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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

OR

 

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission file number: 1-32953

 

 

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE		43-2094238
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road
Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

Registrant’s telephone number, including area code: (412) 262-2830

 

 

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  ¨    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.

 

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

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 6, 2011 was 51,224,302.

 

 

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

 

				PAGE
PART I.     FINANCIAL INFORMATION
Item 1.		Financial Statements (Unaudited)
		Consolidated Combined Balance Sheets as of March 31, 2011 and December 31, 2010			3
		Consolidated Combined Statements of Operations for the Three Months Ended March 31, 2011 and 2010			4
		Consolidated Combined Statement of Partners’ Capital for the Three Months Ended March 31, 2011			5
		Consolidated Combined Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010			6
		Notes to Consolidated Combined Financial Statements			7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			37
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			54
Item 4.		Controls and Procedures			56
PART II.    OTHER INFORMATION
Item 1.		Legal Proceedings			57
Item 5.		Other Information			57
Item 6.		Exhibits			58
SIGNATURES					62

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED BALANCE SHEETS

(in thousands, except share and per share data)

(Unaudited)

 

		March 31, 2011				December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents		$	105,930			$	247
Accounts receivable			122,344				120,697
Current portion of derivative asset			670				36,621
Prepaid expenses and other			31,995				23,652
Total current assets			260,939				181,217
Property, plant and equipment, net			1,863,765				1,849,486
Intangible assets, net			122,596				128,543
Investment in joint venture			—				153,358
Goodwill, net			31,784				31,784
Long-term derivative asset			3,695				36,125
Cash in escrow (APL Senior Note Redemption)			286,670				—
Other assets, net			58,608				54,749
		$	2,628,057			$	2,435,262
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	213			$	35,625
Accounts payable			68,015				79,216
Liabilities associated with drilling contracts			47,347				65,072
Accrued producer liabilities			77,173				72,996
Current portion of derivative liability			18,072				4,917
Current portion of derivative payable to Drilling Partnerships			25,650				30,797
Accrued interest			12,454				1,921
Accrued well drilling and completion costs			22,234				30,126
Advances from affiliates			—				14,335
Accrued liabilities			39,098				42,654
Total current liabilities			310,256				377,659
Long-term debt, less current portion			495,857				565,764
Long-term derivative liability			12,176				11,901
Long-term derivative payable to Drilling Partnerships			31,719				34,796
Other long-term liabilities			42,863				42,896
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests			555,209				409,177
Accumulated other comprehensive income (loss)			(3,170	)			3,882
			552,039				413,059
Non-controlling interests			1,183,147				989,187
Total partners’ capital			1,735,186				1,402,246
		$	2,628,057			$	2,435,262

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

 

		Three Months Ended March 31,
		2011				2010
Revenues:
Gas and oil production		$	17,626			$	25,480
Well construction and completion			17,725				72,642
Gathering and processing			280,218				236,546
Administration and oversight			1,361				2,045
Well services			5,286				5,180
Gain (loss) on mark-to-market derivatives			(21,645	)			4,721
Other, net			4,353				3,389
Total revenues			304,924				350,003
Costs and expenses:
Gas and oil production			3,921				4,043
Well construction and completion			15,021				61,561
Gathering and processing			236,984				196,162
Well services			2,360				2,463
General and administrative			16,190				10,541
Depreciation, depletion and amortization			26,607				27,097
Total costs and expenses			301,083				301,867
Operating income			3,841				48,136
Gain (loss) on asset sales			255,947				(2,947	)
Interest expense			(18,078	)			(27,021	)
Income from continuing operations			241,710				18,168
Discontinued operations:
Income (loss) from discontinued operations			(81	)			6,781
Net income			241,629				24,949
Income attributable to non-controlling interests			(211,378	)			(1,807	)
Net income after non-controlling interests			30,251				23,142
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			(4,711	)			(24,506	)
Net income (loss) attributable to common limited partners		$	25,540			$	(1,364	)
Net income (loss) attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners		$	0.65			$	(0.08	)
Income from discontinued operations attributable to common limited partners			—				0.03
Net income (loss) attributable to common limited partners		$	0.65			$	(0.05	)
Net income (loss) attributable to common limited partners per unit – diluted:
Income (loss) from continuing operations attributable to common limited partners		$	0.65			$	(0.08	)
Income from discontinued operations attributable to common limited partners			—				0.03
Net income (loss) attributable to common limited partners		$	0.65			$	(0.05	)
Weighted average common limited partner units outstanding:
Basic			39,010				27,704
Diluted			39,245				27,704
Net income (loss) attributable to common limited partners:
Income (loss) from continuing operations		$	25,550			$	(2,222	)
Income (loss) from discontinued operations			(10	)			858
Net income (loss) attributable to common limited partners		$	25,540			$	(1,364	)

See accompanying notes to consolidated combined financial statements.

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

 

		Common Limited Partners’ Capital								Accumulated Other Comprehensive Income (Loss)				Non- Controlling Interests				Total
		Units				$
Balance at January 1, 2011			27,835,254			$	409,177			$	3,882			$	989,187			$	1,402,246
Issuance of common limited partner units related to the acquisition of the Transferred Business (see Note 3)			23,379,384				372,200				—				—				372,200
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			—				(254,970	)			—				—				(254,970	)
APL distributions to non-controlling interests			—				—				—				(18,830	)			(18,830	)
Unissued common units under incentive plans			—				501				—				1,177				1,678
Issuance of units under incentive plans			9,664				—				—				468				468
Distributions paid to common limited partners			—				(1,948	)			—				—				(1,948	)
Distributions equivalent rights paid on unissued units under incentive plans			—				(2	)			—				(181	)			(183	)
APL preferred unit distribution			—				—				—				(240	)			(240	)
Other comprehensive income (loss)			—				—				(7,052	)			188				(6,864	)
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			—				4,711				—				—				4,711
Net income			—				25,540				—				211,378				236,918
Balance at March 31, 2011			51,224,302			$	555,209			$	(3,170	)		$	1,183,147			$	1,735,186

See accompanying notes to consolidated combined financial statements.

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

		Three Months Ended March 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	241,629			$	24,949
Income (loss) from discontinued operations			(81	)			6,781
Income from continuing operations			241,710				18,168
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization			26,607				27,097
Amortization of deferred finance costs			6,199				1,686
Non-cash loss on derivative value, net			72,807				5,754
Non-cash compensation expense			1,678				474
(Gain) loss on asset sales and dispositions			(255,947	)			2,947
Distributions paid to non-controlling interests			(19,251	)			(1,678	)
Equity income in unconsolidated companies			(1,613	)			(1,407	)
Distributions received from unconsolidated companies			2,154				3,991
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other			(17,437	)			74,210
Accounts payable and accrued liabilities			(34,572	)			(70,335	)
Net cash provided by continuing operating activities			22,335				60,907
Net cash provided by (used in) discontinued operating activities			(81	)			1,947
Net cash provided by operating activities			22,254				62,854
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(26,065	)			(35,192	)
Investments in unconsolidated companies			(12,250	)			(6,320	)
Net proceeds from asset sales			411,753				210
Other			(1,480	)			405
Net cash provided by (used in) continuing investing activities			371,958				(40,897	)
Net cash used in discontinued investing activities			—				(1,947	)
Net cash provided by (used in) investing activities			371,958				(42,844	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash placed in escrow (APL Senior Note Redemption)			(293,696	)			—
Borrowings under credit facilities			178,000				137,000
Repayments under credit facilities			(248,000	)			(187,000	)
Repayments of long-term debt			(35,415	)			(7,661	)
Net proceeds from equity offerings			—				19,332
Distributions paid to unit holders			(1,948	)			—
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			117,230				—
Net investment received from Atlas Energy, Inc. received prior to February 17, 2011 (see Note 3)			—				17,353
Deferred financing costs and other			(4,700	)			41
Net cash used in financing activities			(288,529	)			(20,935	)
Net change in cash and cash equivalents			105,683				(925	)
Cash and cash equivalents, beginning of period			247				1,103
Cash and cash equivalents, end of period		$	105,930			$	178

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

March 31, 2011

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS). On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of its general partner (see Note 3).

The Partnership also maintains ownership interests in the following entities:

 

•

Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At March 31, 2011, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.8% common limited partner interest; and

 

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At March 31, 2011, the Partnership had an approximate direct and indirect 18% ownership interest in Lightfoot GP. The Partnership also had direct and indirect ownership interest in Lightfoot LP.

The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 2010 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 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 combined 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, 2010 (see Note 2). Certain amounts in the prior year’s consolidated combined financial statements have also been reclassified to conform to the current year presentation, including amounts related to APL’s Elk City system, which have been reclassified to discontinued operations following the sale of that system in September 2010 (see Note 4). The results of operations for the three month period ended March 31, 2011 may not necessarily be indicative of the results of operations for the full year ending December 31, 2011.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at March 31, 2011 except for APL, which is controlled by the Partnership. The non-controlling ownership interests in the net income (loss) of APL are reflected within non-controlling interests on the Partnership’s consolidated combined statements of operations. The non-controlling interests in the assets and liabilities of APL are reflected as a component of partners’ capital on the Partnership’s consolidated combined balance sheets. All material intercompany transactions have been eliminated.

In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 3). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at carrying value at the date of transfer, with any difference between the purchase price and the net book

 

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value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:

 

•

Recognized the assets acquired and liabilities assumed from the Transferred Business at their carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (See Note 3);

 

•

Retrospectively adjusted its consolidated combined balance sheet as of December 31, 2010, its consolidated combined statement of partners’ capital for the three months ended March 31, 2011, its consolidated combined statements of operations and cash flows for the three months ended March 31, 2011 and 2010 and the notes to such consolidated combined financial statements to reflect its results combined with the results of the Transferred Business as of or at the beginning of the respective period; and

 

•

Adjusted the presentation of its consolidated combined statements of operations for the three months ended March 31, 2011 and 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense as AEI was unable to identify and allocate such amounts to the Transferred Business for the respective period.

In accordance with established practice in the oil and gas industry, the Partnership’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Partnership has an interest (“the Drilling Partnerships”). Such interests typically range from 15% to 35%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated combined financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its consolidated combined statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests within partners’ capital on its consolidated combined balance sheets. The 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 combined balance sheets.

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

Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United States 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 combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization,

 

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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. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical period financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition (see “Principles of Consolidation and Combination”). 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, 2011 and 2010 represent actual results in all material respects (see “- Revenue Recognition” accounting policy for further description).

Inventory

The Partnership and APL value inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs have been determined using the first-in, first-out method (“FIFO”). Under this methodology, the cost of products sold consists of APL’s natural gas liquids line fill and condensate inventories. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the FIFO inventory layers.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see “Principles of Consolidation and Combination”). Depreciation and amortization expense was based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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 and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to 6 Mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated combined statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated combined balance sheets. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated combined 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.

 

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Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Partnership’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Partnership’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

The Partnership’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in a Drilling Partnership which the Partnership may be unable to recover due to the Drilling Partnership’s legal structure. The Partnership may have to pay additional consideration in the future as a well or Drilling Partnership becomes uneconomic under the terms of the Drilling Partnership’s agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by the Partnership. There were no impairments of proved oil and gas properties recorded by the Partnership for the three months ended March 31, 2011 and 2010.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved oil and gas properties recorded by the Partnership for the three months ended March 31, 2011 and 2010.

During the three months ended December 31, 2010, the Partnership recognized a $49.7 million asset impairment related to oil and gas properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in Tennessee. This impairment related to the carrying amount of these oil and gas properties

 

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being in excess of its estimate of their fair value at December 31, 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Capitalized Interest

The Partnership and its subsidiaries 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 rate used to capitalize interest on combined borrowed funds by the Partnership in the aggregate was 5.9% and 7.4% for the three months ended March 31, 2011 and 2010, respectively. The aggregate amount of interest capitalized by the Partnership was $0.4 million and $0.1 million for the three months ended March 31, 2011 and 2010, respectively.

Intangible Assets

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, which APL amortizes 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 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 or less than the average length.

