 2014			December 31, 2013			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	871,072		$	891,072			2–15
Partnership management and operating contracts		14,344			14,344			13
	$	885,416		$	905,416
Accumulated Amortization:
Customer contracts and relationships	$	(216,288	)	$	(194,801	)
Partnership management and operating contracts		(13,449	)		(13,381	)
	$	(229,737	)	$	(208,182	)
Net Carrying Amount:
Customer contracts and relationships	$	654,784		$	696,271
Partnership management and operating contracts		895			963
	$	655,679		$	697,234

Amortization expense on intangible assets was $21.6 million and $8.2 million for the three months ended March 31, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $80.3 million; 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; and 2018 - $59.6 million.

The following table reflects the carrying amounts of goodwill by reportable operating segments at March 31, 2014 and December 31, 2013 (in thousands):

At March 31, 2014, the Partnership had $402.2 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $370.4 million related to APL’s Cardinal Acquisition in 2012 and TEAK Acquisition in 2013. The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position and potential future synergies. The goodwill related to APL’s TEAK Acquisition is a result of the strategic industry position. The change in APL’s goodwill during the three months ended March 31, 2014 is primarily related to a $1.8 million increase in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 3).

ARP and APL test goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’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 assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to 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 ARP’s and APL’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, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise.

Subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired. APL performed a qualitative assessment for goodwill impairment of APL’s gas treating reporting unit. The assessment indicated the potential for goodwill to be impaired due to lower forecasted cash flows as compared to original forecasts. Using a combination of discounted cash flow models and market multiples for similar businesses, APL measured the amount of goodwill impairment to be $43.9 million, which was recorded within asset impairment on the Partnership’s consolidated statement of operations for the year ended December 31, 2013.

During the three months ended March 31, 2014 and 2013, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership.

The Partnership and ARP recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities (see Note 7). The Partnership and ARP also recognize a liability for their respective 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations it owns and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of March 31, 2014 or December 31, 2013 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

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 (loss) reported 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 months ended March 31, 2014 and 2013.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2014, except for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011.

Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal acquisition in 2012, the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of March 31, 2014 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 11).

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 net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

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. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 16), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights 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):

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, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 16).

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):

Accrued producer liabilities on the Partnership’s consolidated balance sheets represent APL’s accrued purchase commitments payable to producers related to the natural gas gathered and processed through its system under its Percentage of Proceeds (“POP”) and Keep-Whole contracts (see “Revenue Recognition”).

Natural gas and oil production. The Partnership and ARP generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, 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 or ARP has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay ARP the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, ARP classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated statements of operations.

ARP’s Gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga Shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing, treating and transportation operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs, if any, at delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas and NGLs is recognized upon physical delivery. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers:

The Partnership and its subsidiaries accrue unbilled revenue and APL accrues the related purchase costs due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate 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” for further description). The Partnership and its subsidiaries had unbilled revenues at March 31, 2014 and December 31, 2013 of $268.9 million and $191.8 million, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at March 31, 2014 and December 31, 2013 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets.

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 9). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (see Note 8), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 14). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing July 31, 2013.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

On May 7, 2013, APL completed the TEAK Acquisition for $974.7 million in cash, including final purchase price adjustments, less cash received. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in Texas, which includes a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”).

Subsequent to the closing of the TEAK Acquisition, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 on May 10, 2013 for net proceeds of $391.2 million to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 8).

APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet for the year ended December 31, 2013. In conjunction with APL’s issuance of the 4.75% APL Senior Notes and an amendment to its revolving credit facility (see Note 8), APL recorded $9.7 million of transaction fees as deferred financing costs, which are included in other assets, net on the Partnership’s consolidated balance sheet at December 31, 2013. All other costs associated with the acquisition were expensed as incurred.

Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. On May 5, 2014, closing of the transaction was approved by GeoMet’s shareholder vote, and is expected to occur during the second quarter of 2014, subject to certain customary closing conditions.

In September 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013.

In July 2013, the Partnership completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of the Partnership’s term loan facility (see Note 8). The Arkoma Acquisition had an effective date of May 1, 2013.

APL has a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (NYSE: CVX), which owns the remaining 80% interest. APL accounts for its ownership interest in WTLPG under the equity method of accounting, with recognition of its ownership interest in the income of WTLPG included within other, net on the Partnership’s consolidated statements of operations. In May 2014, APL entered into a definitive agreement to sell its interest in WTLPG to Martin Midstream Partners, L.P. (see Note 18).

On May 7, 2013, APL acquired a 75% interest in T2 LaSalle, a 50% interest in T2 Eagle Ford and a 50% interest in T2 EF Co-Gen as part of the TEAK Acquisition (see Note 3). The T2 Joint Ventures are operated by TexStar Midstream Services, L.P. (“TexStar”), which owns the remaining interests. The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. APL accounts for its investments in the joint ventures under the equity method of accounting. APL’s proportionate share of the net income (loss) of the T2 Joint Ventures is included within other, net on the Partnership’s consolidated statement of operations for the three months ended March 31, 2014 and 2013.

APL evaluated whether the T2 Joint Ventures should be subject to consolidation. The T2 Joint Ventures do meet the qualifications of a Variable Interest Entity (“VIE”), but APL does not meet the qualifications as the primary beneficiary. Even though APL owns a 50% or greater interest in the T2 Joint Ventures, APL does not have controlling financial interests in these entities. Since APL shares equal management rights with TexStar, and TexStar is the operator of the T2 Joint Ventures, APL determined that it is not the primary beneficiary of the VIEs and should not consolidate the T2 Joint Ventures. APL accounts for its investment in the T2 Joint Ventures under the equity method, since APL does not have a controlling financial interest, but does have a significant influence. APL’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment; any additional capital contribution commitments and APL’s share of any approved operating expenses incurred by the VIEs.

The following tables present the values of APL’s equity method investments as of March 31, 2014 and December 31, 2013 and equity income (loss) in joint ventures as of March 31, 2014 and 2013 (in thousands):

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

	March 31,			December 31,			Estimated Useful Lives
	2014			2013			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	323,698		$	322,217
Pre-development costs		4,066			4,367
Wells and related equipment		2,280,114			2,231,213
Total proved properties		2,607,878			2,557,797
Unproved properties		216,691			211,851
Support equipment		26,656			23,258
Total natural gas and oil properties		2,851,225			2,792,906
Pipelines, processing and compression facilities		3,063,750			2,926,134			2–40
Rights of way		195,518			203,966			20–40
Land, buildings and improvements		29,735			30,216			3–40
Other		37,372			36,752			3–10
		6,177,600			5,989,974
Less – accumulated depreciation, depletion and amortization		(1,153,095	)		(1,079,099	)
	$	5,024,505		$	4,910,875

During the three months ended March 31, 2014, the Partnership and its subsidiaries recognized $1.6 million of loss on asset disposal, primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. During the three months ended March 31, 2013, ARP recognized a $0.7 million loss on asset disposal pertaining to its decision not to drill wells on leasehold property that expired during the three months ended March 31, 2013 in Indiana and Tennessee.

During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

The following is a summary of other assets at the dates indicated (in thousands):

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 8). Amortization expense of the Partnership and its subsidiaries’ deferred financing costs was $4.1 million and $3.0 million for the three months ended March 31, 2014 and 2013, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2013, ARP recognized an additional $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of 7.75% senior unsecured notes due 2021 (see Note 8). During the three months ended March 31, 2013, APL recorded an additional $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% senior unsecured notes due June 15, 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 8). There was no accelerated amortization of deferred financing costs for the three months ended March 31, 2014.

ARP notes receivable. At March 31, 2014 and December 31, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets on the Partnership’s consolidated balance sheet. 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 closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For the three months ended March 31, 2014, $23,000 of interest income was recognized within other, net on the Partnership’s consolidated statement of operations. There was no interest income recognized for the three months ended March 31, 2013. At March 31, 2014 and December 31, 2013, ARP recorded no allowance for credit losses within the Partnership’s consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At March 31, 2014, the Partnership owned an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended March 31, 2014 and 2013, the Partnership recognized equity income of approximately $0.2 million and equity loss of approximately $1,000, respectively, within other, net on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2014 and 2013, the Partnership received net cash distributions of approximately $0.4 million and approximately $4,000, respectively.

On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”.

The Partnership and ARP recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Partnership and ARP also recognized a liability for their respective future asset retirement obligations 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, 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 and ARP have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership and ARP’s gas and oil properties, the Partnership and its subsidiaries determined that there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At March 31, 2014, the Drilling Partnerships had $57.9 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP 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. During the three months ended March 31, 2014, ARP withheld approximately $0.6 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the three months ended March 31, 2013. ARP’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, ARP 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, ARP’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 ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

A reconciliation of the Partnership and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations in the Partnership’s consolidated balance sheets. During the year ended December 31, 2013, the Partnership incurred $1.3 million of future plugging and abandonment costs related to the Arkoma Acquisition it consummated during the period. During the year ended December 31, 2013, ARP incurred $16.7 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period.

	March 31,			December 31,
	2014			2013
Term loan facility	$	238,800		$	239,400
Revolving credit facility		—			—
ARP revolving credit facility		366,000			419,000
ARP 7.75% Senior Notes – due 2021		275,000			275,000
ARP 9.25% Senior Notes – due 2021		248,388			248,334
APL revolving credit facility		150,000			152,000
APL 6.625% Senior Notes – due 2020		504,387			504,556
APL 5.875% Senior Notes – due 2023		650,000			650,000
APL 4.750% Senior Notes – due 2021		400,000			400,000
APL capital leases		556			754
Total debt		2,833,131			2,889,044
Less current maturities		(2,794	)		(2,924	)
Total long-term debt	$	2,830,337		$	2,886,120

On July 31, 2013, in connection with the Arkoma Acquisition (see Note 3), the Partnership entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). At March 31, 2014, $238.8 million was outstanding under the Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at the Partnership’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by the Partnership. The Partnership is required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At March 31, 2014, the weighted average interest rate on outstanding borrowings under the term facility was 6.5%.

The Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 the Partnership’s assets. The Term Facility also contains covenants that require (i) the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions (see Note 3). At March 31, 2014, the Partnership was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

The Partnership’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under its Term Facility are guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of the Partnership’s subsidiaries, other than the subsidiary guarantors, are minor. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and the Partnership’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

On July 31, 2013, in connection with the Arkoma Acquisition (see Note 3), the Partnership amended its credit facility with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At March 31, 2014, no amounts were outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility are guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of the Partnership’s subsidiaries, other than the subsidiary guarantors, are minor. At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

The credit facility contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 the Partnership’s assets. The credit facility also contains covenants the same as those in the Partnership’s Term Facility with respect to (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At March 31, 2014, the Partnership was in compliance with these covenants. Based on the definition in the Partnership’s Term Facility and credit facility, the Partnership’s ratio of Total Funded Debt to EBITDA was 2.3 to 1.0.

The credit facility is subject to an intercreditor agreement as described above under the “Partnership’s Term Loan Facility”.

At March 31, 2014, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

At March 31, 2014, ARP has a credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”) that provides for a senior secured revolving credit facility with a maximum facility amount of $1.5 billion scheduled to mature in July 2018. ARP’s borrowing base under the credit facility, which was $735.0 million at March 31, 2014, is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At March 31, 2014, $366.0 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 $3.7 million was outstanding at March 31, 2014. ARP’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 ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.75% 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 0.75% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At March 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.3%.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of March 31, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to four quarters of EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014 and 4.0 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit agreement, at March 31, 2014, ARP’s ratio of current assets to current liabilities was 2.1 to 1.0, and its ratio of Total Funded Debt to EBITDA was 3.9 to 1.0.

On March 31, 2014, ARP had $275.0 million principal outstanding of 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) and $250.0 million principal outstanding of 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”). On July 30, 2013, ARP issued $250.0 million of its 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% ARP Senior Notes were presented net of a $1.6 million unamortized discount as of March 31, 2014. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes due 2021, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes and used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the three months ended March 31, 2013 (see Note 6). Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable 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% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP 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. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes and the exchange offer was completed on January 2, 2014.