Partnership management and operating contracts. The Partnership recorded its own intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at March 31, 2011 and December 31, 2010 (in thousands):

 

		March 31, 2011				December 31, 2010				Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships		$	205,313			$	205,313				3 – 6
Partnership management and operating contracts			14,344				14,344				1 – 13
		$	219,657			$	219,657
Accumulated Amortization:
Customer contracts and relationships		$	(84,710	)		$	(78,934	)
Partnership management and operating contracts			(12,351	)			(12,180	)
		$	(97,061	)		$	(91,114	)
Net Carrying Amount:
Customer contracts and relationships		$	120,603			$	126,379
Partnership management and operating contracts			1,993				2,164
		$	122,596			$	128,543

Amortization expense on intangible assets was $6.0 million for both the three months ended March 31, 2011 and 2010. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2011 - $17.8 million; 2012 - $23.3 million; 2013 - $23.3 million; 2014 - $19.7 million; and 2015 - $14.7 million.

Goodwill

At March 31, 2011 and December 31, 2010, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. There were no changes in the carrying amount of goodwill for the three months

 

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ended March 31, 2011 and 2010.

The Partnership tests its 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, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Partnership’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. The Partnership will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three months ended March 31, 2011 and 2010, no impairment indicators arose and no goodwill impairments were recognized by the Partnership.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of 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 15), 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 (loss) 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) from continuing operations and net income from discontinued operations allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):

 

		Three Months Ended March 31,
		2011				2010
Continuing operations:
Net income		$	241,710			$	18,168
(Income) loss attributable to non-controlling interests			(211,449	)			4,116
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			(4,711	)			(24,506	)
Net income (loss) attributable to common limited partners			25,550				(2,222	)
Less: Net income attributable to participating securities – phantom units(1)			(98	)			—
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit		$	25,452			$	(2,222	)

 

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Discontinued operations:
Net income (loss)		$	(81	)		$	6,781
(Income) loss attributable to non-controlling interests			71				(5,923	)
Net income (loss) utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit		$	(10	)		$	858

 

(1)

Net income attributable to common limited partners’ ownership interest is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended March 31, 2010, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 138,000 phantom units because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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 15).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

 

		Three Months Ended March  31,
		2011				2010
Weighted average common limited partners per unit - basic			39,010				27,704
Add effect of dilutive incentive awards(1)			235				—
Weighted average common limited partners per unit - diluted			39,245				27,704

 

(1)	For the three months ended March 31, 2010, approximately 43,000 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Revenue Recognition

Certain energy activities are conducted by the Partnership through and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues within its consolidated combined statements of operations.

The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest and/or overriding royalty. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and liquids, along with the fees earned from its gathering and processing 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 natural gas liquids

 

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(“NGLs”), if any, off of 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 is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

 

•

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas. APL is also paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas.

 

•

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP contracts may include a fee component, which is charged to the producer.

 

•

Keep-Whole Contracts. These contracts require APL, as the gatherer and processor, to gather or purchase raw natural gas at current market rates. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to NGLs extracted when processed through a plant. APL must make up or “keep the producer whole” for this loss in volume. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the volume of residue gas available for redelivery to the producer may be less than received from the producer; or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to mitigate the risk associated with keep-whole contracts, APL imposes a fee to gather gas that is settled under this arrangement. In addition, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk.

The Partnership accrues unbilled revenue 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 from the Partnership’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at March 31, 2011 and December 31, 2010 of $74.3 million and $78.6 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined balance sheets.

Comprehensive Income

Comprehensive income includes net income 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 accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. The following table sets forth the calculation of the Partnership’s comprehensive income (in thousands):

 

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		Three Months Ended March 31,
		2011				2010
Net income		$	241,629			$	24,949
Income attributable to non-controlling interests			(211,378	)			(1,807	)
Income attributable to AEI related to the Transferred Business acquired on February 17, 2011			(4,711	)			(24,506	)
Net income (loss) attributable to common unitholders			25,540				(1,364	)
Other comprehensive income (loss):
Net change in fair value of derivative instruments accounted for as cash flow hedges			442				19,985
Less: reclassification adjustment for realized gains in net income (loss)			(6,029	)			139
Net change in non-controlling interest related to items in other comprehensive income (loss)			(1,465	)			(9,107	)
Total other comprehensive income (loss)			(7,052	)			11,017
Comprehensive income attributable to common unitholders		$	18,488			$	9,653

Recently Adopted Accounting Standards

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“Update 2010-29”). The amendments in Update 2010-29 affect any public entity as defined by Topic 805, Business Combinations, that enters into business combinations that are material on an individual or aggregate basis. Update 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Update 2010-29 also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The Partnership applied the requirements of Update 2010-29 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.

In December 2010, the FASB issued Accounting Standards Update 2010-28, Intangibles - Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (“Update 2010-28”). Update 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist in between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Partnership applied the requirements of Update 2010-28 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, the Partnership acquired the Transferred Business from AEI, the former parent of its general partner, which included the following assets:

 

•

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which the Partnership will fund a portion of its natural gas and oil well drilling;

 

•

proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee;

 

•

certain producing natural gas and oil properties, upon which the Partnership will be developers and producers;

 

•

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

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•

a direct and indirect ownership interest in Lightfoot (see Notes 1 and 6).

For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, the Partnership also received $124.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $528.7 million.

Concurrent with the Partnership’s acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.

In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 2). As such, the Partnership recognized the assets acquired and liabilities assumed at carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. The Partnership recognized a non-cash decrease of $255.0 million in partner’s capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the carrying value of the assets acquired and liabilities assumed, including any the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

 

Cash		$	159,180
Accounts receivable			18,090
Accounts receivable – affiliate			45,682
Prepaid expenses and other			6,955
Total current assets			229,907
Property, plant and equipment, net			516,625
Goodwill			31,784
Intangible assets, net			2,107
Other assets, net			20,416
Total long-term assets			570,932
Total assets acquired		$	800,839
Accounts payable		$	59,202
Net liabilities associated with drilling contracts			47,929
Accrued well completion costs			39,552
Current portion of derivative payable to Drilling Partnerships			25,659
Accrued liabilities			25,283
Total current liabilities			197,625
Long-term derivative payable to Drilling Partnerships			31,719
Asset retirement obligations			42,791
Total long-term liabilities			74,510
Total liabilities assumed		$	272,135
Carrying value of net assets acquired		$	528,704

Also in accordance with prevailing accounting literature, the Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

 

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NOTE 4 – DISCONTINUED OPERATIONS

On September 16, 2010, APL completed the sale of its Elk City natural gas gathering and processing system to Enbridge Energy Partners, L.P. (NYSE: EEP) for $682.0 million in cash, excluding any working capital or other adjustments. APL used the net proceeds from the transaction to terminate its term loan and reduce borrowings under its revolving credit facility (see Note 8). The Partnership accounted for the sale of the Elk City system assets as discontinued operations within its consolidated combined financial statements and recorded a gain of $312.1 million on the sale within income (loss) from discontinued operations on its consolidated combined statement of operations during the period the transaction occurred.

The following table summarizes the components included within income (loss) from discontinued operations on the Partnership’s consolidated combined statements of operations (in thousands):

 

		Three Months Ended March  31,
		2011				2010
Total revenues		$	—			$	41,984
Total costs and expenses			(81	)			(35,203	)
Income (loss) from discontinued operations		$	(81	)			6,781

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

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

 

		March 31, 2011				December 31, 2010				Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	49,673			$	46,495
Pre-development costs			2,013				2,337
Wells and related equipment			808,026				798,269
Total proved properties			859,712				847,101
Unproved properties			41,220				42,520
Support equipment			8,142				8,138
Total natural gas and oil properties			909,074				897,759
Pipelines, processing and compression facilities			1,390,655				1,370,230				2 – 40
Rights of way			157,360				156,797				20 – 40
Land, buildings and improvements			14,512				14,465				3 – 40
Other			28,299				26,367				3 – 10
			2,499,900				2,465,618
Less – accumulated depreciation, depletion and amortization			(636,135	)			(616,132	)
		$	1,863,765			$	1,849,486

NOTE 6 – OTHER ASSETS

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

 

		March 31, 2011				December 31, 2010
Deferred financing costs, net of accumulated amortization of $30,635 and $24,436 at March 31, 2011 and December 31, 2010, respectively		$	27,667			$	28,327
Investment in Lightfoot			19,679				18,912
APL long-term note receivable			8,500				—
Security deposits			2,717				2,841

 

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Long-term derivative receivable from Drilling Partnerships			—				4,669
Other investments			45				—
		$	58,608			$	54,749

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). In March 2011, the Partnership recorded $4.9 million of accelerated amortization of deferred financing costs associated with the retirement of its $70.0 million credit facility (see Note 8). In September 2010, APL recorded $4.3 million of accelerated amortization of deferred financing costs associated with the retirement of its term loan with the proceeds from the sale of its Elk City system (see Note 4).

The Partnership owns, directly and indirectly, approximately 13% of Lightfoot LP. In addition, the Partnership owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Chairman of the Partnership’s Board of Directors, is the Chairman of the Board. The Partnership has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships 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. The Partnership recorded income associated with its equity ownership interest in Lightfoot of $1.2 million and a loss of $0.1 million for the three months ended March 31, 2011 and 2010, respectively, within other, net on its consolidated combined statements of operations.

Long-term derivative receivable from Drilling Partnerships represents a portion of the Partnership’s long-term unrealized derivative liability on contracts that have been allocated to the Drilling Partnerships based on their share of total production volumes sold (see Note 9).

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes 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. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on the Partnership’s 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. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

 

		Three Months Ended March 31,
		2011				2010
Asset retirement obligations, beginning of period		$	42,673			$	36,599
Liabilities incurred			93				—
Liabilities settled			(99	)			(6	)
Accretion expense			648				522
Asset retirement obligations, end of period		$	43,315			$	37,115

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated combined statements of operations and the asset retirement obligation liabilities were included within other long-term liabilities in the Partnership’s consolidated combined balance sheets.

 

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NOTE 8 – DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

		March 31, 2011				December 31, 2010
Note payable to affiliate		$	—			$	35,415
APL revolving credit facility			—				70,000
APL 8.125 % senior notes – due 2015			272,329				272,181
APL 8.75 % senior notes – due 2018			223,050				223,050
APL capital leases			691				743
Total debt			496,070				601,389
Less current maturities			(213	)			(35,625	)
Total long-term debt		$	495,857			$	565,764

Credit Facility

On March 22, 2011, the Partnership entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and an initial borrowing base of $125 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by the Partnership. Up to $20.0 million of the credit facility may be in the form of standby letters of credit, of which $0.1 million was outstanding at March 31, 2011, which was not reflected as borrowings on the Partnership’s consolidated combined balance sheets. The facility is secured by substantially all of the Partnership’s assets and is guaranteed by substantially all of its subsidiaries (excluding APL and its subsidiaries). At March 31, 2011, there were no borrowings outstanding under the credit facility. Borrowings under the credit facility bear interest, at the Partnership’s election, of either LIBOR plus an applicable margin (based upon the utilization of the facility, as defined in the credit agreement) 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 (based on the utilization of the facility, as defined in the credit agreement). The Partnership is also required to pay a fee of 0.5% per annum on the unused portion of the borrowing base.

On February 17, 2011, the Partnership entered into a bridge credit facility with a bank in connection with the closing of the acquisition of the Transferred Business, which was replaced with the credit facility previously noted. The credit facility provided for an initial borrowing base of $70 million and a maturity of February 2012.

The credit agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Partnership was in compliance with these covenants as of March 31, 2011. The credit agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a Current Ratio (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the Partnership’s credit facility, its Current Ratio was 2.1 to 1.0 at March 31, 2011.

APL Credit Facility

At March 31, 2011, APL had a $350.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015. 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, 2011 was 5.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $3.2 million was outstanding at March 31, 2011. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at March 31, 2011. At March 31, 2011, APL had $346.8 million of remaining committed capacity under its credit facility, subject to covenant limitations.

 

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Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures, and by the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or 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 for 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. APL was in compliance with these covenants as of March 31, 2011.

APL Senior Notes

At March 31, 2011, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented net of $3.2 million of unamortized discount as of March 31, 2011. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 31, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes in the aggregate are also 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 APL’s obligations under its credit facility.

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of 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 of its assets. APL was in compliance with these covenants as of March 31, 2011.

On March 7, 2011, APL elected, pursuant to the indenture for the 8.125% Senior Notes, to redeem all of the 8.125% Senior Notes on April 8, 2011. The redemption price was determined in accordance with the indenture for the 8.125% Senior Notes, plus accrued and unpaid interest thereon to the redemption date. The Partnership placed $293.7 million in escrow to redeem the $275.5 million principal plus $11.2 million premium and $7.0 million accrued interest. At March 31, 2011, the escrow is recorded on the Partnership’s consolidated combined balance sheets as current assets of $7.0 million and long-term assets of $286.7 million. The redemption of the 8.125% Senior Notes was completed on April 8, 2011 (see Note 17).

Cash payments for interest related to debt made by the Partnership and its subsidiaries were $1.3 million and $18.4 million for the three months ended March 31, 2011 and 2010, respectively.

NOTE 9 – DERIVATIVE INSTRUMENTS

The Partnership and APL use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity and interest rate price risk management activities. The Partnership and APL enter into financial instruments to hedge forecasted natural gas, NGL, crude oil and condensate 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 natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not

 

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the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

The Partnership and APL formally document all relationships between hedging instruments and the items being hedged, including its 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 APL 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 APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Partnership and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, the Partnership and APL recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated combined statements of operations as they occur.

Derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value. The Partnership reflected a net derivative liability on its consolidated combined balance sheets of $25.9 million at March 31, 2011 and a net derivative asset of $55.9 million at December 31, 2010. Of the $3.2 million of net loss in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at March 31, 2011, if the fair values of the instruments remain at current market values, the Partnership will reclassify $1.5 million of losses to its consolidated combined statements of operations over the next twelve month period as these contracts expire, consisting of $0.7 million of losses to gas and oil production revenues and $0.8 million of losses to gathering and processing revenues. Aggregate losses of $1.7 million will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire, consisting of $1.3 million of losses to gas and oil production revenues and $0.4 million of losses to gathering and processing revenues. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Partnership’s own derivative instruments as of March 31, 2011 and December 31, 2010, as well as the gain or loss recognized in the consolidated combined statements of operations for effective derivative instruments for the three months ended March 31, 2011 and 2010:

 

Contract Type		Balance Sheet Location		March 31, 2011				December 31, 2010
Commodity contracts		Current portion of derivative asset		$	512			$	36,621
Commodity contracts		Long-term derivative asset			3,695				36,125
					4,207				72,746
Commodity contracts		Current portion of derivative liability			(1,221	)			(353	)
Commodity contracts		Long-term derivative liability			(4,959	)			(6,293	)
					(6,180	)			(6,646	)
Total derivatives				$	(1,973	)		$	66,100

 

		Three Months Ended March 31,
		2011				2010
Gain (Loss) Recognized in Accumulated OCI		$	442			$	19,985
Gain (Loss) Reclassified from Accumulated OCI into Income		$	(7,731	)		$	(10,637	)

The Partnership enters into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated

 

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over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Partnership recognized gains of $7.7 million and $10.6 million for the three months ended March 31, 2011 and 2010, respectively, on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2011 and 2010 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Prior to its merger transaction with Chevron on February 17, 2011, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships that the Partnership sponsors. Monetization proceeds of $57.4 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents acquired of the Transferred Business at the date of acquisition. The Partnership will allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. At March 31, 2011, the Partnership recognized a current and long-term derivative payable to Drilling Partnerships of $25.7 million and $31.7 million, respectively, on its consolidated combined balance sheets.

At March 31, 2011, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(mmbtu)(1)				(per mmbtu)(1)				(in thousands)(2)
2011			4,680,000			$	4.484				(409	)
2012			5,520,000			$	5.000				(308	)
2013			3,120,000			$	5.288				(355	)
										$	(1,072	)

Natural Gas Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(mmbtu)(1)				(per mmbtu)(1)				(in thousands)(2)
2011		Puts purchased			1,620,000			$	3.750			$	97
2011		Calls sold			1,620,000			$	5.611				(162	)
2012		Puts purchased			1,920,000			$	4.250				611
2012		Calls sold			1,920,000			$	6.084				(702	)
2013		Puts purchased			3,120,000			$	4.750				2,149
2013		Calls sold			3,120,000			$	6.065				(2,526	)
												$	(533	)

Crude Oil Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
				(Bbl) (1)		(per Bbl)(1)		(in thousands)(3)

 

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2011		Puts purchased			45,000			$	90.000			$	74
2011		Calls sold			45,000			$	125.312				(118	)
2012		Puts purchased			60,000			$	90.000				338
2012		Calls sold			60,000			$	117.912				(527	)
2013		Puts purchased			60,000			$	90.000				571
2013		Calls sold			60,000			$	116.396				(706	)
												$	(368	)
									Total Partnership net liability			$	(1,973	)

 

(1)	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

(3)	Fair value based on forward WTI crude oil prices, as applicable.

The Partnership’s commodity price risk management activities include the estimated future natural gas and crude oil production of the Drilling Partnerships. Therefore, prior to the Partnership’s acquisition of the Transferred Business, a portion of any unrealized derivative gain or loss was allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. Prior to the Partnership’s acquisition of the Transferred Business, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At March 31, 2011, hedge monetization cash proceeds of $57.4 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents, and the Partnership will allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The derivative payable related to the hedge monetization proceeds at March 31, 2011 and net unrealized derivative assets at December 31, 2010 were payable to the limited partners in the Drilling Partnerships and are included in the consolidated combined balance sheets as follows (in thousands):

 

		March 31, 2011				December 31, 2010
Current portion of derivative receivable from Partnerships		$	—			$	138
Long-term derivative receivable from Partnerships			—				4,669
Current portion of derivative payable to Partnerships			(25,650	)			(30,797	)
Long-term portion of derivative payable to Partnerships			(31,719	)			(34,796	)
		$	(57,369	)		$	(60,786	)

Atlas Pipeline Partners

The following table summarizes APL’s gross fair values of derivative instruments for the period indicated (in thousands):

 

Contract Type		Balance Sheet Location		March 31, 2011				December 31, 2010
Asset Derivatives
Commodity contracts		Current portion of derivative asset		$	796			$	—
Commodity contracts		Long-term derivative asset			—				—
Commodity contracts		Current portion of derivative liability			3,053				2,624
Commodity contracts		Long-term derivative liability			2,384				1,052
					6,233				3,676
Liability Derivatives
Commodity contracts		Current portion of derivative asset			(638	)			—
Commodity contracts		Long-term derivative asset			—				—
Commodity contracts		Current portion of derivative liability			(19,904	)			(7,188	)
Commodity contracts		Long-term derivative liability			(9,601	)			(6,660	)
					(30,143	)			(13,848	)
Total derivatives				$	(23,910	)		$	(10,172	)

As of March 31, 2011, APL had the following commodity derivatives, which do not qualify for hedge accounting:

 

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Fixed Price Swaps

 

Production Period		Purchased/ Sold		Commodity		Volumes(2)				Average Fixed Price				Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2011		Sold		Natural Gas Basis			1,440,000				(0.728	)		$	(692	)
2011		Purchased		Natural Gas Basis			1,440,000				(0.758	)			735
2011		Sold		Natural Gas Basis			3,300,000				4.637				155
Natural Gas Liquids
2011		Sold		Ethane			5,040,000				0.500				(857	)
2011		Sold		Propane			12,852,000				1.153				(3,031	)
2011		Sold		Isobutane			1,008,000				1.618				(164	)
2011		Sold		Normal Butane			2,772,000				1.580				(841	)
2011		Sold		Natural Gasoline			6,552,000				2.042				(2,625	)
2012		Sold		Propane			14,868,000				1.277				(951	)
2012		Sold		Natural Gasoline			2,520,000				2.395				15
Crude Oil
2011		Sold		Crude Oil			99,000				91.642				(1,598	)
2012		Sold		Crude Oil			84,000				99.500				(579	)
Total Fixed Price Swaps														$	(10,433	)

Options

 

Production Period		Purchased/ Sold		Type		Commodity		Volumes(2)				Average Strike Price				Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2011		Purchased		Put		Propane			14,616,000			$	1.280			$	957
2012		Purchased		Put		Propane			3,780,000			$	1.359			$	627
Crude Oil
2011		Purchased		Put		Crude Oil			402,000				93.356				1,014
2011		Sold		Call		Crude Oil			509,000				93.354				(8,789	)
2011		Purchased(3)		Call		Crude Oil			189,000				125.200				523
2012		Purchased		Put		Crude Oil			60,000				105.003				739
2012		Sold		Call		Crude Oil			498,000				94.694				(9,691	)
2012		Purchased(3)		Call		Crude Oil			180,000				125.200				1,143
Total Options																$	(13,477	)
									Total APL net liability							$	(23,910	)

 

(1)	See Note 10 for discussion on fair value methodology.

(2)	Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

(3)	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

The following tables summarize the gross effect of APL’s derivative instruments on the Partnership’s consolidated combined statement of operations for the period indicated (in thousands):

 

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Gain (Loss) Reclassified from Accumulated OCI into Income

 

				Three Months Ended March 31,
				2011				2010
Contract Type		Location
Interest rate contracts(2)		Interest expense		$	—			$	(1,785	)
Interest rate contracts(2)		Other, net							—
Commodity contracts(2)		Gathering and processing revenue			(1,702	)			(4,943	)
Commodity contracts(2)		Discontinued operations			—				(3,990	)
				$	(1,702	)		$	(10,718	)

Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)

 

				Three Months Ended March 31,
				2011				2010
Contract Type		Location
Interest rate contracts(2)		Gain (loss) on mark-to market derivatives		$	—			$	—
Interest rate contracts(2)		Other, net			—				(6	)
Commodity contracts		Gain (loss) on mark-to market derivatives			(21,645	)			4,292
Commodity contracts		Discontinued operations			—				(153	)
				$	(21,645	)		$	4,133

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its Elk City systems (see Note 4).

(2)	Hedges previously designated as cash flow hedges.

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

 

		March 31, 2011				December 31, 2010
Current portion of derivative asset		$	670			$	36,621
Long-term derivative asset			3,695				36,125
Current portion of derivative liability			(18,072	)			(4,917	)
Long-term derivative liability			(12,176	)			(11,901	)
Total Partnership net asset (liability)		$	(25,883	)		$	55,928

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. 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 assumption 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.

 

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its and APL’s outstanding derivative contracts (see Note 9). The Partnership’s and APL’s 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 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, 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.

Information for assets and liabilities measured at fair value at March 31, 2011 and December 31, 2010 was as follows (in thousands):

 

		Level 1				Level 2				Level 3				Total
March 31, 2011
Partnership commodity-based derivatives		$	—			$	(1,973	)		$	—			$	(1,973	)
APL commodity-based derivatives			—				(17,040	)			(6,870	)			(23,910	)
Total		$	—			$	(19,013	)		$	(6,870	)		$	(25,883	)
December 31, 2010
Partnership commodity-based derivatives		$	—			$	66,100			$	—			$	66,100
APL commodity-based derivatives			—				(8,382	)			(1,790	)			(10,172	)
Total		$	—			$	57,718			$	(1,790	)		$	55,928

APL’s Level 3 fair value amount relates 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 as of March 31, 2011 (in thousands):

 

		NGL Fixed Price Swaps								NGL Put Options								Total
		Volume(1)				Amount				Volume(1)				Amount				Amount
Balance – January 1, 2011			32,760			$	(1,790	)			—			$	—			$	(1,790	)
New contracts			22,176				—				18,396				—				—
Cash settlements(2)(3)			(9,324	)			1,703				—				—				1,703
Net change in unrealized loss(2)			—				(8,367	)			—				(1,526	)			(9,893	)
Option premium recognition(3)			—				—				—				3,110				3,110
Balance – March 31, 2011			45,612			$	(8,454	)			18,396			$	1,584			$	(6,870	)

 

(1)	Volumes are stated in thousand gallons.