The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are full and unconditional and joint and several, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain covenants, including limitations of ARP’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 ARP’s assets. ARP was in compliance with these covenants as of March 31, 2014.

At March 31, 2014, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $150.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at March 31, 2014 was 3.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2014. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at March 31, 2014. At March 31, 2014, APL had $449.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK, West TX and Centrahoma joint ventures and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies.

The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default under the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner.

On March 11, 2014, APL entered into an amendment to the credit agreement governing its revolving credit facility which, among other changes:

At March 31, 2014, APL had $400.0 million of 4.75% Senior Notes due 2021 (“4.75% APL Senior Notes”), $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $500.0 million principal outstanding of 6.625% unsecured senior notes due October 1, 2020 (“6.625% APL Senior Notes”) (collectively, the “APL Senior Notes”).

On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014.

On February 11, 2013, APL issued $650.0 million of the 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million after underwriting commissions and other transaction costs and utilized the proceeds to redeem APL’s previously outstanding 8.75% unsecured senior notes due June 15, 2018 (“8.75% APL Senior Notes”) and repay a portion of the outstanding indebtedness under its revolving credit agreement. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014.

The 6.625% APL Senior Notes are presented combined with a net $4.4 million unamortized premium as of March 31, 2014. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% APL Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture.

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million 8.75% APL Senior Notes not purchased in connection with the tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes. During the three months ended March 31, 2013, APL recorded a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid; $8.0 million consent payment; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium.

The APL Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including its obligations under its revolving credit facility.

Indentures governing the APL Senior Notes contain covenants, including limitations on APL’s ability to: incur certain liens; engage in sale/leaseback transactions; 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 its assets. APL was in compliance with these covenants as of March 31, 2014.

The following is a summary of the leased property under capital leases as of March 31, 2014 and December 31, 2013, which are included within property, plant and equipment, net (see Note 5) (in thousands):

In March 2014, APL took ownership of $1.1 million of facilities in connection with the conclusion of a capital lease. During the year ended December 31, 2013, APL accelerated payment on certain leases and purchased the leased property by paying approximately $7.5 million in accordance with the lease agreements. These leases were to mature in August 2013.

Depreciation expense for leased properties was approximately $32,000 and $0.2 million for the three months ended March 31, 2014 and 2013, respectively. Depreciation expense for leased properties is included within depreciation, depletion and amortization expense on the Partnership’s consolidated statements of operations.

Cash payments for interest by the Partnership and its subsidiaries were $38.8 million and $26.7 million for the three months ended March 31, 2014 and 2013, respectively.

The Partnership and its subsidiaries use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. The Partnership and its subsidiaries enter 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 or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership and its subsidiaries occasionally enter 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 and its subsidiaries receive or pay 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.

The Partnership and ARP apply the principles of hedge accounting for derivatives qualifying as hedges. Accordingly, the Partnership and ARP formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership and ARP assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and ARP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership and ARP recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income (loss) and reclassify the portion relating to the Partnership and ARP’s commodity derivatives within gas and oil production revenues and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations as they occur.

APL does not apply the principles of hedge accounting to its derivative instruments. Accordingly, any changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. APL recognizes the portion relating to commodity derivatives within gathering and processing revenues on the Partnership’s consolidated statement of operations as the derivative instruments are settled.

The Partnership and its subsidiaries enter 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 and its subsidiaries enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their 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. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative liabilities on its consolidated balance sheets of $8.5 million and net derivative assets of $14.9 million at March 31, 2014 and December 31, 2013, respectively. Of the $2.1 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at March 31, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $7.8 million of losses to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $9.9 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. No amounts were reclassified from other comprehensive income related to derivative instruments entered into during the three months ended March 31, 2014 and 2013.

The following table summarizes the Partnership’s and ARP’s gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands):

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 as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of March 31, 2014
Long-term portion of derivative assets	$	1,367	$	—		$	1,367
Total derivative assets	$	1,367	$	—		$	1,367
As of December 31, 2013
Current portion of derivative assets	$	24	$	(23	)	$	1
Long-term portion of derivative assets		1,547		(33	)		1,514
Current portion of derivative liabilities		63		(63	)		—
Total derivative assets	$	1,634	$	(119	)	$	1,515

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of March 31, 2014
Current portion of derivative liabilities	$	(770	)	$	—	$	(770	)
Total derivative liabilities	$	(770	)	$	—	$	(770	)
As of December 31, 2013
Current portion of derivative assets	$	(23	)	$	23	$	—
Long-term portion of derivative assets		(33	)		33		—
Current portion of derivative liabilities		(96	)		63		(33	)
Total derivative liabilities	$	(152	)	$	119	$	(33	)

During the three months ended March 31, 2014, the Partnership recorded losses of $0.5 million on settled derivative contracts within its consolidated statements of operations. These losses were included within gas and oil production revenue in the Partnership’s consolidated statement of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statements of operations for the three months ended March 31, 2013 as the Partnership had no derivative contracts in those months. 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 months ended March 31, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

In connection with the Arkoma Acquisition, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to the Arkoma assets acquired from EP Energy (see Note 3). In connection with the swaption contacts, the Partnership paid premiums of $2.3 million which represented their fair value on the date the transactions were initiated, were initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and were fully amortized into other, net on the Partnership’s consolidated statement of operations as of September 30, 2013.

The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of March 31, 2014
Current portion of derivative assets	$	161	$	—		$	161
Long-term portion of derivative assets		25,859		(2,110	)		23,749
Current portion of derivative liabilities		4,382		(4,382	)		—
Long-term portion of derivative liabilities		114		(114	)		—
Total derivative assets	$	30,516	$	(6,606	)	$	23,910
As of December 31, 2013
Current portion of derivative assets	$	2,664	$	(773	)	$	1,891
Long-term portion of derivative assets		31,146		(4,062	)		27,084
Current portion of derivative liabilities		4,341		(4,341	)		—
Long-term portion of derivative liabilities		122		(122	)		—
Total derivative assets	$	38,273	$	(9,298	)	$	28,975

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of March 31, 2014
Current portion of derivative assets	$	—		$	—	$	—
Long-term portion of derivative assets		(2,110	)		2,110		—
Current portion of derivative liabilities		(26,754	)		4,382		(22,372	)
Long-term portion of derivative liabilities		(127	)		114		(13	)
Total derivative liabilities	$	(28,991	)	$	6,606	$	(22,385	)
As of December 31, 2013
Current portion of derivative assets	$	(773	)	$	773	$	—
Long-term portion of derivative assets		(4,062	)		4,062		—
Current portion of derivative liabilities		(10,694	)		4,341		(6,353	)
Long-term portion of derivative liabilities		(189	)		122		(67	)
Total derivative liabilities	$	(15,718	)	$	9,298	$	(6,420	)

ARP recognized losses of $14.0 million and gains of $1.0 million for the three months ended March 31, 2014, and 2013, respectively, on settled contracts covering commodity production. These gains and losses were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in ARP’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 months ended March 31, 2014 and 2013, respectively for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At March 31, 2014, ARP had net cash proceeds of $1.9 million related to hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of March 31, 2014 and December 31, 2013.

In June 2012, ARP 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 March 31, 2014, net unrealized derivative assets of $1.1 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At March 31, 2014, ARP 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 8), ARP 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. ARP, 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 Partnerships’ 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.

The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of March 31, 2014
Long-term portion of derivative assets	$	5,336	$	(2,127	)	$	3,209
Current portion of derivative liabilities		2,082		(2,082	)		—
Total derivative assets	$	7,418	$	(4,209	)	$	3,209
As of December 31, 2013
Current portion of derivative assets	$	1,310	$	(1,136	)	$	174
Long-term portion of derivative assets		5,082		(2,812	)		2,270
Current portion of derivative liabilities		1,612		(1,612	)		—
Long-term portion of derivative liabilities		949		(949	)		—
Total derivative assets	$	8,953	$	(6,509	)	$	2,444

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of March 31, 2014
Long-term portion of derivative assets	$	(2,127	)	$	2,127	$	—
Current portion of derivative liabilities		(15,869	)		2,082		(13,787	)
Total derivative liabilities	$	(17,996	)	$	4,209	$	(13,787	)
As of December 31, 2013
Current portion of derivative assets	$	(1,136	)	$	1,136	$	—
Long-term portion of derivative assets		(2,812	)		2,812		—
Current portion of derivative liabilities		(12,856	)		1,612		(11,244	)
Long-term portion of derivative liabilities		(1,269	)		949		(320	)
Total derivative liabilities	$	(18,073	)	$	6,509	$	(11,564	)

Production Period	Purchased/ Sold	Commodity	Volumes⁽¹⁾		Average Fixed Price		Fair Value Asset/(Liability) (in thousands)⁽²⁾
Natural Gas
2014	Sold	Natural Gas		12,690,000	$	4.029	$	(5,555	)
2015	Sold	Natural Gas		18,610,000	$	4.244		592
2016	Sold	Natural Gas		7,950,000	$	4.277		779
2017	Sold	Natural Gas		600,000	$	4.455		23
Natural Gas Liquids
2014	Sold	Natural Gas Liquids		60,354,000	$	1.198		(5,123	)
2015	Sold	Natural Gas Liquids		41,076,000	$	1.079		(1,993	)
2016	Sold	Natural Gas Liquids		6,300,000	$	1.034		(85	)
Crude Oil
2014	Sold	Crude Oil		219,000	$	91.062		(1,672	)
2015	Sold	Crude Oil		60,000	$	85.130		(298	)
Total Fixed Price Swaps							$	(13,332	)

Production Period	Purchased/ Sold		Type		Commodity		Volumes⁽¹⁾		Average Strike Price		Fair Value Asset/(Liability) (in thousands)⁽²⁾
Natural Gas
2014		Purchased		Put		Natural Gas		500,000	$	4.130	$	60
Natural Gas Liquids
2014		Purchased		Put		Natural Gas Liquids		6,930,000	$	0.960		135
2014		Sold		Call		Natural Gas Liquids		3,780,000	$	1.318		(27	)
2015		Purchased		Put		Natural Gas Liquids		3,150,000	$	0.941		155
2015		Sold		Call		Natural Gas Liquids		1,260,000	$	1.275		(46	)
Crude Oil
2014		Purchased		Put		Crude Oil		267,000	$	90.413		657
2015		Purchased		Put		Crude Oil		270,000	$	89.175		1,820
Total Options											$	2,754
								APL’s net liability			$	(10,578	)

The following tables summarize APL’s derivatives not designated as hedges, which are included within gain on mark-to market derivatives on the Partnerships consolidated statements of operations:

The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands):

The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them 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 and its subsidiaries 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.

The Partnership and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 9). The Partnership and its subsidiaries manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. The Partnership and its subsidiaries’ commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, 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.

Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which are considered to be Level 3 inputs. The prices for propane, iso butane, normal butane and natural gasoline are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is an unobservable Level 3 input. The NGL fixed price swaps are over the counter instruments which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3. The NGL options are over the counter instruments that are not actively traded in an open market, thus APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade. These valuations are tested for reasonableness through the use of an internal valuation model.