(2)	Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations.

(3)	Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.

The Partnership’s other current assets and liabilities on its consolidated combined balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s debt at March 31, 2011 and December 31, 2010, which consists principally of APL’s Senior Notes and borrowings under the Partnership’s and APL’s revolving credit facilities, were $495.1 million and $532.3 million, respectively, compared with the carrying amounts of $496.1 million and $601.4 million, respectively. The APL Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

 

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The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 7). Information for assets that are measured at fair value on a nonrecurring basis for the three months ended March 31, 2011 and 2010 was as follows (in thousands):

 

		Three Months Ended March 31,
		2011								2010
		Level 3				Total				Level 3				Total
Asset retirement obligations		$	93			$	93			$	—			$	—
Total		$	93			$	93			$	—			$	—

NOTE 11 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective partnership agreements.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

General Commitments

The Partnership is the managing general partner of the Drilling Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Partnership believes that any liability incurred would not be material. The Partnership may be required to subordinate a part of its net partnership revenues from the Drilling Partnerships to the benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2011 and 2010, $1.4 million and $3.3 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

On February 26, 2010, APL received notice from Williams, its former joint venture partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by APL to Laurel Mountain. Under the Formation and Exchange Agreement with Williams (“Formation Agreement”): (i) Williams had nine months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL had 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects, which was extended until March 31, 2011. On March 26, 2010, APL delivered notice, disputing Williams’ alleged title defects as well as the amounts claimed. APL has delivered documentation to Williams which should resolve many of the alleged title defects. Although APL’s cure period has technically expired, APL, without objection from Williams, continues to work to resolve the remaining alleged title defects. In addition, AEI delivered a proposed assignment to Laurel Mountain that should resolve some of the alleged deficiencies. Williams also claims, in a letter dated August 26, 2010, that the alleged title defects violate APL’s representation with respect to sufficiency of the assets contributed to Laurel Mountain. If valid, this would make Williams’ title defect claims subject to a higher deductible (which is noted below). APL believes its representations with respect to title are Williams’ sole and exclusive remedy with respect to title matters.

In August 2010, Williams asserted additional indemnity claims under the Formation Agreement totaling approximately $19.8 million. Williams’ claims are generally based on APL’s alleged failure to construct and maintain the assets contributed to Laurel Mountain in accordance with “standard industry practice” or applicable law. As a preliminary matter, APL believes Williams has overstated its claim by forty-nine percent (49%), because, under the Formation Agreement, these claims are reduced on a pro-rata basis to equal Williams’ percentage ownership interest in

 

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Laurel Mountain. APL has received additional information from Williams and an adverse outcome is probable with respect to a portion of Williams’s claim. Under the Formation Agreement, Williams’ indemnity claims are capped, in the aggregate, at $27.5 million. In addition, APL is entitled to indemnification from AEI with respect to some of Williams’ claims. APL has established an accrual with respect to the portion of Williams’ claims that it deems probable, which is less than 51% of the amounts asserted by Williams. In addition, APL is entitled to indemnification from AEI with respect to some of Williams’ claims.

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

As of March 31, 2011, the Partnership and APL are committed to expend approximately $126.8 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

Following the November 9, 2010 announcement that AEI had entered into a definitive agreement to be acquired by Chevron Corporation and that we and APL agreed to enter into separate transactions with AEI relating to certain AEI natural gas reserves and other assets and fee revenues, and APL’s interest in Laurel Mountain, a purported shareholder derivative case was filed on November 16, 2010, in the Western District of Pennsylvania federal court, Ussach v. Atlas Energy, Inc., et al., C.A. No. 2:10-cv-1533. The complaint is asserted derivatively on behalf of APL and named Atlas Energy, Inc., Atlas Pipeline GP, and members of the Managing Board of Atlas Pipeline GP as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the sale to AEI of APL’s interest in Laurel Mountain and that AEI has been unjustly enriched. In the complaint, among other relief, the plaintiff requested damages and equitable and injunctive relief, as well as restitution and disgorgement from the individual defendants. On February 22, 2011, the plaintiff voluntarily dismissed its complaint without prejudice. The Partnership has not received an indication whether the plaintiff intends to reassert its claims in another forum. The defendants believe the claims are without merit.

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 13 – ISSUANCES OF APL UNITS

The Partnership recognizes gains on APL’s equity transactions as a credit to equity rather than as income pursuant to prevailing accounting literature. These gains represent the Partnership’s portion of the excess net offering price per unit of each of APL’s units over the book carrying amount per unit.

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units are entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The APL Class C Preferred Units are not convertible into common units of APL. APL has the right at any time to redeem some or all (but not less than 2,500) of the outstanding APL Class C Preferred Units for cash at an amount equal to the APL Class C Preferred Face Value being redeemed plus accrued but unpaid dividends.

In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see Note 8), and to fund the early termination of certain derivative agreements.

NOTE 14 – CASH DISTRIBUTIONS

 

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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, 2010 through March 31, 2011 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid or Payable		For Quarter Ended		Cash Distribution per Common Limited Partner Unit
November 16, 2010		September 30, 2010		$	0.05
February 18, 2011		December 31, 2010		$	0.07

On April 26, 2011, the Partnership declared a cash distribution of $0.11 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $5.6 million distribution will be paid on May 20, 2011 to unitholders of record at the close of business on May 13, 2011.

Atlas Pipeline Partners 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 15% and 50% 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, 2010 through March 31, 2011 were as follows (in thousands, except per unit amounts):

 

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
November 14, 2010		September 30, 2010		$0.35		$18,660		$363
February 14, 2011		December 31, 2010		$0.37		$19,735		$398

On April 26, 2011, APL declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $21.8 million distribution, including $2.7 million to the Partnership for its general partner interest, will be paid on May 13, 2011 to unitholders of record at the close of business on May 6, 2011.

NOTE 15 – BENEFIT PLANS

2010 Long-Term Incentive Plan

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 Partnership’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 5,300,000 common limited partner units. At March 31, 2011, the Partnership had 3,792,000 phantom units and unit options outstanding under the 2010 LTIP, with 1,508,000 phantom units and unit options available for grant.

Upon a change in control, as defined in the 2010 LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, 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), in any case following a change in control, 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.

 

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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 a 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. Through March 31, 2011, phantom units granted under the 2010 LTIP generally will vest 25% of the on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Of the phantom units outstanding under the 2010 LTIP at March 31, 2011, there are no units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at March 31, 2011 include DERs granted to the Participants by the LTIP Committee. There were no amounts paid with respect to the 2010 LTIP DERs for the three months ended March 31, 2011 and 2010.

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

 

		Three Months Ended March 31,
		2011								2010
		Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value
Outstanding, beginning of period			—			$	—				—			$	—
Granted			1,566,000				22.23				—				—
Vested (1)			—				—				—				—
Forfeited			—				—				—				—
Outstanding, end of period(2)			1,566,000			$	22.23				—			$	—
Non-cash compensation expense recognized (in thousands)						$	176							$	—

 

(1)	No phantom unit awards were exercised during the three months ended March 31, 2011 and 2010.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2011 was $35.0 million.

At March 31, 2011, the Partnership had approximately $34.6 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 shall determine 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. Through March 31, 2011, unit options granted under the 2010 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2010 LTIP. There are no unit options outstanding under the 2010 LTIP at March 31, 2011 that will vest within the following twelve months.

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

 

		Three Months Ended March 31,
		2011								2010
		Number of Unit Options				Weighted Average Exercise Price				Number of Unit Options				Weighted Average Exercise Price
Outstanding, beginning of period			—			$	—				—			$	—
Granted			2,226,000				22.23				—				—
Forfeited			—				—				—				—
Outstanding, end of period(1)(2)			2,226,000			$	22.23				—			$	—
Options exercisable, end of period(3)			—			$	—				—			$	—

 

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Non-cash compensation expense recognized (in thousands)				$	112							$	—

 

(1)	The weighted average remaining contractual life for outstanding options at March 31, 2011was 10.0 years.

(2)	The aggregate intrinsic value of options outstanding at March 31, 2011 was approximately $0.3 million.

(3)	No options were exercisable at March 31, 2011. There were no options exercised during the three months ended March 31, 2011 and 2010.

At March 31, 2011, the Partnership had approximately $22.0 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 to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

 

		Three Months Ended March  31, 2011
Expected dividend yield			1.5	%
Expected stock price volatility			48.0	%
Risk-free interest rate			2.8	%
Expected term (in years)			6.88
Fair value of stock options granted		$	9.93

2006 Long-Term Incentive Plan

The Board of Directors of the General Partner 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 2,100,000 common limited partner units. At March 31, 2011, the Partnership had 986,025 phantom units and unit options outstanding under the Partnership 2006 LTIP, with 927,161 phantom units and unit options available for grant.

2006 Phantom Units. Through March 31, 2011, phantom units granted under the 2006 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. Of the phantom units outstanding under the 2006 LTIP at March 31, 2011, 8,928 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at March 31, 2011 include DERs granted to the Participants by the LTIP Committee. The amount paid with respect to 2006 LTIP’s DERs was $1,000 for the three months ended March 31, 2011. This amount was recorded as a reduction of partners’ capital on the Partnership’s consolidated combined balance sheet. There were no amounts paid with respect to 2006 LTIP’s DERs for the three months ended March 31, 2010.

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

 

		Three Months Ended March 31,
		2011								2010
		Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value
Outstanding, beginning of period			27,294			$	5.98				138,875			$	22.18
Granted			13,395				15.92				—				—
Vested (1)			(9,664	)			13.75				—				—
Forfeited			—				—				(500	)			32.28
Outstanding, end of period(2)			31,025			$	7.85				138,375			$	22.14
Non-cash compensation expense recognized (in thousands)						$	185							$	196

 

 

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(1)	The intrinsic value for phantom unit awards exercised during the three months ended March 31, 2011, was $0.2 million. No phantom unit awards were exercised during the three months ended March 31, 2010.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2011 was $0.7 million.

At March 31, 2011, the Partnership had approximately $0.5 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. Through March 31, 2011, unit options granted under the 2006 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. There are no unit options outstanding under the 2006 LTIP at March 31, 2011 that will vest within the following twelve months.

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

 

		Three Months Ended March 31,
		2011								2010
		Number of Unit Options				Weighted Average Exercise Price				Number of Unit Options				Weighted Average Exercise Price
Outstanding, beginning of period			955,000			$	20.54				955,000			$	20.54
Granted			—				—				—				—
Forfeited			—				—				—				—
Outstanding, end of period(1)(2)			955,000			$	20.54				955,000			$	20.54
Options exercisable, end of period(3)			955,000			$	20.54				213,750			$	22.56
Non-cash compensation expense recognized (in thousands)						$	28							$	155

 

(1)	The weighted average remaining contractual life for outstanding options at March 31, 2011 was 5.8 years.

(2)	The aggregate intrinsic value of options outstanding at March 31, 2011 was approximately $1.9 million.

(3)	The weighted average remaining contractual life for options exercisable at March 31, 2011 was 5.8 years. There were no options exercised during the three months ended March 31, 2011 and 2010.

At March 31, 2011, the Partnership had no 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 to estimate the weighted average fair value of options granted. No options were granted during the three months ended March 31, 2011 and 2010 under the 2006 Plan.

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan (“APL 2010 LTIP”), (collectively 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. On June 15, 2010, APL’s unitholders approved the terms of the APL 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and DERs. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by APL’s general partner. Under the 2010 APL LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in previous plans. At March 31, 2011, APL had 414,716 phantom units and unit options outstanding under the APL LTIPs, with 2,495,617 phantom units and unit options available for grant.

APL Phantom Units. Through March 31, 2011, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan agreed to exchange their APL Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period. The first tranche vested on June 1, 2010. Awards will automatically vest upon a change of control, as

 

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defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at March 31, 2011, 159,483 units will vest within the following twelve months. On February 17, 2011, APL’s employment agreement with its Chief Executive Officer (“CEO”) was terminated in connection with AEI’s merger with Chevron and 75,250 outstanding phantom units, which represents all outstanding phantom units held by APL’s CEO, automatically vested and were issued.

All phantom units outstanding under the APL LTIPs at March 31, 2011 include DERs granted to the participants by the APL LTIP Committee. The amount paid with respect to APL LTIP DERs was $0.2 million for the three months ended March 31, 2011. This amount was recorded as a reduction of non-controlling interest on the Partnership’s consolidated combined balance sheet. No APL LTIP DERs were paid during the three months ended March 31, 2010.

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

 

		Three Months Ended March 31,
		2011								2010
		Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value
Outstanding, beginning of period			490,886			$	11.75				52,233			$	39.72
Granted			5,730				30.63				1,000				12.70
Vested (1)			(81,900	)			13.60				(2,695	)			42.78
Forfeited			—				—				(1,375	)			43.99
Outstanding, end of period(2)			414,716			$	11.65				49,163			$	38.88
Non-cash compensation expense recognized (in thousands)(3)						$	1,174							$	122

 

(1)	The intrinsic values for phantom unit awards exercised during the three months ended March 31, 2011 and 2010 were $2.5 million and $0.4 million, respectively.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2011was $14.3 million.

(3)	Non-cash compensation expense includes $0.5 million related to APL Bonus Units converted to phantom units during the three months ended March 31, 2011.

At March 31, 2011, APL had approximately $2.2 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards.

APL Unit Options. The exercise price of the unit option is equal to the fair market value of APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2011, unit options granted under the APL LTIPs generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL LTIPs. On February 17, 2011, the employment agreement with APL’s CEO of the General Partner was terminated in connection with AEI’s merger with Chevron and 50,000 outstanding unit options held by its CEO automatically vested. As of March 31, 2011, all unit options were exercised. There are no unit options outstanding under APL LTIPs at March 31, 2011 that will vest within the following twelve months.

The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:

 

		Three Months Ended March 31,
		2011								2010
		Number of Unit Options				Weighted Average Exercise Price				Number of Unit Options				Weighted Average Exercise Price
Outstanding, beginning of period			75,000			$	6.24				100,000			$	6.24
Granted			—				—				—				—
Exercised(1)			(75,000	)			6.24				—				—

 

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Forfeited			—				—				—				—
Outstanding, end of period(2)			—			$	—				100,000			$	6.24
Options exercisable, end of period(2)			—			$	—				25,000			$	6.24
Non-cash compensation expense recognized (in thousands)(3)		$	3							$	1

 

(1)	The intrinsic value for the options exercised during the three months ended March 31, 2011 was $1.8 million.

(2)	No options are outstanding or exercisable.

(3)	Incremental compensation expense of $2,000, related to the accelerated vesting of options held by APL’s CEO, was recognized during the three months ended March 31, 2011.

At March 31, 2011, APL had no unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.

APL uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the three months ended March 31, 2011 and 2010 under the APL LTIPs.

NOTE 16 — OPERATING SEGMENT INFORMATION

The Partnership’s operations include four 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 are as follows (in thousands):

 

		Three Months Ended March 31,
		2011				2010(1)
Gas and oil production
Revenues		$	17,626			$	25,480
Costs and expenses			(3,921	)			(4,043	)
Depreciation, depletion and amortization expense			(6,566	)			(7,897	)
Segment income		$	7,139			$	13,540
Well construction and completion
Revenues		$	17,725			$	72,642
Costs and expenses			(15,021	)			(61,561	)
Segment income		$	2,704			$	11,081
Other partnership management(2)
Revenues		$	12,249			$	10,266
Costs and expenses			(8,094	)			(6,718	)
Depreciation, depletion and amortization expense			(1,135	)			(743	)
Segment income		$	3,020			$	2,805
Atlas Pipeline
Revenues (3)		$	257,324			$	241,615
Costs and expenses			(231,250	)			(191,907	)
Depreciation and amortization expense			(18,906	)			(18,457	)
Segment income		$	7,168			$	31,251
Reconciliation of segment income to net income from continuing operations
Segment income:
Gas and oil production		$	7,139			$	13,540
Well construction and completion			2,704				11,081

 

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Other partnership management			3,020				2,805
Atlas Pipeline			7,168				31,251
Total segment income			20,031				58,677
General and administrative expenses(4)			(16,190	)			(10,541	)
Gain (loss) on asset sales			255,947				(2,947	)
Interest expense(4)			(18,078	)			(27,021	)
Net income from continuing operations		$	241,710			$	18,168
Capital expenditures
Gas and oil production		$	4,738			$	20,116
Well construction and completion			—				—
Other partnership management			1,152				6,195
Atlas Pipeline			18,333				6,787
Corporate and other			1,842				2,094
Total capital expenditures		$	26,065			$	35,192

 

		March 31, 2011				December 31, 2010
Balance sheet
Goodwill:
Gas and oil production		$	18,145			$	18,145
Well construction and completion			6,389				6,389
Other partnership management			7,250				7,250
		$	31,784			$	31,784
Total assets:
Gas and oil production		$	524,549			$	592,452
Well construction and completion			6,932				9,627
Other partnership management			45,042				38,592
Atlas Pipeline			1,917,250				1,752,568
Corporate and other			135,564				42,023
		$	2,629,337			$	2,435,262

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sales of certain APL assets in September 2010 (see Note 4).

(2)	Includes revenues and expenses from well services, transportation, administration and oversight and other income that do not meet the quantitative threshold for reporting segment information.

(3)	Includes losses of $21.6 million on mark-to-market derivatives for the three months ended March 31, 2011, and a gain of $4.7 million during the three months ended March 31, 2010.

(4)	The Partnership notes that interest expense and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 17 — SUBSEQUENT EVENTS

Joint-venture Agreement. In May 2011, the Partnership entered into a joint venture agreement with a third-party drilling company, under which the Partnership’s investment drilling programs will invest approximately $35 million to drill wells into the Marcellus Shale formation in West Virginia.

APL Pipeline Acquisition. In May 2011, APL purchased a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) from Buckeye Partners, L.P. for $85.0 million. WTLPG owns a 2,295 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu for fractionation. The pipeline is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest.

Cash Distributions. On April 26, 2011, the Partnership declared a cash distribution of $0.11 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $5.6 million distribution will be paid on May 20, 2011 to unitholders of record at the close of business on May 13, 2011.

APL Cash Distribution. On April 26, 2011, APL declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $21.8

 

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million distribution, including $2.7 million to the Partnership, will be paid on May 13, 2011 to unitholders of record at the close of business on May 6, 2011.

APL Senior Note Redemption. On April 8, 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. APL also purchased $7.2 million, or 3.24%, of the outstanding 8.75% Senior Notes, which represented all of the 8.75% Senior Notes validly tendered pursuant to its offer to purchase these notes and paid $0.2 million in accrued and unpaid interest for a total payment of $7.4 million (see Note 8). APL funded the purchases with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see Note 3).

 

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements —

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, 2010. 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.

BUSINESS OVERVIEW

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS). On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner (see “Recent Developments”). These assets principally included the following:

 

•

AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we will fund a portion of our natural gas and oil well drilling;

 

•

proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee;

 

•

certain producing natural gas and oil properties, upon which the Partnership will be developers and producers;

 

•

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

•

a direct and indirect ownership interest in Lightfoot LP and Lightfoot GP (collectively, “Lightfoot”), which incubate new MLPs and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP. We also have direct and indirect ownership interests in Lightfoot LP.

We also maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At March 31, 2011, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.8% common limited partner interest.

FINANCIAL PRESENTATION

Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at March 31, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL’s net income.

In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see “Recent Developments”). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between

 

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entities under common control require that assets and liabilities be recognized by the acquirer at carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

 

•

Recognized the assets acquired and liabilities assumed from the Transferred Business at their carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

 

•

Retrospectively adjusted our consolidated combined balance sheet as of December 31, 2010, our consolidated combined statement of partners’ capital for the three months ended March 31, 2011, and our consolidated combined statements of operations and cash flows for the three months ended March 31, 2011 and 2010 to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period; and

 

•

Adjusted the presentation of our consolidated combined statements of operations for the three months ended March 31, 2011 and 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. Furthermore, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense as we were unable to identify and allocate such amounts to the Transferred Business for the respective period.

APL completed the sale of its Elk City system on September 16, 2010. As such, we have adjusted the prior year consolidated financial information presented to reflect the amounts related to the operations of this system as discontinued operations.

SUBSEQUENT EVENTS

Joint-venture Agreement. In May 2011, we entered into a joint venture agreement with a third-party drilling company, under which our investment drilling programs will invest approximately $35 million to drill wells into the Marcellus Shale formation in West Virginia.

APL Pipeline Acquisition. In May 2011, APL purchased a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) from Buckeye Partners, L.P. for $85.0 million. WTLPG owns a 2,295 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu for fractionation. The pipeline is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest.

Cash Distributions. On April 26, 2011, we declared a cash distribution of $0.11 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $5.6 million distribution will be paid on May 20, 2011 to unitholders of record at the close of business on May 13, 2011.

APL Cash Distributions. On April 26, 2011, APL declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2011. The $21.8 million distribution, including $2.7 million to us, will be paid on May 13, 2011 to unitholders of record at the close of business on May 6, 2011.

APL Senior Note Redemption. On April 8, 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. APL also purchased $7.2 million, or 3.24%, of its outstanding 8.75% Senior Notes, which represented all of the 8.75% Senior Notes validly tendered pursuant to its offer to purchase these notes and paid $0.2 million in accrued and unpaid interest for a total payment of $7.4 million. APL funded the purchases with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see “Recent Developments”).

 

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RECENT DEVELOPMENTS

Acquisition from AEI. On February 17, 2011, we completed an acquisition of the Transferred Business from AEI, the former parent of our general partner, which included the following assets:

 

•

AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we will fund a portion of our natural gas and oil well drilling;

 

•

proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee;

 

•

certain producing natural gas and oil properties, upon which the Partnership will be developers and producers;

 

•

all of the ownership interests in Atlas Energy GP LLC, our general partner; and

 

•

a direct and indirect ownership interest in Lightfoot, which incubates new MLPs and invests in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP. We also have direct and indirect ownership interests in Lightfoot LP.

For the assets acquired and liabilities assumed, we issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on our February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, we also received $124.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $528.7 million.

Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with our acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, net of expenses, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.

New Credit Facility. On March 22, 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and an initial borrowing base of $125 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our 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 our assets. The credit agreement also requires us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a Current Ratio (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011.

On February 17, 2011, we entered into a bridge credit facility with a bank in connection with the closing of the acquisition of the Transferred Business, which was replaced with the current credit facility. The credit facility provided for an initial borrowing base of $70 million and a maturity of February 2012.

 

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CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:

 

•

Well construction and completion. For each well that is drilled by an investment partnership, we receive an 18% mark-up on those costs incurred to drill and complete the well;

 

•

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $249,000 for horizontal wells drilled and a range of $15,700 to $62,200 for all other well types. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well; and

 

•

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

APL’s principal revenue is generated from the gathering and sale of natural gas, natural gas liquids (“NGL”s) and condensate. Variables that affect its revenue are:

 

•

the volumes of natural gas APL gathers and processes, which in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;

 

•

the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

 

•

the NGL and BTU content of the gas that is gathered and processed;

 

•

the contract terms with each producer; and

 

•

the efficiency of APL’s gathering systems and processing plants.

Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of 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 is recognized upon physical delivery of the natural gas.

GENERAL TRENDS AND OUTLOOK

 

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

Natural Gas Supply and Outlook. The areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. While we 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 by third parties in the development of new natural gas reserves.