Information for ARP’s and APL’s assets and liabilities measured at fair value at March 31, 2014 and December 31, 2013 was as follows (in thousands):

	Level 1		Level 2			Level 3			Total
As of March 31, 2014
Derivative assets, gross
Commodity swaps	$	—	$	1,367		$	—		$	1,367
ARP Commodity swaps		—		26,771			—			26,771
ARP Commodity basis swaps		—		159			—			159
ARP Commodity puts		—		1,144			—			1,144
ARP Commodity options		—		2,442			—			2,442
APL Commodity swaps		—		3,189			1,402			4,591
APL Commodity options		—		2,537			290			2,827
Total derivative assets, gross		—		37,609			1,692			39,301
Derivative liabilities, gross
Commodity swaps		—		(770	)		—			(770	)
ARP Commodity swaps		—		(27,556	)		—			(27,556	)
ARP Commodity basis swaps		—		(201	)		—			(201	)
ARP Commodity options		—		(1,234	)		—			(1,234	)
APL Commodity swaps		—		(9,320	)		(8,603	)		(17,923	)
APL Commodity options		—		—			(73	)		(73	)
Total derivative liabilities, gross		—		(39,081	)		(8,676	)		(47,757	)
Total derivatives, fair value, net	$	—	$	(1,472	)	$	(6,984	)	$	(8,456	)
As of December 31, 2013
Derivative assets, gross
Commodity swaps	$	—	$	1,634		$	—		$	1,634
ARP Commodity swaps		—		33,594			—			33,594
ARP Commodity puts		—		1,374			—			1,374
ARP Commodity options		—		3,305			—			3,305
APL Commodity swaps		—		2,994			1,412			4,406
APL Commodity options		—		4,337			210			4,547
Total derivative assets, gross		—		47,238			1,622			48,860
Derivative liabilities, gross
Commodity swaps		—		(152	)		—			(152	)
ARP Commodity swaps		—		(14,624	)		—			(14,624	)
ARP Commodity options		—		(1,094	)		—			(1,094	)
APL Commodity swaps		—		(4,695	)		(13,378	)		(18,073	)
Total derivative liabilities, gross		—		(20,565	)		(13,378	)		(33,943	)
Total derivatives, fair value, net	$	—	$	26,673		$	(11,756	)	$	14,917

APL’s Level 3 fair value amounts relate to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the periods indicated (in thousands):

	NGL Fixed Price Swaps						NGL Put Options						NGL Call Options					Total
	Gallons			Amount			Gallons			Amount			Gallons		Amount			Amount
Balance – January 1, 2014		130,158		$	(11,966	)		6,300		$	210			—		—		$	(11,756	)
New contracts⁽¹⁾		—			—			5,040			200			5,040		(200	)		—
Cash settlements from unrealized gain (loss)⁽²⁾⁽³⁾		(22,428	)		5,873			(1,260	)		137			—		—			6,010
Net change in unrealized gain (loss)⁽²⁾		—			(1,108	)		—			(120	)		—		127			(1,101	)
Option premium recognition⁽³⁾		—			—			—			(137	)		—		—			(137	)
Balance – March 31, 2014		107,730			(7,201	)		10,080			290			5,040		(73	)		(6,984	)

The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at March 31, 2014 and December 31, 2013 (in thousands):

	Gallons		Third Party Quotes⁽¹⁾			Adjustments⁽²⁾			Total Amount
As of March 31, 2014
Propane swaps		83,538	$	(6,059	)	$	—		$	(6,059	)
Iso butane swaps		5,040		(1,405	)		651			(754	)
Normal butane swaps		5,040		483			192			675
Natural gasoline swaps		14,112		(276	)		(787	)		(1,063	)
Total NGL swaps — March 31, 2014		107,730	$	(7,257	)	$	56		$	(7,201	)
As of December 31, 2013
Propane swaps		100,296	$	(10,260	)	$	—		$	(10,260	)
Iso butane swaps		6,300		(2,342	)		955			(1,387	)
Normal butane swaps		7,560		40			322			362
Natural gasoline swaps		16,002		132			(813	)		(681	)
Total NGL swaps — December 31, 2013		130,158	$	(12,430	)	$	464		$	(11,966	)

The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL fixed price swaps for the periods indicated (in thousands):

				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of March 31, 2014
Iso butane swaps	$	651		$	1.1168	$	1.1271	$	1.1219
Normal butane swaps		192			1.0341		1.0382		1.0361
Natural gasoline swaps		(787	)		0.9685		0.9716		0.9701
Total NGL swaps – March 31, 2014	$	56
As of December 31, 2013
Iso butane swaps	$	955			1.1184		1.1284		1.1234
Normal butane swaps		322			1.0341		1.0386		1.0364
Natural gasoline swaps		(813	)		0.9727		0.9751		0.9739
Total NGL swaps – December 31, 2013	$	464

APL had $21.7 million and $14.5 million of NGL linefill at March 31, 2014 and December 31, 2013, respectively, which were included within prepaid expenses and other on the Partnership’s consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill held by some counterparties will be settled at various periods in the future and is defined as a Level 3 asset, which is valued using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of $0.4 million and $0.4 million as of March 31, 2014 and December 31, 2013, respectively. APL’s NGL linefill held by other counterparties is adjusted on a monthly basis according to the volumes delivered to the counterparties each period and is valued on a first in first out (“FIFO”) basis.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the three months ended March 31, 2014 (in thousands):

	Linefill Valued at Market				Linefill Valued on FIFO						Total NGL Linefill
	Gallons		Amount		Gallons			Amount			Gallons			Amount
Balance – January 1, 2014		5,788	$	4,739		11,538		$	9,778			17,326		$	14,517
Deliveries into NGL linefill		1,050		1,013		25,600			16,875			26,650			17,888
NGL linefill sales		—		—		(20,622	)		(10,847	)		(20,622	)		(10,847	)
Net change in NGL linefill valuation⁽¹⁾		—		143		—			—			—			143
Balance – March 31, 2014		6,838	$	5,895		16,516		$	15,806			23,354		$	21,701

The estimated fair value of the Partnership and its subsidiaries’ 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 and its subsidiaries could realize upon the sale or refinancing of such financial instruments.

The Partnership and its subsidiaries’ 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 and its subsidiaries’ debt at March 31, 2014 and December 31, 2013, which consist principally of ARP’s and APL’s senior notes and borrowings under the Partnership’s, ARP’s and APL’s revolving and term loan credit facilities, were $2,875.0 million and $2,841.7 million, respectively, compared with the carrying amounts of $2,833.1 million and $2,889.0 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP and APL senior notes were based upon the market approach and calculated using the yields of the ARP and APL senior notes as provided by financial institutions and thus were categorized as a Level 3 value.

The Partnership and ARP estimate the fair value of their respective 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 ARP and estimated inflation rates (see Note 7).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2014 and 2013 was as follows (in thousands):

The Partnership and its subsidiaries estimate the fair value of its long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2013, ARP recognized $38.0 million of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized during the three months ended March 31, 2014 and 2013.

During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimates of fair value of the EP Energy and TEAK acquisitions as of their respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of March 31, 2014, are subject to change as the final valuations have not yet been completed, and such changes may 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 and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 7). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuation and are subject to change.

In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million in contingent payments, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. Sufficient volumes were achieved in December 2012, and APL paid the first contingent payment of $6.0 million in January 2013. As of March 31, 2014, the fair value of the remaining contingent payment resulted in a $6.0 million long-term liability, which was recorded within other long-term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amounts APL could pay related to the remaining contingent payment is up to $6.0 million.

APL owns a taxable subsidiary. The components of the federal and state income tax expense (benefit) for APL’s taxable subsidiary for the three months ended March 31, 2014 and 2013 are as follows (in thousands):

As of March 31, 2014 and December 31, 2013, APL had non-current net deferred income tax liabilities of $32.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of March 31, 2014 and December 31, 2013 consist of the following (in thousands):

As of March 31, 2014, APL had net operating loss carry forwards for federal income tax purposes of approximately $40.1 million, which expire at various dates from 2029 to 2034. APL believes it more likely than not that the deferred tax asset will be fully utilized. APL expects all goodwill recorded to be deductible for tax purposes.

Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP 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. ARP 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.

Relationship between ARP and APL. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For the three month periods ended March 31, 2014 and 2013, $0.1 million and $0.1 million, respectively, of gathering fees paid by ARP to APL were eliminated in consolidation.

Relationship with Resource America, Inc. In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVC”), which is a joint-venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. The Partnership’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and the Partnership’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President and Resource America, Inc.

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by ARP, as managing general partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of March 31, 2014, the management of ARP believes that any such liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from certain of the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to eight years, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2014 and 2013, $3.5 million and $2.1, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

The Partnership and its subsidiaries are party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

In connection with ARP’s EP Energy Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of March 31, 2014 were as follows: 2014—$6.6 million; 2015—$8.6 million; 2016—$2.1 million; and 2017 to 2018—none.

APL has certain long-term unconditional purchase obligations and commitments, primarily transportation contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts, including minimum shipment payments, were $7.3 million and $3.0 million for the three months ended March 31, 2014 and 2013, respectively. The future fixed and determinable portions of APL’s obligations as of March 31, 2014 were as follows: remainder of 2014—$6.3 million; 2015 to 2017—$3.5 million per year; and 2018—$2.7 million.

As of March 31, 2014, the Partnership and its subsidiaries are committed to expend approximately $84.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

The Partnership and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe 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.

The Partnership recognizes gains on ARP’s and APL’s equity transactions as credits to partners’ capital on its consolidated balance sheets rather than as income on its consolidated statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

In July 2013, in connection with ARP’s EP Energy Acquisition (see Note 3), the Partnership purchased 3,746,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, the Partnership, as purchaser of the Class C preferred units, also received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

In March 2014, ARP 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. The units were registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 3), ARP issued 3,749,986 newly created Class C convertible preferred units to the Partnership at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at the Partnership’s option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act (see “Purchase of ARP Preferred Units”).

Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

In June 2013, in connection with the EP Energy Acquisition (see Note 3), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 8).

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated the equity distribution agreement effective December 27, 2013.

At March 31, 2014 and December 31, 2013, in connection with the issuance of ARP’s common units, the Partnership recorded gains of $14.6 million and $27.3 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital.

In March 2014, APL issued 5,060,000 of its Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. APL received $122.4 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility.

APL will make cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions will be payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units will be payable on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million. Thereafter, APL will pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year.

At any time on or after March 17, 2019, or in the event of a liquidation or certain changes of control, APL may redeem the Class E 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 on the date of redemption, whether or not declared. If APL does not exercise this redemption right upon a change of control, then the holders of the Class E Preferred Units will have the option to convert their Class E Preferred Units into a number of APL’s common units, as set forth in the Certificate of Designation relating to the Class E Preferred Units.

In May 2013, APL issued Class D Preferred Units in a private placement transaction to third party investors which are presented combined with a net $50.2 million unaccreted beneficial conversion discount within non-controlling interests on the Partnership’s consolidated balance sheet at March 31, 2014. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the three months ended March 31, 2014, APL recorded $11.4 million within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the beneficial conversion discount.

The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of the Partnership, as general partner. For the three months ended March 31, 2014, APL recorded Class D Preferred Unit distributions in kind of $9.7 million within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2014, APL distributed 274,785 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution in kind. APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the three months ended March 31, 2014.

APL had an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL offered and sold through Citigroup, as its sales agent, common units for $150.0 million. Sales were at market prices prevailing at the time of the sale. During the three year period ended December 31, 2013, APL issued 3,895,679 common units under the equity distribution program for net proceeds of $137.8 million, net of $2.8 million in sales commissions incurred and other offering costs. APL also received capital contributions from the Partnership of $2.9 million during the year ended December 31, 2013 to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering for general partnership purposes. As of December 31, 2013, APL had used the full capacity under the equity distribution program.

In April 2013, APL sold 11,845,000 of its common units in a public offering at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from the Partnership of $8.3 million to maintain its 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see Note 3).

At December 31, 2013, in connection with the issuance of APL’s common units, the Partnership recorded an $11.9 million gain, respectively, within partner’s capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital. No gain or loss was recorded within partners’ capital for the three months ended March 31, 2014.

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts):

On April 23, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $23.9 million distribution will be paid on May 20, 2014 to unitholders of record at the close of business on May 7, 2014.

ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby the monthly cash distribution will be paid within 45 days from the month end. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.

Distributions declared by ARP for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter/ Month Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners		Total Cash Distribution to the General Partner
May 15, 2013	March 31, 2013	$	0.5100	$	22,428	$	1,957	$	946
August 14, 2013	June 30, 2013	$	0.5400	$	32,097	$	2,072	$	1,884
November 14, 2013	September 30, 2013	$	0.5600	$	33,291	$	4,248	$	2,443
February 14, 2014	December 31, 2013	$	0.5800	$	34,489	$	4,400	$	2,891

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

On April 23, 2014, ARP declared its monthly distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014.

APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.

Common unit and general partner distributions declared by APL for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts):

On April 22, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, will be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. Based on this declaration, APL will issue approximately 317,000 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended March 31, 2014 (see Note 18).