Reserve Outlook. Our future oil and gas reserves, production, cash flow and our ability to make payments on our revolving credit facility depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas and oil production operations in various shale plays in the northeastern and midwestern United States. As part of our agreement with AEI to acquire the Transferred Business, we have entered into certain agreements which restrict our ability to drill additional wells in certain areas of the Marcellus Shale. Through March 31, 2011, we have established production positions in the following areas:

 

•

Appalachia basin, including activities in the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas;

 

•

Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

 

•

New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile;

 

•

Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale; and

 

•

Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three months ended March 31, 2011 and 2010:

 

		Three Months Ended March  31,
		2011				2010
Gross wells drilled:
Appalachia			3				10
New Albany/Antrim			—				—
Niobrara			17				—
			20				10
Our share of gross wells drilled(1):
Appalachia			1				2
New Albany/Antrim			—				—

 

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Niobrara			5				—
			6				2
Gross wells turned in line:
Appalachia			1				35
New Albany/Antrim			12				18
Niobrara			18				—
			31				53

 

(1)	Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

Production Volumes. The following table presents our total net gas and oil production volumes and production per day for the three months ended March 31, 2011 and 2010:

 

		Three Months Ended March 31,
		2011				2010
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)			2,630				3,331
Oil (000’s Bbls)			65	(4)			77	(4)
Total (MMcfe)			3,023				3,793
New Albany/Antrim:
Natural gas (MMcf)			292				92
Oil (000’s Bbls)			—				—
Total (MMcfe)			292				92
Niobrara:
Natural gas (MMcf)			17				—
Oil (000’s Bbls)			—				—
Total (MMcfe)			17				—
Total:
Natural gas (MMcf)			2,939				3,423
Oil (000’s Bbls)			65	(4)			77	(4)
Total (MMcfe)			3,332				3,885
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)			29,226				37,008
Oil (Bpd)			727	(4)			856	(4)
Total (Mcfed)			33,589				42,147
New Albany/Antrim:
Natural gas (Mcfd)			3,244				1,022
Oil (Bpd)			—				—
Total (Mcfed)			3,244				1,022
Niobrara:
Natural gas (Mcfd)			185				—
Oil (Bpd)			—				—
Total (Mcfed)			185				—
Total:
Natural gas (Mcfd)			32,655				38,031
Oil (bpd)			727	(4)			856	(4)
Total (Mcfed)			37,019				43,169

 

(1)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

 

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(2)	“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.

(3)	Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

(4)	Includes NGL production volume for the three months ended March 31, 2011 and 2010.

Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2010. The following table presents our production revenues and average sales prices for our natural gas and oil production for the three months ended March 31, 2011 and 2010, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

 

		Three Months Ended March 31,
		2011				2010
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue		$	12,215			$	20,662
Oil revenue			3,904	(5)			4,213	(5)
Total revenues		$	16,119			$	24,875
New Albany/Antrim:
Natural gas revenue		$	1,439			$	605
Oil revenue			—				—
Total revenues		$	1,439			$	605
Niobrara:
Natural gas revenue		$	68			$	—
Oil revenue			—				—
Total revenues		$	68			$	—
Total:
Natural gas revenue		$	13,722			$	21,267
Oil revenue			3,904	(5)			4,213	(5)
Total revenues		$	17,626			$	25,480
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3)		$	5.46			$	7.65
Total realized price, before hedge (3)		$	4.47			$	5.97
Oil (per Bbl):
Total realized price, after hedge		$	87.39			$	72.54
Total realized price, before hedge		$	87.39			$	67.90
Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(4)		$	0.86			$	0.84
Production taxes			0.06				0.04
Transportation and compression			0.57				0.57
		$	1.49			$	1.45
New Albany/Antrim:
Lease operating expenses		$	1.12			$	1.77
Production taxes			0.08				0.13
Transportation and compression			0.09				0.08
		$	1.28			$	1.98
Niobrara:
Lease operating expenses		$	0.66			$	—
Production taxes			—				—
Transportation and compression			0.30				—
		$	0.96			$	—
Total:

 

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Lease operating expenses(4)		$	0.88			$	0.87
Production taxes			0.06				0.04
Transportation and compression			0.53				0.56
		$	1.47			$	1.46

 

(1)	Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

(2)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(3)

Excludes the impact of certain allocations of production revenue to investor partners within our investment partnerships for the three months ended March 31, 2011 and 2010. Including the effect of these allocations, the average realized gas sales price was $4.67 per Mcf ($3.68 per Mcf before the effects of financial hedging) and $6.21 per Mcf ($4.53 per Mcf before the effects of financial hedging) for the three months ended March 31, 2011 and 2010, respectively.

(4)

Excludes the effects of our proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within our investment partnerships. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.54 per Mcfe ($1.17 per Mcfe for total production costs) and $0.41 per Mcfe ($1.02 per Mcfe for total production costs) for the three months ended March 31, 2011 and 2010, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.59 per Mcfe ($1.18 per Mcfe for total production costs) and $0.45 per Mcfe ($1.04 per Mcfe for total production costs) for the three months ended March 31, 2011 and 2010, respectively.

(5)	Includes NGL production revenue for the three months ended March 31, 2011 and 2010.

Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010. Total natural gas revenues were $13.7 million for the three months ended March 31, 2011, a decrease of $7.6 million from $21.3 million for the three months ended March 31, 2010. This decrease consisted of a $7.5 million decrease attributable to lower realized natural gas prices and a $2.7 million decrease attributable to lower production volumes, partially offset by a $2.6 million decrease in gas revenues allocated to the investor partners within our investment partnerships for the three months ended March 31, 2011 compared with the prior year period. Total oil revenues were $3.9 million for the three months ended March 31, 2011, a decrease of $0.3 million from $4.2 million for the comparable prior year period. This decrease resulted primarily from a $1.1 million decrease associated with lower oil production volumes, partially offset by a $0.5 million increase associated with higher average realized prices and a $0.3 million increase from the sale of natural gas liquids.

Appalachia production costs were $3.5 million for the three months ended March 31, 2011, a decrease of $0.4 million from $3.9 million for the three months ended March 31, 2010. This decrease was principally due to a $0.5 million decrease in transportation costs and a $0.6 million decrease associated with labor, maintenance expenses and other costs associated with our gas and oil operations. This amount was partially offset by a $0.7 million decrease associated with our proportionate share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships. New Albany/Antrim production costs were $0.4 million for the three months ended March 31, 2011, an increase of $0.2 million from $0.2 million for the comparable prior year period. This increase was primarily attributable to a $0.1 million increase for labor-related expense and a $0.1 million increase associated with parts, materials and other costs associated with our New Albany/Antrim gas operations.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary within the partnership management segment depending on the amount of capital we raise through our investment 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 we drilled for our investment partnerships during the three months ended March 31, 2011 and 2010. There were no exploratory wells drilled during the three months ended March 31, 2011 and 2010:

 

		Three Months Ended March 31,
		2011				2010
Drilling partnership investor capital:
Raised		$	—			$	—
Deployed		$	17,725			$	72,642
Gross partnership wells drilled:

 

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Appalachia			3				10
New Albany/Antrim			—				—
Niobrara			17				—
Total			20				10
Net partnership wells drilled:
Appalachia			3				9
New Albany/Antrim			—				—
Niobrara			17				—
Total			20				9

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. 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,
		2011				2010
Average construction and completion:
Revenue per well		$	635			$	2,132
Cost per well			538				1,807
Gross profit per well		$	97			$	325
Gross profit margin		$	2,704			$	11,081
Partnership net wells associated with revenue recognized(1):
Appalachia			1				26
New Albany/Antrim			2				8
Niobrara			25				—
			28				34

 

(1)	Consists of partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010. Well construction and completion segment margin was $2.7 million for the three months ended March 31, 2011, a decrease of $8.4 million from $11.1 million for the three months ended March 31, 2010. This decrease consisted of a $7.8 million decrease associated with lower gross profit per well and a $0.6 million decrease related to fewer wells recognized for revenue within the investment partnerships. Since our drilling contracts with the Drilling Partnerships are on a “cost-plus” basis (typically cost-plus 18%), an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well decreased between periods due to more capital deployed for Niobrara formation wells within the Drilling Partnerships during the first quarter 2011, while the first quarter 2010 was characterized by more Marcellus Shale capital deployed. Typically, the Niobrara formation wells we have drilled within the Drilling Partnerships have a lower cost per well as compared to the Marcellus Shale wells. In addition, the decrease in well construction and completion margin was the result of the cancellation of the fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.

Our consolidated combined balance sheet at March 31, 2011 includes $47.3 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated combined statements of operations. We expect to recognize this amount as revenue during the remainder of 2011 and possibly the beginning of 2012.

Administration and Oversight

 

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Administration and oversight fee revenues represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships.

Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010. Administration and oversight fee revenues were $1.4 million for the three months ended March 31, 2011, a decrease of $0.6 million from $2.0 million for the three months ended March 31, 2010. This decrease was primarily due to a decrease in the number of Marcellus Shale wells drilled, for which we receive higher fixed fees, during the current year period in comparison to the prior year period. In addition, the decrease in administration and oversight margin was the result of the cancellation of the fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.

Well Services

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.

Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010. Well services revenues were $5.3 million for the three months ended March 31, 2011, an increase of $0.1 million from $5.2 million for the three months ended March 31, 2010. Well services expenses were $2.4 million for three months ended March 31, 2011, a decrease of $0.1 million from $2.5 million for the three months ended March 31, 2010.

Gathering and Processing

Gathering and processing margin includes gathering fees we charge to our investment partnership wells and the related expenses, gross margin for our processing plants in the New Albany Shale and the Chattanooga Shale, and the operating revenues and expenses of APL. The gathering fees charged to our investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships, we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachia Basin, will generally exceed the revenues collected from the investment partnerships by approximately 3%.

The following table presents our gathering and processing revenues and expenses and those attributable to APL for each of the respective periods:

 

		Three Months Ended March 31,
		2011				2010(1)
Gathering and Processing:
Atlas Energy:
Revenue		$	4,499			$	3,113
Expense			(5,734	)			(4,255	)
Gross Margin		$	(1,235	)		$	(1,142	)
Atlas Pipeline:
Revenue		$	275,719			$	233,433
Expense			(231,250	)			(191,907	)
Gross Margin		$	44,469			$	41,526
Total:
Revenue		$	280,218			$	236,546
Expense			(236,984	)			(196,162	)
Gross Margin		$	43,234			$	40,384

 

 

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(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010.

Three Months March 31, 2011 Compared with the Three Months Ended March 31, 2010. Our net gathering and processing expense for the three months ended March 31, 2011was $1.2 million compared with $1.1 million for the three months ended March 31, 2010. This unfavorable increase was principally due to a $0.1 million unfavorable increase in our plant operating costs.

Gathering and processing margin for APL was $44.5 million for the three months ended March 31, 2011 compared with $41.5 million for the three months ended March 31, 2010. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.

Gain (Loss) on Mark-to-Market Derivatives

Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010. Loss on mark-to-market derivatives was $21.6 million for the three months ended March 31, 2011 as compared with a gain of $4.7 million for the three months ended March 31, 2010. This unfavorable movement was due primarily to a $31.9 million unfavorable variance in non-cash mark-to-market adjustments on derivatives, a $12.0 million unfavorable variance in non-cash derivative gains related to early termination of a portion of APL’s derivative contracts and a $0.3 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s early termination of a portion of its derivative contracts partially offset by a $17.9 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period.

OTHER COSTS AND EXPENSES

General and Administrative Expenses

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

 

		Three Months Ended March 31,
		2011				2010(1)
General and Administrative expenses:
Atlas Energy		$	7,173			$	790
Atlas Pipeline			9,017				9,751
Total		$	16,190			$	10,541

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010.