The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At March 31, 2014, the Partnership had 4,454,130 phantom units and unit options outstanding under the 2010 LTIP, with 1,217,255 phantom units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2010 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 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 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 Partnership’s 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):

2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units granted to employees under the 2010 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2010 LTIP at March 31, 2014, there are 1,243,877 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, the Partnership paid $0.9 million and $0.6 million, respectively, with respect to the 2010 LTIP DERs.

The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		2,054,534		$	22.56		2,044,227		$	20.88
Granted		—			—		—			—
Vested and issued⁽¹⁾		(38,335	)		20.29		(2,936	)		17.47
Forfeited		(11,768	)		27.25		—			—
Outstanding, end of period⁽²⁾		2,004,431		$	22.57		2,041,291		$	20.88
Vested and not yet issued⁽³⁾		344,553		$	20.60		—		$	—
Non-cash compensation expense recognized (in thousands)				$	2,928				$	3,108

At March 31, 2014, the Partnership had approximately $13.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are 1,723,698 unit options outstanding under the 2010 LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013, respectively.

The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		2,452,412		$	20.52		2,504,703		$	20.51
Granted		—			—		—			—
Exercised⁽¹⁾		—			—		—			—
Forfeited		(2,713	)		17.47		(2,604	)		17.47
Outstanding, end of period⁽²⁾⁽³⁾		2,449,699		$	20.52		2,502,099		$	20.52
Options exercisable, end of period⁽⁴⁾		569,368		$	20.43		3,398		$	20.85
Non-cash compensation expense recognized (in thousands)				$	1,438				$	1,515

At March 31, 2014, the Partnership had approximately $4.2 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The Board of Directors approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At March 31, 2014, the Partnership had 1,534,966 phantom units and unit options outstanding under the 2006 LTIP, with 339,639 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2006 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2006 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.

2006 Phantom Units. Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2006 LTIP at March 31, 2014, 264,859 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at March 31, 2014 include DERs.

During the three months ended March 31, 2014 and 2013, the Partnership paid $0.1 million with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets.

The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		234,940		$	35.82		50,759		$	21.02
Granted		423,837			43.23		204,777			37.92
Vested and issued^{(1) (2)}		(63,750	)		35.33		(5,500	)		18.16
Forfeited		—			—		—			—
Outstanding, end of period⁽³⁾⁽⁴⁾		595,027		$	41.15		250,036		$	34.92
Vested and not yet issued⁽⁵⁾		11,497		$	37.68		—		$	—
Non-cash compensation expense recognized (in thousands)				$	2,988				$	1,147

At March 31, 2014, the Partnership had approximately $19.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. There are 2,500 unit options outstanding under the 2006 LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013.

The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

	Three Months Ended March 31,
	2014				2013
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		939,939	$	20.94		929,939	$	20.75
Granted		—		—		10,000		38.51
Exercised⁽¹⁾		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of year⁽²⁾⁽³⁾		939,939	$	20.94		939,939	$	20.94
Options exercisable, end of period⁽⁴⁾⁽⁵⁾		932,439	$	20.80		929,939	$	20.75
Non-cash compensation expense recognized (in thousands)			$	7			$	7

At March 31, 2014, the Partnership had approximately $33,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,0000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At March 31, 2014, ARP had 2,284,983 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 372,711 phantom units, restricted units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP 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 ARP 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 Partnership, as 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):

ARP Phantom Units. Phantom units granted under the ARP 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 ARP LTIP at March 31, 2014, 275,545 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, ARP paid $0.6 million and $0.5 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheets.

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		839,808		$	24.31		948,476		$	24.76
Granted		3,500			20.99		83,250			21.96
Vested and issued⁽¹⁾		(15,500	)		22.69		(2,465	)		24.67
Forfeited		(15,500	)		22.63		(4,000	)		25.14
Outstanding, end of period⁽²⁾⁽³⁾		812,308		$	24.35		1,025,261		$	24.53
Vested and not yet issued⁽⁴⁾		6,875		$	22.76		—		$	—
Non-cash compensation expense recognized (in thousands)				$	1,731				$	3,053

At March 31, 2014, ARP had approximately $6.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.

ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 367,575 unit options outstanding under the ARP LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Units			Weighted Average Exercise Price		Number of Units			Weighted Average Exercise Price
Outstanding, beginning of year		1,482,675		$	24.66		1,515,500		$	24.68
Granted		—			—		2,000			22.27
Exercised⁽¹⁾		—			—		—			—
Forfeited		(10,000	)		23.40		(4,000	)		25.14
Outstanding, end of period⁽²⁾⁽³⁾		1,472,675		$	24.66		1,513,500		$	24.67
Options exercisable, end of period⁽⁴⁾		368,825		$	24.67		—		$	—
Non-cash compensation expense recognized (in thousands)				$	612				$	1,194

At March 31, 2014, ARP had approximately $2.2 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by APL’s compensation committee (the “APL LTIP Committee”). Under the APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At March 31, 2014, APL had 1,664,642 phantom units outstanding under the APL LTIPs, with 608,369 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options that have vested and have been exercised. Share based payments to non-employees that have a cash settlement option are recognized within liabilities in the consolidated financial statements based upon their current fair market value. There were no unit options outstanding as of March 31, 2014.

APL Phantom Units. Through March 31, 2014, phantom units granted under the APL LTIPs generally had vesting periods of four years. However, in February 2014, APL granted 227,000 phantom units which had a vesting period of three years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of APL’s board automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at March 31, 2014, 531,244 phantom units will vest within the following twelve months. APL is authorized to purchase common units from employees to cover employee-related taxes when certain phantom units have vested.

All phantom units outstanding under the APL LTIPs at March 31, 2014 include DERs. The amounts paid with respect to APL LTIP DERs were $0.9 million and $0.6 million, respectively, for the three months ended March 31, 2014 and 2013, respectively. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet.

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2014					2013
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		1,446,553		$	36.32		1,053,242		$	33.21
Granted		234,701			31.03		6,804			33.06
Vested and issued⁽¹⁾		(14,412	)		34.03		(2,963	)		28.94
Forfeited		(2,200	)		39.51		—			—
Outstanding, end of period⁽²⁾⁽³⁾		1,664,642		$	35.59		1,057,083		$	33.22
Non-cash compensation expense recognized (in thousands)				$	6,439				$	4,384

At March 31 2014, APL had approximately $31.5 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.0 years.

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 March 31,
	2014			2013
Atlas Resource:
Revenues	$	157,345		$	112,048
Operating costs and expenses		(103,078	)		(88,626	)
Depreciation, depletion and amortization expense		(50,237	)		(21,208	)
Loss on asset sales and disposal		(1,603	)		(702	)
Interest expense		(13,188	)		(6,889	)
Segment loss	$	(10,761	)	$	(5,377	)
Atlas Pipeline:
Revenues	$	698,089		$	409,952
Operating costs and expenses		(618,138	)		(361,718	)
Depreciation, depletion and amortization expense		(49,239	)		(30,458	)
Loss on asset sales and disposal		—			—
Interest expense		(23,663	)		(18,686	)
Loss on early extinguishment of debt		—			(26,582	)
Segment income (loss)	$	7,049		$	(27,492	)
Corporate and other:
Revenues	$	4,828		$	102
Operating costs and expenses		(15,918	)		(8,692	)
Depreciation, depletion and amortization expense		(1,802	)		—
Loss on asset sales and disposal		—			—
Interest expense		(4,463	)		(235	)
Segment loss	$	(17,355	)	$	(8,825	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(10,761	)	$	(5,377	)
Atlas Pipeline		7,049			(27,492	)
Corporate and other		(17,355	)		(8,825	)
Net loss	$	(21,067	)	$	(41,694	)
Capital expenditures:
Atlas Resource	$	39,897		$	58,487
Atlas Pipeline		128,331			108,516
Corporate and other		4,522			—
Total capital expenditures	$	172,750		$	167,003

Cash Distribution. On April 23, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common units, representing the cash distribution for the quarter ended March 31, 2014. The $23.9 million distribution will be paid on May 20, 2014 to unitholders of record at the close of business on May 7, 2014.

Cash Distribution. On April 23, 2014, ARP declared a cash distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014.

Merit Acquisition. On May 7, 2014, ARP entered into a definitive purchase and sale agreement to acquire Merit Energy Company’s (“Merit”) non-operated producing oil wells in the Rangely field of northwest Colorado for $420 million in cash, subject to customary closing adjustments. The transaction is expected to close during the second quarter of 2014 and has an effective date of April 1, 2014. In connection with the transaction, on May 8, 2014, ARP issued 13,500,000 of its common limited partner units in a public offering at a price of $19.18 per unit, yielding net proceeds of approximately $258.7 million.

Sale of WTLPG. On May 5, 2014, APL entered into a definitive agreement to sell its 20% interest in WTLPG to Martin Midstream Partners, L.P. for $135.0 million in cash, subject to certain customary closing adjustments. The proceeds from the sale will be used to repay borrowings outstanding on APL’s credit facility.

Distribution. On April 22, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, will be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. Based on this declaration, APL will also issue approximately 317,000 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended March 31, 2014.

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2013. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

We are a publicly-traded Delaware master limited partnership, whose common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “ATLS”.

At March 31, 2014, our operations primarily consisted of our ownership interests in the following:

Our consolidated financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at March 31, 2014, except for ARP, APL and our Development Subsidiary, which we control. Due to the structure of our ownership interests in ARP, APL and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP, APL and our Development Subsidiary into our consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP, APL and our Development Subsidiary are reflected as income attributable to non-controlling interests in our consolidated statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP, APL and our Development Subsidiary, adjusted for non-controlling interests in ARP, APL and our Development Subsidiary. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

Cash Distribution. On April 23, 2014, we declared a cash distribution of $0.46 per unit on our outstanding common units, representing the cash distribution for the quarter ended March 31, 2014. The $23.9 million distribution will be paid on May 20, 2014 to unitholders of record at the close of business on May 7, 2014.

Distribution. On April 22, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $56.1 million distribution, including $6.1 million to us as general partner, will be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. Based on this declaration, APL will also issue approximately 317,000 Class D convertible preferred units (“Class D Preferred Units”) to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended March 31, 2014.

GeoMet Acquisition. On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. On May 5, 2014, closing of the transaction was approved by GeoMet’s shareholder vote, and is expected to occur during the second quarter of 2014, subject to certain customary closing conditions.

Cash Distribution Practice. On January 29, 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby the monthly cash distribution will be paid within 45 days from the month end.

Issuance of Preferred Units. On March 17, 2014, APL issued 5,060,000 of its Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to the public at an offering price of $25.00 per Class E Preferred Unit. APL received $122.4 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility (see “Issuance of Units”).

Amendment to Credit Facility. On March 11, 2014, APL entered into an amendment to its credit agreement governing its revolving credit facility which, among other changes:

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our and ARP’s gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the majority of our and ARP’s production areas are as follows:

We and ARP attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

ARP holds firm transportation obligations on Colorado Interstate Gas for the benefit of production from the Raton Basin in the New Mexico/Colorado Area. The total of firm transportation held is approximately 82,500 dth/d at a weighted average rate of $0.2575/MMBtu under contracts expiring in 2014 and 2016.

Crude Oil. Crude oil produced from our and ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We and ARP do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our and ARP’s NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage

retention by the processing and fractionation facility. We and ARP do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

ARP generally funds a portion of its drilling activities through sponsorship of tax-advantaged Drilling Partnerships. In addition to providing capital for its drilling activities, ARP’s Drilling Partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the Drilling Partnerships, ARP receives the following fees:

APL’s principal revenue is generated from the gathering, processing and treating of natural gas, the sale of natural gas, NGLs and condensate, the transportation of NGLs and the leasing of gas treating facilities. Variables that affect its revenue are:

We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.

The areas in which we and ARP operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including the continued development of advanced horizontal and multiple fracturing techniques. While we and ARP anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our and ARP’s future gas and oil reserves, production, cash flow, the ability to make payments on debt and the ability to make distributions to unitholders, including ARP’s ability to make distributions to us, depend on our and ARP’s success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. We and ARP face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas production from particular wells decrease. We and ARP attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry segment is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

APL faces competition in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to, and in some cases lower than, its own. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL’s. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. APL management believes the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. APL management believes offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows it to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s Percentage of Proceeds (“POP”) and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGL and crude oil. APL management believes future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL management generally expects NGL prices to follow changes in crude oil prices over the long term, which management believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered, processed and treated.

Production Profile. At March 31, 2014, our consolidated gas and oil production revenues and expenses consists of our and ARP’s gas and oil production activities. Currently, our gas and oil production entails the production generated by our assets acquired in the Arkoma Acquisition and our wells drilled in the Marble Falls play. ARP has focused its natural gas, crude oil and NGL production operations in various shale plays throughout the United States. ARP had certain agreements which restricted its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which expired on February 17, 2014. Through March 31, 2014, we and ARP have established production positions in the following operating areas:

The following table presents the number of wells we and ARP drilled and the number of wells we and ARP turned in line, both gross and for our and ARP’s interest, during the three months ended March 31, 2014 and 2013:

Production Volumes. The following table presents total net natural gas, crude oil, and NGL production volumes and production per day for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014		2013
Production:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (MMcf)		1,035		—
Oil (000’s Bbls)		5		—
Natural gas liquids (000’s Bbls)		3		—
Total (MMcfe)		1,079		—
Atlas Resource:
Natural gas (MMcf)		19,502		9,653
Oil (000’s Bbls)		141		99
Natural gas liquids (000’s Bbls)		308		288
Total (MMcfe)		22,196		11,974
Total production:
Natural gas (MMcf)		20,537		9,653
Oil (000’s Bbls)		146		99
Natural gas liquids (000’s Bbls)		311		288
Total (MMcfe)		23,276		11,974
Production per day:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (Mcfd)		11,502		—
Oil (Bpd)		50		—
Natural gas liquids (Bpd)		31		—
Total (Mcfed)		11,991		—
Atlas Resource:
Natural gas (Mcfd)		216,688		107,255
Oil (Bpd)		1,568		1,101
Natural gas liquids (Bpd)		3,422		3,197
Total (Mcfed)		246,628		133,039
Total production per day:
Natural gas (Mcfd)		228,191		107,255
Oil (Bpd)		1,618		1,101
Natural gas liquids (Bpd)		3,453		3,197
Total (Mcfed)		258,619		133,039

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised all of our proved reserves and 83% of ARP’s proved reserves on an energy equivalent basis at December 31, 2013. The following table presents production revenues and average sales prices for our and ARP’s natural gas, oil, and natural gas liquids production for the three months ended March 31, 2014 and 2013, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

	Three Months Ended March 31,
	2014		2013
Production revenues (in thousands):
Atlas Energy:
Natural gas revenue	$	4,123	$	—
Oil revenue		375		—
Natural gas liquids revenue		82		—
Total revenues	$	4,580	$	—
Atlas Resource:
Natural gas revenue	$	74,190	$	29,056
Oil revenue		12,283		8,806
Natural gas liquids revenue		9,772		8,202
Total revenues	$	96,245	$	46,064
Total production revenues:
Natural gas revenue	$	78,313	$	29,056
Oil revenue		12,658		8,806
Natural gas liquids revenue		9,854		8,202
Total revenues	$	100,825	$	46,064
Average sales price:
Atlas Energy:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge	$	3.98	$	—
Total realized price, before hedge	$	4.49	$	—
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	82.71	$	—
Total realized price, before hedge	$	82.71	$	—
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	29.28	$	—
Total realized price, before hedge	$	29.28	$	—

	Three Months Ended March 31,
	2014		2013
Atlas Resource:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	4.07	$	3.33
Total realized price, before hedge⁽²⁾	$	4.68	$	2.90
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	87.04	$	88.89
Total realized price, before hedge	$	93.18	$	90.80
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	31.73	$	28.51
Total realized price, before hedge	$	35.65	$	28.74
Total:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	4.06	$	3.33
Total realized price, before hedge⁽²⁾	$	4.67	$	2.90
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	86.90	$	88.89
Total realized price, before hedge	$	92.86	$	90.80
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	31.71	$	28.51
Total realized price, before hedge	$	35.60	$	28.74
Production costs (per Mcfe):⁽¹⁾
Atlas Energy:
Lease operating expenses	$	1.03	$	—
Production taxes		0.29		—
Transportation and compression		0.50		—
	$	1.82	$	—
Atlas Resource:
Lease operating expenses⁽³⁾	$	1.17	$	0.97
Production taxes		0.27		0.22
Transportation and compression		0.29		0.16
	$	1.73	$	1.35
Total production costs:
Lease operating expenses⁽³⁾	$	1.16	$	0.97
Production taxes		0.27		0.22
Transportation and compression		0.30		0.16
	$	1.74	$	1.35

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Total production revenues were $100.8 million for the three months ended March 31, 2014, an increase of $54.7 million from $46.1 million for the three months ended March 31, 2013. This increase consisted primarily of a $46.6 million increase attributable to our and ARP’s newly acquired coal-bed methane assets, a $4.0 million increase attributable to ARP’s Mississippi Lime/Hunton assets primarily due to the production from new Mississippi Lime wells drilled, a $3.1 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled and a $0.6 million increase attributable to our and ARP’s Barnett Shale/Marble Falls operations due primarily to ARP’s new Marble Falls wells drilled, partially offset by a $0.2 million decrease in ARP’s other operating areas due primarily to the natural decline of producing wells.

Total production costs were $38.8 million, an increase of $23.6 million from $15.2 million for the three months ended March 31, 2013. This increase consisted of an $18.1 million increase attributable to production costs associated with our and ARP’s newly acquired coal-bed methane assets, a $3.8 million increase attributable to our and ARP’s Barnett Shale/Marble Falls assets due primarily to new Marble Falls well connections, a $1.4 million increase attributable to ARP’s Appalachia operations due primarily to ARP’s new Marcellus and Utica Shale wells in Northeastern Pennsylvania, and a $1.1 million increase attributable to ARP’s Mississippi Lime/Hunton assets due primarily to new well connections, partially offset by a $0.8 million increase in the credit received against ARP’s lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.74 per Mcfe for the three months ended March 31, 2014 from $1.35 per Mcfe for the comparable prior year period primarily as a result of the increases in our oil and natural gas liquids production. In general, production costs per Mcfe related to oil and natural gas liquids production are higher than production costs per Mcfe for dry natural gas production.

Drilling Program Results. At March 31, 2014, our consolidated well construction and completion revenues and expenses consist solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its Drilling Partnerships during the three months ended March 31, 2014 and 2013. There were no exploratory wells drilled during the three months ended March 31, 2014 and 2013:

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships ARP sponsors. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Well construction and completion segment margin was $6.4 million for the three months ended March 31, 2014, a decrease of $1.0 million from $7.4 million for the three months ended March 31, 2013. This decrease consisted of a $3.9 million decrease associated with ARP’s lower gross profit margin per well, partially offset by a $2.9 million increase related to a higher number of wells recognized for revenue within ARP’s Drilling Partnerships. Average revenue and cost per well decreased between periods due primarily to capital deployed for lower cost Marble Falls wells within ARP’s Drilling Partnerships during the three months ended March 31, 2014 compared with capital deployed for higher cost Marcellus Shale wells during the prior year period. Since ARP’s drilling contracts with the Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in ARP’s average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills.

At March 31, 2014, our consolidated administration and oversight revenues and expenses consist solely of ARP’s activities. Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP receives a lower administration and oversight fee related to shallow, vertical wells it drills within the Drilling Partnerships, such as those in the Marble Falls and Niobrara Shale, as compared to deep, horizontal wells, such as those drilled in the Marcellus and Utica Shales.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Administration and oversight fee revenues were $1.7 million for the three months ended March 31, 2014, an increase of $0.6 million from $1.1 million for the three months ended March 31, 2013. This increase was due to increases in the number of wells spud within the current period compared with the prior year, particularly within the Marble Falls and Mississippi Lime Shale.

At March 31, 2014, our consolidated well services revenues and expenses consist solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Well services revenues were $5.5 million for the three months ended March 31, 2014, an increase of $0.7 million from $4.8 million for the three months ended March 31, 2013. Well services expenses were $2.5 million for the three months ended March 31, 2014, an increase of $0.2 million from $2.3 million for the three months ended March 31, 2013. The increase in well services revenue is primarily related to the increased utilization of ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls plays by ARP’s Drilling Partnership wells. The increase in well services expense is primarily related to higher labor costs.

Gathering and processing margin includes the gathering and processing fees and related expenses for APL and ARP. The following table presents ARP’s and APL’s gathering and processing revenues and expenses for each of the respective periods:

	Three Months Ended March 31,
	2014			2013
Gathering and Processing:
Atlas Resource:
Revenue	$	4,468		$	3,585
Expense⁽¹⁾		(4,358	)		(4,342	)
Gross Margin	$	110		$	(757	)
Atlas Pipeline:
Revenue⁽¹⁾	$	706,512		$	416,502
Expense		(600,596	)		(347,399	)
Gross Margin	$	105,916		$	69,103
Total:⁽¹⁾
Revenue	$	710,980		$	420,087
Expense		(604,954	)		(351,741	)
Gross Margin	$	106,026		$	68,346

Generally, ARP charges a gathering fee to its Drilling Partnership wells equivalent to the fees it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. ARP’s net gathering and processing margin for the three months ended March 31, 2014 was $0.1 million, a favorable movement of $0.9 million compared with net processing expense of $0.8 million for the three months ended March 31, 2013. This favorable movement was principally due to an increase in gathering fees from ARP’s new Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

APL’s Gathering and Processing Profile. At March 31, 2014, APL’s gathering and processing volumes are generated through its operations in the following areas:

The following table presents APL’s production volumes per day and average sales prices for its natural gas, oil, and natural gas liquids production for the three months ended March 31, 2014 and 2013:

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Gathering and processing margin for APL was $105.9 million for the three months ended March 31, 2014 compared with $69.1 million for the three months ended March 31, 2013. This increase was due principally to higher production volumes, including the new volumes from the SouthTX system due to the TEAK Acquisition.

Loss on mark-to-market derivatives principally reflects the change in fair value of APL’s commodity derivatives that will settle in future periods, as APL does not apply hedge accounting to its derivatives. While APL utilizes either quoted market prices or observable market data to calculate the fair value of its natural gas and crude oil derivatives, valuations of APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of its NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for APL’s fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact our net income, though it would have no impact on our liquidity or capital resources. We recognized losses of $1.1 million and $2.4 million for the three months ended March 31, 2014 and 2013, respectively, for APL’s mark-to-market gain (loss) on derivatives valued upon unobservable inputs.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Loss on mark-to-market derivatives was $8.7 million for the three months ended March 31, 2014 as compared with $12.1 million for the three months ended March 31, 2013. The favorable movement of $3.4 million was primarily due to a $14.9 million increase in forward prices during the prior year period resulting in mark-to-market losses on derivatives, partially offset by $11.5 million unfavorable movement in cash settlements in the current year period compared to the prior year period.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Other, net for the three months ended March 31, 2014 was $0.6 million as compared with $5.7 million for the comparable prior year period. This decrease was primarily due to APL’s $3.6 million loss in the current year period from the SouthTX equity method investments and a $1.0 million favorable settlement of APL’s business interruption insurance in the prior year period, partially offset by a $0.2 million increase in income from our investment in Lightfoot. APL’s T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. APL’s loss on equity method investments primarily represents the depreciation expense of these assets.

The following table presents our general and administrative expenses and those attributable to ARP and APL for each of the respective periods (in thousands):

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Total general and administrative expenses increased to $48.4 million for the three months ended March 31, 2014 compared with $40.7 million for the three months ended March 31, 2013. Our $14.0 million of general and administrative expenses for the three months ended March 31, 2014 represented a $5.2 million increase from the comparable prior year period, primarily due to a $2.6 million increase in related to our Development Subsidiary, a $1.6 million increase in non-cash compensation expense, a $1.0 million increase salaries, wages and other corporate activities, and a $0.1 million increase in non-recurring transaction costs. ARP’s $16.5 million of general and administrative expenses for the three months ended March 31, 2014 represents a $1.1 million decrease from the comparable prior year period primarily due to a $1.9 million decrease in ARP’s non-cash compensation expense and a $1.3 million decrease in non-recurring transaction costs related to ARP’s acquisitions in the current and prior year periods, partially offset by a $2.1 million increase in salaries and wages and other corporate activities due to the growth of its business. APL’s $17.9 million of general and administrative expense for the three months ended March 31, 2014 represents an increase of $3.6 million from the comparable prior year period, which was principally due to a $2.1 million increase in non-cash compensation expense, and a $2.1 million increase in salaries and wages partially due to the increase in the number of employees as a result of the TEAK Acquisition, partially offset by a $0.5 million decrease in non-recurring transaction costs.