Total general and administrative expenses increased to $16.2 million for the three months ended March 31, 2011 compared with $10.5 million for the three months ended March 31, 2010. Because the Transferred Business was not accounted for by AEI as a stand-alone business unit, it was not practicable for us to allocate general and administrative expenses to it for historical periods. Therefore, the general and administrative expenses for the three months ended March 31, 2010 were comprised of our stand-alone general and administrative expenses, while the expenses for the three months ended March 31, 2011 were comprised of our stand-alone general and administration expenses and that of the Transferred Business. In addition, our general and administrative expenses for the three months ended March 31, 2011 included $3.1 million of reimbursements we received from Chevron for the transition services we provided during the period. Our $7.2 million of general and administrative expense for the three months ended March 31, 2011 was comprised of $2.1 million of restructuring costs related to the acquisition of the Transferred Business, $3.6 million of salary and wages expense, and $1.5 million of other corporate activities. APL’s $9.0 million of general and administrative expense for the three months ended March 31, 2011 represents a decrease of $0.7 million from the comparable prior year period, which was principally due to a $1.3 million decrease in salaries and wages, partially offset by a $0.6 million increase of other corporate activities.

Depreciation, Depletion and Amortization

 

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The following table presents our depreciation, depletion and amortization expense and that which was attributable to APL for each of the respective periods:

 

		Three Months Ended March 31,
		2011				2010(1)
Depreciation, depletion and amortization:
Atlas Energy		$	7,701			$	8,640
Atlas Pipeline			18,906				18,457
Total		$	26,607			$	27,097

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010.

Total depreciation, depletion and amortization decreased to $26.6 million for the three months ended March 31, 2011 compared with $27.1 million for the comparable prior year period primarily due to a $1.1 million decrease in our depletion expense. The following table presents our depletion expense, excluding amounts attributable to APL, per Mcfe for our operations for the respective periods:

 

		Three Months Ended March  31,
		2011				2010
Depletion expense (in thousands):
Total		$	6,566			$	7,897
Depletion expense as a percentage of gas and oil production revenue			37	%			31	%
Depletion per Mcfe		$	1.97			$	2.03

Depletion expense varies from period to period and is directly affected by changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. For the three months ended March 31, 2011, depletion expense decreased $1.3 million to $6.6 million compared with $7.9 million for the three months ended March 31, 2010. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 37% for the three months ended March 31, 2011, compared with 31% for the three months ended March 31, 2010, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $1.97 for the three months ended March 31, 2011, a decrease of $0.06 per Mcfe from $2.03 for the three months ended March 31, 2010. Depletion expense decreased between periods principally due to an overall decrease in production volumes combined with the $49.7 million impairment of our Chattanooga Shale field recorded during the three months ended December 31, 2010.

Gain (Loss) on Asset Sales

Gain on asset sales was $255.9 million for the three months ended March 31, 2011 compared with loss on asset sales of $2.9 million for the three months ended March 31, 2010. The $255.9 million of gain on asset sales for the first quarter 2011 principally represents APL’s gain on sale of its 49% non-controlling interest in the Laurel Mountain joint venture. The $2.9 million loss on asset sales for the first quarter 2010 represents the loss recognized on our sale of a processing plant.

Interest Expense

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

 

		Three Months Ended March 31,
		2011				2010(1)
Interest Expense:
Atlas Energy		$	5,633			$	618
Atlas Pipeline			12,445				26,403

 

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Total		$	18,078			$	27,021

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010.

Total interest expense decreased to $18.1 million for the three months ended March 31, 2011 as compared with $27.0 million for the three months ended March 31, 2010. This $8.9 million decrease was primarily due to a $14.0 million decrease related to APL, partially offset by our $5.0 million increase. The $14.0 million decrease in interest expense for APL was primarily due to a $7.2 million decrease in interest expense associated with its term loan, a $4.8 million decrease in interest expense associated with its revolving credit facility and a $1.8 million decrease in interest rate swap expense due to the interest rate swaps expiring in April 2010. Our $5.0 million increase in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our interim bridge credit facility that was used for the acquisition of the Transferred Business. This credit facility was terminated and replaced in March 2011.

Income (Loss) from Discontinued Operations

For the three months ended March 31, 2011, income (loss) from discontinued operations, which consists of amounts associated with APL’s Elk City system was $0.1 million. For the three months ended March 31, 2010, income from discontinued operations, which consists of amounts associated with APL’s Elk City that were sold in September 2010 was $6.8 million.

Income Not Attributable to Common Limited Partners

For the three months ended March 31, 2011 and 2010, income not attributable to common limited partners was $4.7 million and $25.5 million, respectively, which consists of income not attributable to common limited partners related to the results of operations of the Transferred Business prior to our acquisition on February 17, 2011.

(Income) Loss Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $211.4 million for the three months ended March 31, 2011 compared with income of $1.8 million for the comparable prior year period. Income attributable to non-controlling interests includes an allocation of APL’s net income (loss) to non-controlling interest holders. This change was primarily due to an increase in APL’s net earnings between periods, including the gain from the sale of its investment in Laurel Mountain.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships, and borrowings under our credit facility (see “Recent Developments”). Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders. In general, we expect to fund:

 

•

Cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

 

•

Expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through investment partnerships; and

 

•

Debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales.

We rely on cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We 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 are subject to business,

 

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operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional common units, the sale of assets and other transactions.

Cash Flows – Three Months Ended March 31, 2011 Compared with the Three Months Ended March 31, 2010

Net cash provided by operating activities of $22.3 million for the three months ended March 31, 2011 represented an unfavorable movement of $40.6 million from net cash provided by operating activities of $62.9 million for the comparable prior year period. The decrease was derived principally from a $55.9 million unfavorable movement in working capital, a $17.6 million increase in distributions paid to non-controlling interests, a $1.8 million decrease in distributions received from unconsolidated subsidiaries and a $2.0 million unfavorable movement in net income from discontinued operations, partially offset by a $36.7 million increase in net income excluding non-cash items. The non-cash charges which impacted net income include a $223.5 million increase in net income from continuing operations, a favorable movement in non-cash gain on derivatives of $67.1 million and a $5.0 million favorable movement in non-cash expenses, including compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs, partially offset by a $258.9 million unfavorable movement in gains on asset sales. The movement in non-cash derivative losses resulted from increases in commodity prices from January 1, 2010 through March 31, 2010 and their $11.0 million favorable impact on the fair value of derivative contracts we and APL had for future periods. The movement in cash distributions to non-controlling interest holders was due principally to decreases in the cash distributions of APL. The movement in working capital was principally due to a $91.7 million unfavorable movement in accounts receivable and other current assets, partially offset by a $35.8 million favorable movement in accounts payable and other current liabilities.

Net cash provided by investing activities of $372.0 million for the three months ended March 31, 2011 represented a favorable movement of $414.8 million from net cash used in investing activities of $42.8 million for the comparable prior year period. This favorable movement was principally due to a $411.5 million increase in net proceeds from asset sales, a $6.3 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries, including our investment in Lightfoot and a $1.9 million favorable movement in net cash used in discontinued operations, partially offset by a $3.1 million unfavorable movement in capital expenditure and a $1.9 million unfavorable movement in other assets. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $288.5 million for the three months ended March 31, 2011 represented an unfavorable movement of $266.5 million from $22.0 million for the comparable prior year period. This unfavorable movement was principally due to $293.7 million of cash placed in escrow related to APL’s senior note redemption, $88.7 million unfavorable movement in the repayment of outstanding borrowings, a $19.3 million unfavorable movement in proceeds from equity offerings, a $16.3 million unfavorable movement in net investment received from AEI prior to February 17, 2011, and a $6.7 million unfavorable movement in other financing activities, partially offset by $117.2 million non-cash transaction adjustment related to the acquisition of the Transferred Business and a $41.0 million favorable movement in outstanding borrowings.

Capital Requirements

Our capital requirements consist primarily of:

 

•

maintenance capital expenditures — capital expenditures we make on an ongoing basis to maintain our capital asset base at a steady level; and

 

•

expansion capital expenditures — capital expenditures we make to expand our capital asset base for longer than the short-term and includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships.

Atlas Pipeline Partners. APL’s 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:

 

•

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

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•

expansion capital expenditures to acquire complementary assets and to expand the capacity of its existing operations.

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

 

		Three Months Ended March 31,
		2011				2010(1)
Atlas Energy
Maintenance capital expenditures		$	1,666			$	—
Expansion capital expenditures			6,066				28,405
Total		$	7,732			$	28,405
Atlas Pipeline
Maintenance capital expenditures		$	3,260			$	875
Expansion capital expenditures			15,073				5,912
Total		$	18,333			$	6,787
Consolidated Combined
Maintenance capital expenditures		$	4,926			$	875
Expansion capital expenditures			21,139				34,317
Total		$	26,065			$	35,192

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sales of certain APL assets in September 2010.

During the three months ended March 31, 2011, our $7.7 million of total capital expenditures related primarily to $4.0 million of well costs, principally our investments in the Drilling Partnerships, compared with $15.5 million for prior year comparable period, $0.7 million in leasehold acquisition costs compared with $4.6 million for the prior year comparable period, $1.2 million of gathering and processing costs compared with $6.2 million for the prior year comparable period, and $1.8 million of corporate and other compared with $2.1 million for the prior year comparable period. Maintenance capital expenditures, which are the component of total capital expenditures that maintain our capital asset base at a steady level and is based upon the estimated cost to replace the reserves produced during the respective period, were $1.7 million during the first quarter 2011. Prior to our acquisition of the Transferred Business on February 17, 2011, we had no maintenance capital requirements with regard to our oil and gas properties.

We continuously evaluate acquisitions of gas and oil assets. In order to make any acquisition, we 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 will be successful in our efforts to obtain outside capital.

Atlas Pipeline Partners. APL’s capital expenditures increased to $18.3 million for the three months ended March 31, 2011 compared with $6.8 million for the comparable prior year period. The increase was due principally to costs incurred related to APL’s compressor upgrades and pipeline projects.

As of March 31, 2011, we and APL are committed to expend approximately $126.8 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of March 31, 2011, our and APL’s off-balance sheet arrangements are limited to our letters of credit outstanding of $0.1 million, APL’s letters of credit outstanding of $3.2 million and commitments to spend $126.8 million related to our drilling and completion expenditures and our and APL’s capital expenditures.

CASH DISTRIBUTIONS

The board of directors of our general partner 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

 

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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:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law, any of our debt instruments or other agreements; or

 

•

provide funds for distributions to our unitholders for any one or more of 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 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.

APL’S CASH DISTRIBUTIONS

APL’s partnership agreement requires that it distribute 100% of available cash to its common 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 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% of the aggregate amount of cash being distributed. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights as set forth in the IDR Adjustment Agreement. No incentive distributions were declared for the three months ended March 31, 2011 and 2010.

CREDIT FACILITY

On March 22, 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and an initial borrowing base of $125 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our 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 our assets. The credit agreement also requires us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a Current Ratio (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011.

ISSUANCE OF UNITS

 

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Pursuant to prevailing accounting literature, we recognize gains on our APL’s equity transactions as a credit to partners’ capital rather than as income. These gains represent our portion of the excess net offering price per unit of each of APL’s common units over the book carrying amount per unit.

In February 2011, we paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million (see “Recent Developments”).

Atlas Pipeline Partners

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units are redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. AEI is entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units.

In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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 our significant accounting policies we have adopted and followed in the preparation of our consolidated combined financial statements was included within our Audit Report on Form 10-K for the year ended December 31, 2010 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through March 31, 2011.

Fair Value of Financial Instruments

We 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.

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 assumption 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.

 

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We use a fair value methodology to value the assets and liabilities for our and APL’s outstanding derivative contracts. Our and APL’s 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.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s 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.

 

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. As our assets currently consist principally of our ownership interests in our subsidiaries, the following information principally encompasses their exposure to market risks unless otherwise noted. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas 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 view and manage our ongoing market risk exposures. All of the market risk sensitive instruments were entered into for purposes other than trading.

General

All of our 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, 2011. 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 commodity and interest-rate derivative contracts are banking institutions, who also participate in our revolving credit facilities. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk. At March 31, 2011, we had no outstanding borrowings under our $125.0 million revolving credit facility. At March 31, 2011, APL had no outstanding borrowings under its $350.0 million senior secured revolving credit facility. Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in variable interest rates would have no impact on our consolidated interest expense.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. To limit our exposure to changing natural gas and oil prices, we use financial derivative instruments for a portion of our future natural gas and oil production. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL receives or pays a fixed price

 

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and receives or remits 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 natural gas, NGLs and condensate at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated combined operating income from continuing operations for the twelve-month period ending March 31, 2011 of approximately $14.4 million.