The following table presents depreciation, depletion and amortization expense that was attributable to us, ARP and APL for each of the respective periods (in thousands):

Total depreciation, depletion and amortization increased to $101.3 million for the three months ended March 31, 2014 compared with $51.7 million for the comparable prior year period, which was due to a $30.1 million increase in our and ARP’s depletion expense resulting from the acquisitions consummated during 2013 and 2012 and a $18.8 million increase in APL’s depreciation expenses, primarily due to $11.6 million in additional expense related to assets acquired in the TEAK Acquisition and APL’s expansion capital expenditures incurred subsequent to March 31, 2013.

The following table presents our and ARP’s depletion expense per Mcfe for our and ARP’s operations for the respective periods (in thousands, except per Mcfe data):

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Depletion expense varies from period to period and is directly affected by changes in gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of gas and oil properties. Depletion expense was $49.8 million for the three months ended March 31, 2014, an increase of $30.1 million compared with $19.7 million for the three months ended March 31, 2013. Depletion expense of gas and oil properties as a percentage of gas and oil revenues increased to 49% for three months ended March 31, 2014, compared with 43% for the three months ended March 31, 2013, which was primarily due to an increase in ARP’s depletion expense associated with its oil and natural gas liquids drilled between the periods. Depletion expense per Mcfe was $2.14 for three months ended March 31, 2014, an increase of $0.50 per Mcfe from $1.64 per Mcfe for the three months ended March 31, 2013, which was primarily due to an increase in ARP’s depletion expense associated with its oil and natural gas liquids wells drilled between the periods. Depletion expense increased between periods principally due to an overall increase in production volume.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. During the three months ended March 31, 2014 and 2013, loss on asset sales and disposals were losses of $1.6 million and $0.7 million, respectively. ARP recognized losses on asset sales and disposals of $1.6 million and $0.7 million during the three months ended March 31, 2014 and 2013, respectively. The $1.6 million loss on asset sales and disposal for the three months ended March 31, 2014 was primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. The $0.7 million loss on asset disposal for the three months ended March 31, 2013 primarily pertained to ARP management’s decision not to drill wells on leasehold property that expired in the New Albany and Chattanooga Shales during the period.

The following table presents our interest expense and that which was attributable to ARP and APL for each of the respective periods:

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Total interest expense increased to $41.3 million for the three months ended March 31, 2014 as compared with $25.8 million for the three months ended March 31, 2013. This $15.5 million increase was due to our $4.2 million increase, a $6.3 million increase related to ARP and a $5.0 million increase related to APL. The $4.2 million increase in our interest expense consisted of $3.9 million associated with our term loan facility, a $0.4 million increase in the amortization of deferred financing costs primarily associated with our term loan facility, partially offset by a $0.1 million decrease associated with our credit facility. The $6.3 million increase in ARP’s interest expense consisted of a $5.8 million increase associated with the June 2013 issuance of the 9.25% ARP Senior Notes due 2021, a $1.3 million increase associated with a full quarter’s impact of ARP’s January 2013 issuance of its 7.75% ARP Senior Notes due 2021, a $0.4 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility net of capitalized interest amounts, partially offset by a $2.8 million decrease in the amortization of deferred financing costs. The decrease in amortization associated with deferred financing costs was primarily related to the accelerated amortization associated with the retirement of ARP’s then-existing term loan credit facility and the reduction in its revolving credit facility borrowing base subsequent to its issuance of the 7.75% ARP Senior Notes. The $5.0 million increase in interest expense for APL was primarily due to $4.8 million in additional interest related to the 4.75% APL Senior Notes and $4.2 million in additional interest related to the 5.875% APL Senior Notes; partially offset by $4.2 million in reduced interest on the 8.75% APL Senior Notes. The increase in the interest on the 5.875% APL Senior Notes and the 4.75% APL Senior Notes is due to their issuance after December 31, 2012. The increase in the interest on the 4.75% APL Senior Notes and the 5.875% APL Senior Notes is due to their issuance in 2013. The decrease in the interest for the 8.75% APL Senior Notes is due to their redemption In February 2013 (see “Senior Notes”).

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Loss on early extinguishment of debt for the three months ended March 31, 2013 represented $17.5 million premiums paid, an $8.0 million consent payment made with respect to the extinguishment, and a $5.3 million write off of deferred financing costs, partially offset by a $4.2 million recognition of unamortized premium, related to the redemption of the 8.75% APL Senior Notes (see “Senior Notes”). There was no loss on early extinguishment of debt for the three months ended March 31, 2014.

Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013. Loss attributable to non-controlling interests was $7.1 million for the three months ended March 31, 2014 as compared with a loss of $29.1 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income (loss) to non-controlling interest holders. The favorable movement between the three months ended March 31, 2014 and the prior year comparable period was primarily due to the increase in APL’s net earnings between periods and a decrease in our ownership interests in ARP and APL between the periods, partially offset by an increase in ARP’s net loss during the three months ended March 31, 2014 as compared to the comparable prior year period.

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP and APL, our cash generated from operations and borrowings under our credit facilities (see “Credit Facilities”). Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders, which we expect to fund through operating cash flow, cash distributions received and cash on hand. Our subsidiaries’ sources of liquidity are discussed in more detail below.

Atlas Resource. ARP’s primary sources of liquidity are cash generated from operations, capital raised through Drilling Partnerships, and borrowings under its credit facility (see “Credit Facilities”). ARP’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and distributions to its unitholders and us as general partner. In general, ARP expects to fund:

Atlas Pipeline. APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to its common unitholders and us as general partner. In general, APL expects to fund:

ARP and APL rely on cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. ARP and APL cannot be certain that additional capital will be available to the extent required and on acceptable terms. We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our, ARP’s and APL’s credit facilities and other borrowings, the issuance of additional limited partner units, the sale of assets and other transactions.

Cash Flows – Three Months Ended March 31, 2014 Compared with the Three Months Ended March 31, 2013

Net cash used in operating activities of $0.4 million for the three months ended March 31, 2014 represented a favorable movement of $21.4 million from net cash used in operating activities of $21.8 million for the comparable prior year period. The $21.4 million favorable movement was derived principally from a $48.9 million favorable movement in net loss excluding non-cash items and a $6.7 million favorable movement in working capital, partially offset by a $34.2 million unfavorable movement in distributions paid to non-controlling interests. The non-cash charges which impacted net loss primarily included an increase of $49.6 million of depreciation, depletion and amortization, a favorable movement in net loss of $20.6 million, a favorable movement of $4.2 million in equity and distributions related to unconsolidated subsidiaries, a favorable movement of $2.7 million in compensation expense and an increase of $0.9 million in loss on asset sales and disposal, partially offset by an unfavorable movement of $26.6 million in loss on early extinguishment of debt, an unfavorable movement of $2.1 million in amortization of deferred financing costs and an increase of $0.4 million in APL’s deferred income tax benefit. The movement in working capital was due to a $75.8 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s and APL’s respective capital programs, partially offset by a $69.1 million unfavorable movement in accounts receivable, prepaid expenses and other. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP and APL

Net cash used in investing activities of $177.2 million for the three months ended March 31, 2014 represented an unfavorable movement of $8.7 million from net cash used in investing activities of $168.5 million for the comparable prior year period. This unfavorable movement was principally due to a $5.7 million increase in capital expenditures, a $1.9 million increase in APL’s contributions to its joint ventures and a $1.1 million unfavorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements”.

Net cash provided by financing activities of $178.9 million for the three months ended March 31, 2014 represented a favorable movement of $14.0 million from net cash provided by financing activities of $164.9 million for the comparable prior year period. This favorable movement was principally due to a decrease of $365.8 million in repayments of APL’s long-term debt, an increase of $239.4 million in net proceeds from ARP’s and APL’s equity offerings, a decrease of $203.8 million in repayments of our and our subsidiaries’ revolving credit facilities, an increase of $84.5 million in our, ARP’s and APL’s borrowings under the respective revolving credit facilities, a favorable movement of $25.6 million in payments of premium on the retirement of APL’s long-term debt, a favorable movement of $6.8 million in contributions from APL’s non-controlling interest and a favorable movement of $1.4 million in deferred financing costs, distribution equivalent rights and other, partially offset by a decrease of $905.0 million in net proceeds from the issuance of ARP’s and APL’s long-term debt and an increase of $8.3 million in distributions paid to our limited partners. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us, ARP and APL, which is generally common practice for our and their industries.

APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the three months ended March 31, 2014.

At March 31, 2014, our and our subsidiaries’ capital requirements are as follows:

Natural gas and oil production. The capital requirements of our and ARP’s natural gas and oil production consist primarily of:

Gathering and processing. APL’s gathering and processing operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational and environmental regulations. APL’s capital requirements consist primarily of:

The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

	Three Months Ended March 31,
	2014		2013
Atlas Energy
Maintenance capital expenditures	$	300	$	—
Expansion capital expenditures		4,222		—
Total	$	4,522	$	—
Atlas Resources
Maintenance capital expenditures	$	10,800	$	4,000
Expansion capital expenditures		29,097		54,487
Total	$	39,897	$	58,487
Atlas Pipeline
Maintenance capital expenditures	$	5,325	$	3,855
Expansion capital expenditures		123,006		104,661
Total	$	128,331	$	108,516
Consolidated
Maintenance capital expenditures	$	16,425	$	7,855
Expansion capital expenditures		156,325		159,148
Total	$	172,750	$	167,003

Atlas Energy. During the three months ended March 31, 2014, our total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs of our Development Subsidiary.

Atlas Resource Partners. During the three months ended March 31, 2014, ARP’s $39.9 million of total capital expenditures consisted primarily of $17.0 million for wells drilled exclusively for its own account compared with $36.5 million for the comparable prior year period, $11.3 million of investments in its Drilling Partnerships compared with $11.6 million for the prior year comparable period, $4.0 million of leasehold acquisition costs compared with $4.3 million for the prior year comparable period, and $7.6 million of corporate and other costs compared with $6.1 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense.

Atlas Pipeline Partners. APL’s capital expenditures increased to $128.3 million for the three months ended March 31, 2014 compared with $108.5 million for the comparable prior year period. The increase was primarily due to construction costs for the Stonewall Plant within SouthOK scheduled to be placed in service during second quarter of 2014; the Silver Oak II Plant within SouthTX scheduled to be placed in service during the second quarter of 2014; the Edward Plant within WestTX scheduled to be placed in service in late 2014; and the construction of the Velma to Arkoma connection within SouthOK scheduled to be completed during third quarter of 2014.

We, ARP and APL continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we, ARP and APL believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we, ARP or APL will be successful in our and its efforts to obtain outside capital.

As of March 31, 2014, we and our subsidiaries are committed to expending approximately $84.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

As of March 31, 2014, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $3.7 million, APL’s letters of credit outstanding of $0.1 million and commitments to spend $84.5 million related to capital expenditures.

The Board has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

Atlas Resource Partners’ Cash Distribution Policy: ARP’s partnership agreement requires that it distribute 100% of available cash to its common and preferred unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of ARP’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments. We, as ARP’s general partner, are granted discretion under the partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.

On January 29, 2014, ARP’s board of directors approved a modification to its cash distribution payment practice to a monthly cash distribution program, beginning with January 2014. Monthly cash distributions will continue to be paid approximately 45 days following the end of each respective monthly period.

Available cash will generally be distributed: first, 98% to ARP’s Class B preferred unitholders and 2% to us as general partner until there has been distributed to each Class B preferred unit the greater of $0.40 per quarter and the distribution payable to common unitholders; second, 98% to ARP’s Class C preferred unitholders and 2% to us as general partner until there has been distributed to each outstanding Class C preferred unit the greater of $0.51 per quarter and the distribution payable to common unitholders; thereafter 98% to ARP’s common unitholders and 2% to us as general partner. These distribution percentages are modified to provide for incentive distributions to be paid to us, as ARP’s general partner, if quarterly distributions exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. The incentive distribution rights will entitle us to receive an increasing percentage of cash distributed by ARP as it reaches specified targets.

Atlas Pipeline Partners’ Cash Distribution Policy. APL’s partnership agreement requires that it distribute 100% of available cash, for each calendar quarter, to its common unitholders and to the general partner, our wholly-owned subsidiary, within 45 days following the end of such calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

APL’s general partner is granted discretion by APL’s partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When APL’s general partner determines its quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2.0% of the aggregate amount of cash being distributed. We, as general partner, agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after we receive the initial $7.0 million per quarter of incentive distribution rights.

APL’s Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods beginning with the distribution for the quarter ended June 30, 2013. Thereafter, the Class D Preferred Units will receive distributions in cash, Class D Preferred Units or a combination of cash and Class D Preferred Units, at the discretion of APL.

On July 31, 2013, in connection with the Arkoma Acquisition, we entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). At March 31, 2014, $238.8 million was outstanding under the Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at our election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by us. We are required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due.

The Term Facility contains customary covenants, similar to those in our credit facility, that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 our assets. The Term Facility also contains covenants that require (i) us to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions. At March 31, 2014, we were in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

Our obligations under the Term Facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under our Term Facility are guaranteed by our material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of our subsidiaries, other than the subsidiary guarantors, are minor. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and our credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

On July 31, 2013, in connection with the Arkoma Acquisition, we amended our credit facility with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At March 31, 2014, no amounts were outstanding under the credit facility. Our obligations under the credit facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under the credit facility are guaranteed by our material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of our subsidiaries, other than the subsidiary guarantors, are minor. At our election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by us for LIBOR loans. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

The credit facility contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 our assets. The credit facility also contains covenants the same as those in our Term Facility with respect to (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At March 31, 2014, the Partnership was in compliance with these covenants.

The credit facility is subject to an intercreditor agreement as described above under the “Term Loan Facility”.

At March 31, 2014, we have not guaranteed any of ARP’s or APL’s debt obligations.

At March 31, 2014, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $150.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2014. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet at March 31, 2014. At March 31, 2014, APL had $449.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.

On March 11, 2014, APL entered into an amendment to its credit agreement governing its revolving credit facility, which among other changes, adjusted the Acquisition Period, as defined in the credit agreement, for the Consolidated Funded Debt Ratio, as defined in the credit agreement, and permitted the payment of cash distributions, if any, on the Class E Preferred Units so long as APL has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50.0 million (see “Recent Developments”).

At March 31, 2014, ARP 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 ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. 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.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

On March 31, 2014, ARP had $275.0 million principal outstanding of 7.75% ARP Senior Notes and $250.0 million principal outstanding of 9.25% ARP Senior Notes. On July 30, 2013, ARP issued $250.0 million of 9.25% ARP Senior Notes, due 2021, in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million. The net proceeds were used to partially fund the EP Energy Acquisition. The 9.25% ARP Senior Notes were presented net of a $1.6 million unamortized discount as of March 31, 2014. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes due 2021, ARP entered into a registration rights agreement, whereby it agreed to (i) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (ii) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes, due 2021, and used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the three months ended March 31, 2013. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable 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% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP 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.

ARP’s 9.25% Senior Notes and 7.75% Senior Notes are guaranteed by certain of its material subsidiaries. The guarantees under ARP 9.25% Senior Notes and 7.75% Senior Notes are full and unconditional and joint and several, and any of its subsidiaries, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

At March 31, 2014, APL had $500.0 million principal outstanding of 6.625% unsecured senior notes due October 1, 2020 (“6.625% APL Senior Notes”), $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $400.0 million of 4.75% Senior Notes due 2021 (and with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

On February 11, 2013, APL issued $650.0 million of the 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million after underwriting commissions and other transaction costs and utilized the proceeds to redeem the 8.75% unsecured senior notes due June 15, 2018 (“8.75% APL Senior Notes”) and repay a portion of the outstanding indebtedness under its revolving credit agreement. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014.

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million 8.75% APL Senior Notes not purchased in connection with the tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes. During the three months ended March 31, 2013, APL recorded a loss of $26.6 million within loss on early extinguishment of debt on our consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid; $8.0 million consent payment; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium.

We recognize gains on ARP’s and APL’s equity transactions as credits to partners’ capital on our consolidated balance sheets rather than as income on our consolidated statements of operations. These gains represent our portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

In July 2013, in connection with the closing of ARP’s EP Energy Acquisition, we purchased 3,746,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, we, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units, at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

In July 2013, in connection with ARP’s EP Energy Acquisition, ARP issued 3,749,986 newly created Class C convertible preferred units to us, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at our option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act.

In June 2013, in connection with the EP Energy Acquisition, ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see “Credit Facilities”).

At March 31, 2014 and December 31, 2013, in connection with the issuance of ARP’s common units, we recorded gains of $14.6 million and $27.3 million within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated balance sheets and consolidated statement of partners’ capital.

APL had an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL offered and sold through Citigroup, as its sales agent, common units for $150.0 million. Sales were at market prices prevailing at the time of the sale. During the three year ended December 31, 2013, APL issued 3,895,679 common units under the equity distribution program for net proceeds of 137.8 million, net of $2.8 million in sales commissions incurred and other offering costs. APL also received capital contributions from the Partnership of $2.9 million during the year ended December 31, 2013 to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering for general partnership purposes. As of December 31, 2013, APL had used the full capacity under the equity distribution program.

In April 2013, APL sold 11,845,000 of its common units to the public at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from us, as general partner, of $8.3 million to maintain our 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements was included in our Annual Report on Form 10-K for the year ended December 31, 2013, and we summarize our significant accounting policies within our consolidated financial statements included in Note 2 under “Item 1: Financial Statements” included in this report. The critical accounting policies and estimates we have identified are discussed below.

Long-Lived Assets. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in “General Trends and Outlook”, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

There were no impairments of proved or unproved gas and oil properties recorded for the three months ended March 31, 2014 and 2013. During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.

There were no goodwill impairments recognized by ARP or APL during the three months ended March 31, 2014 and 2013.

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. 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.

We use a fair value methodology to value the assets and liabilities for our and our subsidiaries’ outstanding derivative contracts. Our and our subsidiaries’ commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

Of the $8.5 million of net derivative liabilities and $14.9 million of net derivative assets at March 31, 2014 and December 31, 2013, respectively, APL had net derivative liabilities of $7.0 million and net derivative liabilities of $11.8 million at March 31, 2014 and December 31, 2013, respectively, that were classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the price APL utilized in calculating the fair value of derivatives at March 31, 2014 would have resulted in a $0.9 million non-cash change, net of non-controlling interests, to net income (loss) for the three months ended March 31, 2014.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

During the year ended December 31, 2013, we completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of 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 our and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of our and its gas and oil wells (see “Item 1: Financial Statements—Note 7”). These inputs require significant judgments and estimates by our, ARP’s and APL’s management at the time of the valuation and are subject to change.

Estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. As discussed in “Item 2: Properties” of our Annual Report on Form 10-K for the year ended December 31, 2013, we and ARP engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of our and ARP’s proved reserves.

Any significant variance in the assumptions utilized in the calculation of reserve estimates could materially affect the estimated quantity of reserves. As a result, estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our and ARP’s ability to pay amounts due under our and ARP’s credit facilities or cause a reduction in our or ARP’s credit facilities. In addition, proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

We and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets.

We and ARP recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We and ARP also recognize a liability for future asset retirement obligations 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. We and ARP also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, 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 is discounted using an assumed credit-adjusted risk-free interest rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we and ARP attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. 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. Neither we nor ARP have any assets legally restricted for purposes of settling asset retirement obligations. Except for gas and oil properties, there are no other material retirement obligations associated with our and ARP’s tangible long lived assets.

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations owned by APL and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of March 31, 2014 and December 31, 2013 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk sensitive instruments were entered into for purposes other than trading.

All of our and our subsidiaries’ assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2014. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Current market conditions elevate our and our subsidiaries’ concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our and our subsidiaries’ commodity derivative contracts are banking institutions or their affiliates, who also participate in our, ARP’s and APL’s revolving credit facilities. The creditworthiness of our and our subsidiaries’ counterparties is constantly monitored, and we and our subsidiaries currently believe them to be financially viable. We and our subsidiaries are not aware of any inability on the part of their counterparties to perform under their contracts and believe our and our subsidiaries’ exposure to non-performance is remote.

Interest Rate Risk. At March 31, 2014, we had $238.8 million of outstanding borrowings under our term loan facility, ARP had $366.0 million of outstanding borrowings under its revolving credit facility and APL had $150.0 million of outstanding borrowings under its senior secured revolving credit facility. At March 31, 2014, we had no borrowings outstanding under our revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending March 31, 2015 by $7.5 million, excluding the effect of non-controlling interests.

Commodity Price Risk. Our and our subsidiaries’ market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our and our subsidiaries’ financial results. To limit the exposure to changing commodity prices, we and our subsidiaries use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we and our subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending March 31, 2015 of approximately $7.2 million, net of non-controlling interests.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years. To limit our and our subsidiaries’ exposure to changing natural gas, oil and natural gas liquids prices, we enter into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

Production Period	Purchased/ Sold	Commodity	Volumes⁽¹⁾		Average Fixed Price
Natural Gas
2014	Sold	Natural Gas		12,690,000	$	4.029
2015	Sold	Natural Gas		18,610,000	$	4.244
2016	Sold	Natural Gas		7,950,000	$	4.277
2017	Sold	Natural Gas		600,000	$	4.455
Natural Gas Liquids
2014	Sold	Natural Gas Liquids		60,354,000	$	1.198
2015	Sold	Natural Gas Liquids		41,076,000	$	1.079
2016	Sold	Natural Gas Liquids		6,300,000	$	1.034
Crude Oil
2014	Sold	Crude Oil		219,000	$	91.062
2015	Sold	Crude Oil		60,000	$	85.130

Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾		Average Strike Price
Natural Gas
2014	Purchased	Put	Natural Gas		500,000	$	4.130
Natural Gas Liquids
2014	Purchased	Put	Natural Gas Liquids		6,930,000	$	0.960
2014	Sold	Call	Natural Gas Liquids		3,780,000	$	1.318
2015	Purchased	Put	Natural Gas Liquids		3,150,000	$	0.941
2015	Sold	Call	Natural Gas Liquids		1,260,000	$	1.275
Crude Oil
2014	Purchased	Put	Crude Oil		267,000	$	90.413
2015	Purchased	Put	Crude Oil		270,000	$	89.175

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

In July 2013, we and ARP acquired certain assets from EP Energy which have been fully integrated into our existing control environment during the three months ended March 31, 2014. Other than the previously mentioned item, there have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Exhibit No.		Description

2.1		Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.⁽⁴⁷⁾

2.2		Assignment & Assumption Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P.⁽⁵⁰⁾

3.1(a)		Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹⁾

3.1(b)		Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹³⁾

3.1(c)		Amendment to Certificate of Limited Partnership of Atlas Energy, L.P.⁽⁵⁾

3.2(a)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹³⁾

3.2(b)		Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.⁽¹³⁾

3.2(c)		Amendment No. 2 to Second Amended and Restated Limited Partnership Agreement of Atlas Energy, L.P.⁽⁵⁾

4.1		Specimen Certificate Representing Common Units⁽¹⁾

10.1		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC.⁽¹³⁾

10.2		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽²²⁾

10.3(a)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁾

10.3(b)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁴⁾

10.3(c)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(d)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(e)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(f)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁷⁾

10.3(g)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁸⁾

10.3(h)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁹⁾

10.3(i)		Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁴⁾

10.3(j)		Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽³⁹⁾

10.3(k)		Amendment No. 11 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁵⁷⁾