Realized pricing of our oil and natural gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil swap 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 futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

At March 31, 2011, we had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price
		(mmbtu)(1)				(per mmbtu)(1)
2011			4,680,000			$	4.484
2012			5,520,000			$	5.000
2013			3,120,000			$	5.288

Natural Gas Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap
				(mmbtu)(1)				(per mmbtu)(1)
2011		Puts purchased			1,620,000			$	3.750
2011		Calls sold			1,620,000			$	5.611
2012		Puts purchased			1,920,000			$	4.250
2012		Calls sold			1,920,000			$	6.084
2013		Puts purchased			3,120,000			$	4.750
2013		Calls sold			3,120,000			$	6.065

Crude Oil Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap
				(Bbl)(1)				(per Bbl)(1)
2011		Puts purchased			45,000			$	90.000
2011		Calls sold			45,000			$	125.312
2012		Puts purchased			60,000			$	90.000
2012		Calls sold			60,000			$	117.912
2013		Puts purchased			60,000			$	90.000
2013		Calls sold			60,000			$	116.396

 

(1)	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

 

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As of March 31, 2011, APL had the following commodity derivatives, which do not qualify for hedge accounting:

Fixed Price Swaps

 

Production Period		Purchased/ Sold		Commodity		Volumes(2)				Average Fixed Price
Natural Gas
2011		Sold		Natural Gas Basis			1,440,000				(0.728	)
2011		Purchased		Natural Gas Basis			1,440,000				(0.758	)
2011		Sold		Natural Gas Basis			3,300,000				4.637
Natural Gas Liquids
2011		Sold		Ethane			5,040,000				0.500
2011		Sold		Propane			12,852,000				1.153
2011		Sold		Isobutane			1,008,000				1.618
2011		Sold		Normal Butane			2,772,000				1.580
2011		Sold		Natural Gasoline			6,552,000				2.042
2012		Sold		Propane			14,868,000				1.277
2012		Sold		Natural Gasoline			2,520,000				2.395
Crude Oil
2011		Sold		Crude Oil			99,000				91.642
2012		Sold		Crude Oil			84,000				99.500
Total Fixed Price Swaps

Options

 

Production Period		Purchased/ Sold		Commodity		Volumes(1)				Average Strike Price
Natural Gas
2011		Purchased(2)		Propane			14,616,000			$	1.280
2012		Purchased		Propane			3,780,000			$	1.359
Crude Oil
2011		Purchased		Crude Oil			402,000				93.356
2011		Sold		Crude Oil			509,000				93.354
2011		Purchased(3)		Crude Oil			189,000				125.200
2012		Purchased		Crude Oil			60,000				105.003
2012		Sold		Crude Oil			498,000				94.694
2012		Purchased(3)		Crude Oil			180,000				125.200

(1)	Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

(2)	Liabilities for purchased options are due to deferred premium payments, which will be paid at the time the options are settled.

(3)	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

 

ITEM 4.

CONTROLS AND PROCEDURES

 

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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 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 and with the participation of our management, including of our Chief Executive Officer and Chief Financial Officer, 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 Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2011, our disclosure controls and procedures were effective at the reasonable assurance level.

On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. In addition, in connection with this acquisition, we have installed the management team that managed the Transferred Business under AEI into our organization, including our Chief Executive Officer and Chief Financial Officer, and adopted AEI’s internal controls over financial reporting under which the Transferred Business operated. However, we continue to integrate these internal controls into our internal control structure. This integration may lead to changes in our internal control over financial reporting in future fiscal reporting periods. Other than 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.

PART II. OTHER INFORMATION

 

ITEM 1.

LEGAL PROCEEDINGS

Following the November 9, 2010 announcement that Atlas Energy, Inc. had entered into a definitive agreement to be acquired by Chevron Corporation and that we and APL agreed to enter into separate transactions with Atlas Energy, Inc. relating to certain Atlas Energy, Inc. natural gas reserves and other assets and fee revenues, and APL’s interest in Laurel Mountain, a purported shareholder derivative case was filed on November 16, 2010, in the Western District of Pennsylvania federal court, Ussach v. Atlas Energy, Inc., et al., C.A. No. 2:10-cv-1533. The complaint is asserted derivatively on behalf of APL and names Atlas Energy, Inc., Atlas Pipeline GP, and members of the Managing Board of Atlas Pipeline GP as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the proposed sale to Atlas Energy, Inc. of APL’s interest in Laurel Mountain and that Atlas Energy, Inc. has been unjustly enriched. In the complaint, among other relief, the plaintiff requests damages and equitable and injunctive relief, as well as restitution and disgorgement from the individual defendants. On February 22, 2011, the plaintiff voluntarily dismissed its complaint without prejudice. We have not received an indication whether the plaintiff intends to reassert its claims in another forum. The defendants believe the claims are without merit.

We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

 

ITEM 5.

OTHER INFORMATION

On May 13, 2011, we entered into employment agreements with Edward E. Cohen (“E. Cohen”) and Jonathan Z. Cohen (“J. Cohen”) to secure their services as President and Chief Executive Officer (in the case of E. Cohen) and Chairman of the Board (in the case of J. Cohen). The agreements have an effective date of May 16, 2011 and have a term of three years, which automatically renews daily, unless terminated before the expiration of the term pursuant to the termination provisions of the agreements.

The agreements provide for an initial annual base salary of $700,000 in the case E. Cohen and $500,000 in the case of J. Cohen, which may be increased at the discretion of the board of directors. The executives are entitled to participate in any short-term and long-term incentive programs and health and welfare plans of the company and receive

 

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perquisites and reimbursement of business expenses, in each case as provided by us for our senior level executives generally. E. Cohen and J. Cohen each participate in an excess 401(k) plan, under which the executive may elect to defer up to 10% of his total annual cash compensation, which we must match on a dollar-for-dollar basis up to 50% of the executive’s annual base salary. During the term of the agreement, we must maintain a term life insurance policy on the executive’s life which provides a death benefit of $3 million for E. Cohen and $2 million for J. Cohen, which can be assumed by the executive upon a termination of employment.

The agreements provide the following benefits in the event of a termination of the executive’s employment:

 

•

Upon termination of employment due to death, all equity awards held by the executive accelerate and vest in full upon the later of the termination of employment or six months after the date of grant of the awards (“Acceleration of Equity Vesting”), and the executive’s estate is entitled to receive, in addition to payment of all accrued and unpaid amounts of base salary, vacation, business expenses and other benefits (“Accrued Obligations”), a pro-rata bonus for the year of termination, based on the actual bonus that would have been earned had the termination of employment not occurred, determined and paid consistent with past practice (the “Pro-Rata Bonus”).

 

•

Upon termination of employment due to disability, the executive will receive the Accrued Obligations, all amounts payable under our long-term disability plans, three years’ continuation of group term life and health insurance benefits (or, alternatively, we may elect to pay executive cash in lieu of such coverage in an amount equal to three years’ healthcare coverage at COBRA rates and the premiums we would have paid during the three-year period for such life insurance) (such coverage, the “Continued Benefits”), Acceleration of Equity Vesting, and the Pro-Rata Bonus.

 

•

Upon termination of employment by us without cause or by the executive for good reason, the executive will be entitled to either (i) if the executive does not execute and not revoke a release of claims against us, payment of the Accrued Obligations, or (ii), in addition to payment of the Accrued Obligations, if the executive executes and does not revoke a release of claims against us, (A) a lump-sum cash payment in an amount equal to three years of his average compensation (which is generally defined as the sum of his base salary in effect immediately before the termination of employment plus the average of the cash bonuses earned for the three calendar years preceding the year in which the date of termination of employment occurs), (B) Continued Benefits, (C) the Pro-Rata Bonus, and (D) Acceleration of Equity Vesting.

 

•

Upon a termination by us for cause or by the executive without good reason, the executive is entitled to receive payment of the Accrued Obligations.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to the executive will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if the executive would be in a better after-tax position as a result of such reduction.

The terms and conditions of the employment agreements for E. Cohen and J. Cohen summarized above are qualified in their entirety by reference to the terms and conditions of the employment agreements themselves, which are filed herewith as Exhibits 10.16 and 10.17.

 

ITEM 6.

EXHIBITS

 

Exhibit No.		Description
2.1		Transaction Agreement, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010.(21)
2.2		Purchase and Sale Agreement, by and among Atlas Pipeline Partners, L.P., APL Laurel Mountain, LLC, Atlas Energy, Inc., and Atlas Energy Resources, LLC, dated November 8, 2010.(21)
2.3		Employee Matters Agreement, by and among Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010.(21)
3.1		Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1)

 

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Exhibit No.		Description
3.2		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.3		Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.4		Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13)
4.1		Specimen Certificate Representing Common Units(1)
10.1		Certificate of Formation of Atlas Pipeline Holdings GP, LLC(1)
10.2		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC.(13)
10.3(a)		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1)
10.3(b)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1)
10.3(c)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4)
10.3(d)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(e)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(f)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(g)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7)
10.3(h)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14)
10.3(i)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(15)
10.4		Certificate of Designation for 12% Cumulative Class C Preferred Units of Atlas Pipeline Partners, L.P.(15)
10.5(a)		Long-Term Incentive Plan(6)
10.5(b)		Amendment No. 1 to Long-Term Incentive Plan(26)
10.6		2010 Long-Term Incentive Plan(16)
10.7		Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(25)
10.8		Form of Stock Option Grant under 2010 Long-Term Incentive Plan(25)
10.9		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)
10.10		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.
10.11		Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, 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

 

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Exhibit No.		Description
		material has been separately filed with the Securities and Exchange Commission.
10.12(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.
10.12(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.
10.12(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.
10.13		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.
10.14		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.
10.15		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.
10.16		Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011
10.17		Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011
10.18		Securities Purchase Agreement, dated July 27, 2010, by and among Atlas Pipeline Mid-Continent, LLC, Atlas Pipeline Partners, L.P., Enbridge Pipelines (Texas Gathering) L.P. and Enbridge Energy Partners, L.P.(18)
10.19		Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras(12)
10.20		Phantom Unit Grant Agreement between Atlas Pipeline Mid-Continent, LLC and Eric Kalamaras, dated September 14, 2009(12)
10.21		Form of Grant of Phantom Units to Non-Employee Managers(20)
10.22		Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21)
10.23		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and

 

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Exhibit No.		Description
		Edward E. Cohen, dated as of November 8, 2010(22)
10.24		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010(22)
10.25		Credit Agreement, dated as of March 22, 2011, among Atlas Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto(24)
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

 

(1)	Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999).

(2)	[Intentionally omitted]

(3)	[Intentionally omitted]

(4)	Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007.

(5)	[Intentionally omitted]

(6)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

(7)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

(8)	[Intentionally omitted]

(9)	[Intentionally omitted]

(10)	Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009.

(11)	[Intentionally omitted]

(12)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2009.

(13)	Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2011.

(14)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010.

(15)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010.

(16)	Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010.

(17)	[Intentionally omitted]

(18)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 29, 2010.

(19)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 1, 2010.

(20)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2010.

(21)	Previously filed as an exhibit to current report on Form 8-K filed November 12, 2010.

(22)	Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010.

(23)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 23, 2010.

(24)	Previously filed as an exhibit to current report on Form 8-K filed on March 25, 2011.

(25)	Previously filed as an exhibit to the registration statement on Form S-8 filed on March 25, 2011.

(26)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010.

 

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SIGNATURES

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.

 

						ATLAS ENERGY, L.P.
						By: Atlas Energy GP, LLC, its General Partner
Date: May 16, 2011						By:		/s/    EDWARD E. COHEN
								Edward E. Cohen
								Chief Executive Officer and President
Date: May 16, 2011						By:		/s/    SEAN P. MCGRATH
								Sean P. McGrath
								Chief Financial Officer
Date: May 16, 2011						By:		/s/    JEFFREY M. SLOTTERBACK
								Jeffrey M. Slotterback
								Chief Accounting Officer

 

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