Exhibit No.		Description
10.4		Atlas Pipeline Partners, L.P.’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Convertible Preferred Units, dated as of May 7, 2013⁽³⁹⁾

10.5		Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC ⁽⁵³⁾

10.6(a)		Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.⁽²⁸⁾

10.6(b)		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 25, 2012⁽¹⁷⁾

10.6(c)		Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 31, 2013⁽⁴⁴⁾

10.7		Atlas Resource Partners, L.P’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class B Preferred Units, dated as of July 25, 2012⁽¹⁷⁾

10.8		Atlas Resource Partners, L.P’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class C Convertible Preferred Units, dated as of July 31, 2013⁽⁴⁴⁾

10.9(a)		Long-Term Incentive Plan⁽⁶⁾

10.9(b)		Amendment No. 1 to Long-Term Incentive Plan⁽¹⁵⁾

10.10		Form of Phantom Grant under 2006 Long-Term Incentive Plan⁽⁵⁴⁾

10.11		Form of Phantom Grant under 2006 Long-Term Incentive Plan (2013)⁽⁶⁰⁾

10.12		2010 Long-Term Incentive Plan⁽¹⁶⁾

10.13		Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan⁽³²⁾

10.14		Form of Stock Option Grant under 2010 Long-Term Incentive Plan⁽³²⁾

10.15		Amended and Restated Credit Agreement, dated July 31, 2013 among Atlas Energy, L.P., the lenders party thereto and Wells Fargo Bank, NA as administrative agent⁽⁴⁵⁾

10.16		Secured Term Loan Credit Agreement, dated July 31, 2013 among Atlas Energy, L.P., the lenders party thereto and Deutsche Bank AG New York Branch, as administrative agent⁽⁴⁵⁾

10.17		Intercreditor Agreement, dated July 31, 2013 among Atlas Energy, L.P., the grantors party thereo, Wells Fargo Bank, NA as revolving facility administrative agent and Deutsche Bank AG, New York Branch, as term facility administrative agent⁽⁴⁵⁾

10.18(a)		Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto⁽²³⁾

10.18(b)		Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011⁽²⁵⁾

10.18(c)		Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011⁽²⁶⁾

10.18(d)		Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012⁽¹⁸⁾

10.18(e)		Amendment No. 3 to the Amended and Restated Credit Agreement⁽³⁴⁾

10.18(f)		Amendment No. 4 to the Amended and Restated Credit Agreement⁽¹¹⁾

10.18(g)		Amendment No. 6 to the Amended and Restated Credit Agreement⁽⁵⁸⁾

Exhibit No.		Description
10.19		Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.20(a)		Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.20(b)		Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011.⁽¹²⁾

10.20(c)		Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.21		Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.22		Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.23		Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

10.24		Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011⁽¹²⁾

10.25		Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011⁽¹²⁾

10.26		Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011⁽²¹⁾

10.27		Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011⁽³²⁾

10.28		Employment Agreement between Atlas Energy, L.P. and Daniel Herz dated as of November 4, 2011⁽⁵⁵⁾

10.29		Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012⁽³⁵⁾

10.30		Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010⁽²¹⁾

10.31(a)		Second Amended and Restated Credit Agreement dated July 31, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽⁴⁴⁾

Exhibit No.		Description
10.31(b)		First Amendment to Second Amended and Restated Credit Agreement dated December 6, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽⁵⁶⁾

10.32(a)		Credit Agreement, dated as of March 5, 2012, among Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders⁽³⁰⁾

10.32(b)		First Amendment to Credit Agreement, dated as of April 30, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders⁽³¹⁾

10.32(c)		Second Amendment to Amended and Restated Credit Agreement, dated as of July 26, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders⁽¹⁷⁾

10.32(d)		Third Amendment to Amended and Restated Credit Agreement dated as of December 20, 2012⁽³⁶⁾

10.32(e)		Fourth Amendment to Amended and Restated Credit Agreement dated as of January 11, 2013⁽³⁷⁾

10.32(f)		Fifth Amendment to Amended and Restated Credit Agreement dated as of May 30, 2013⁽⁵¹⁾

10.33		Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers⁽³⁰⁾

10.34		Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan⁽²⁸⁾

10.35		Atlas Pipeline Partners, L.P. Long-Term Incentive Plan⁽²⁷⁾

10.36		Atlas Pipeline Partners, L.P. Amended and Restated 2010 Long-Term Incentive Plan⁽²⁰⁾

10.37		Registration Rights Agreement, dated as of April 30, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein⁽³¹⁾

10.38		Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein⁽¹⁷⁾

10.39		Registration Rights Agreement, dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation and the initial purchasers named therein⁽¹⁰⁾

10.40		Registration Rights Agreement, dated May 16, 2012, between Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein⁽³⁵⁾

10.41		Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.⁽⁴³⁾

10.42		Purchase and Sale Agreement, dated as of April 16, 2013, among TEAK Midstream Holdings, LLC, TEAK Midstream, L.L.C. and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Registration S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request⁽²⁹⁾

10.43		Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽³⁸⁾

10.44		Class D Preferred Unit Purchase Agreement, dated as of April 16, 2013, among Atlas Pipeline Partners, L.P. and the various purchasers party thereto⁽²⁹⁾

10.45		Registration Rights Agreement, dated May 7, 2013, by and among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽³⁹⁾

10.46		Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.⁽⁴⁷⁾

Exhibit No.		Description
10.47		Warrant to Purchase Common Units⁽⁴⁴⁾

10.48		Distribution Agreement dated as of May 10, 2013, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents⁽⁴⁸⁾

10.49		Class C Preferred Unit Purchase Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P.⁽⁵⁰⁾

10.50		Indenture dated as of July 30, 2013, by and between Atlas Resource Escrow Corporation and Wells Fargo Bank, National Association⁽⁴⁹⁾

10.51		Supplemental Indenture dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association⁽⁴⁹⁾

10.52		Registration Rights Agreement dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Deutsche Bank Securities, Inc., for itself and on behalf of the Initial Purchasers⁽⁴⁹⁾

10.53		Registration Rights Agreement dated as of July 31, 2013 by and among Atlas Energy, L.P. and Atlas Resource Partners, L.P.⁽⁴⁴⁾

10.54		Registration Rights Agreement dated May 7, 2013, among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽⁵²⁾

10.55		Indenture dated as of May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein and U.S. Bank National Association⁽⁴⁶⁾

10.56		Registration Rights Agreement, dated May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the guarantors named therein and Citigroup Global Markets, Inc. for itself and on behalf of the initial purchasers⁽⁴⁶⁾

10.57		Asset Purchase Agreement, dated as of February 13, 2014, by and among GeoMet, Inc., GeoMet Operating Company, Inc., GeoMet Gathering Company, LLC and ARP Mountaineer Production, LLC. The exhibits and schedules to the Asset Purchase Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request⁽³³⁾

31.1		Rule 13(a)-14(a)/15(d)-14(a) Certification

31.2		Rule 13(a)-14(a)/14(d)-14(a) Certification

32.1		Section 1350 Certification

32.2		Section 1350 Certification

99.1		Voting Agreement, dated as of February 13, 2014, by and among ARP Mountaineer Production, LLC, Atlas Resource Partners, L.P. and each of the persons listed on Annex I thereto⁽³³⁾

101.INS		XBRL Instance Document⁽⁵⁹⁾

101.SCH		XBRL Schema Document⁽⁵⁹⁾

101.CAL		XBRL Calculation Linkbase Document⁽⁵⁹⁾

101.LAB		XBRL Label Linkbase Document⁽⁵⁹⁾

101.PRE		XBRL Presentation Linkbase Document⁽⁵⁹⁾

101.DEF		XBRL Definition Linkbase Document⁽⁵⁹⁾

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Delaware		43-2094238
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA		15275
(Address of principal executive offices)		(Zip code)

Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if smaller reporting company)	Smaller reporting company	¨

		PAGE
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	3
	Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	3
	Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	4
	Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2014 and 2013	5
	Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2014	6
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	88
Item 4.	Controls and Procedures	94
PART II. OTHER INFORMATION
Item 6.	Exhibits	95
SIGNATURES		102

	Three Months Ended March 31,
	2014			2013
Net loss	$	(21,067	)	$	(41,694	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		(36,255	)		(24,944	)
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss		14,569			(993	)
Total other comprehensive loss		(21,686	)		(25,937	)
Comprehensive loss		(42,753	)		(67,631	)
Comprehensive loss attributable to non-controlling interests		20,630			43,372
Comprehensive loss attributable to common limited partners	$	(22,123	)	$	(24,259	)

Assets:
Prepaid expenses and other	$	5,268
Property, plant and equipment		723,657
Total current assets	$	728,925
Liabilities:
Accounts payable		2,562
Asset retirement obligation		16,728
Total liabilities assumed		19,290
Net assets acquired	$	709,635

	Three Months Ended March 31,
Continuing Operations:	2014			2013
Net loss	$	(21,067	)	$	(41,694	)
Loss attributable to non-controlling interests		7,142			29,098
Net loss attributable to common limited partners		(13,925	)		(12,596	)
Less: Net income attributable to participating securities – phantom units⁽¹⁾		—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	$	(13,925	)	$	(12,596	)

Assets:
Cash	$	8,074
Accounts receivable		11,055
Prepaid expenses and other		1,626
Total current assets		20,755
Property, plant and equipment		193,877
Intangible assets		430,000
Goodwill		190,683
Equity method investment in joint ventures		183,801
Total assets acquired	$	1,019,116
Liabilities:
Accounts payable and accrued liabilities		(35,296	)
Other long term liabilities		(1,075	)
Total liabilities assumed		(36,371	)
Net assets acquired		982,745
Less cash received		(8,074	)
Net cash paid for acquisition	$	974,671

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2014		2,070,000	$	4.177	$	(593	)
2015		2,280,000	$	4.302		228
2016		1,440,000	$	4.433		399
2017		1,200,000	$	4.590		393
2018		420,000	$	4.797		170
		The Partnership’s net asset			$	597

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2014		45,114,700	$	4.152	$	(14,068	)
2015		51,924,500	$	4.239		1,799
2016		45,746,300	$	4.311		7,193
2017		24,840,000	$	4.532		6,734
2018		3,960,000	$	4.716		1,306
					$	2,964

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2014	Puts purchased		2,880,000	$	4.221	$	642
2014	Calls sold		2,880,000	$	5.120		(418	)
2015	Puts purchased		3,480,000	$	4.234		1,636
2015	Calls sold		3,480,000	$	5.129		(721	)
						$	1,139

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		(in thousands)⁽³⁾
2014		79,500	$	91.568	$	(486	)
2015		96,000	$	88.550		(129	)
2016		84,000	$	85.651		92
2017		60,000	$	83.780		127
					$	(396	)

	March 31, 2014			December 31, 2013
Deferred tax assets:
Net operating loss tax carryforwards and alternative minimum tax credits	$	15,499		$	14,900
Deferred tax liabilities:
Excess of asset carrying value over tax basis		(48,391	)		(48,190	)
Net deferred tax liabilities	$	(32,892	)	$	(33,290	)

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partners
May 20, 2013	March 31, 2013	$	0.31	$	15,928
August 19, 2013	June 30, 2013	$	0.44	$	22,611
November 19, 2013	September 30, 2013	$	0.46	$	23,649
February 19, 2014	December 31, 2013	$	0.46	$	23,681

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
May 15, 2013	March 31, 2013	$	0.59	$	45,382	$	3,980
August 14, 2013	June 30, 2013	$	0.62	$	48,165	$	5,875
November 14, 2013	September 30, 2013	$	0.62	$	49,298	$	6,013
February 14, 2014	December 31, 2013	$	0.62	$	49,969	$	6,095

		ATLAS ENERGY, L.P.
		By: Atlas Energy GP, LLC, its General Partner

Date:	May 8, 2014	By:	/s/ EDWARD E. COHEN
			Edward E. Cohen
			Chief Executive Officer and President of the General Partner

Date:	May 8, 2014	By:	/s/ SEAN P. MCGRATH
			Sean P. McGrath
			Chief Financial Officer of the General Partner

Date:	May 8, 2014	By:	/s/ JEFFREY M. SLOTTERBACK
			Jeffrey M. Slotterback
			Chief Accounting Officer