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 ~~June~~September 30, 2013

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

For the transition period fromto

Commission file number: 1-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

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

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

Registrant’s telephone number, including area code: (412) 489-0006

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

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

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


Large accelerated filerx	x		Accelerated filer	¨

Non-accelerated filer	¨ ~~(Do~~	(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 ~~August 5,~~November 4, 2013 was ~~51,389,574.~~51,410,826.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM10-Q

TABLE OF CONTENTS


			PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)			3

		Consolidated Balance Sheets as of ~~June~~September 30, 2013 and December 31, 2012			3

		Consolidated Statements of Operations for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2013 and 2012			4

		Consolidated Statements of Comprehensive Income (Loss) for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2013 and 2012			5

		Consolidated Statement of Partners’ Capital for the ~~Six~~Nine Months Ended ~~June~~September 30, 2013			6

		Consolidated Statements of Cash Flows for the ~~Six~~Nine Months Ended ~~June~~September 30, 2013 and 2012			7

		Notes to Consolidated Financial Statements			8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			61	65

Item 3.	Quantitative and Qualitative Disclosures About Market Risk			93	99

Item 4.	Controls and Procedures			98
		103

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings			99	104

Item 6.	Exhibits			~~100~~
		105

SIGNATURES				~~108~~	111

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

   June 30,
2013    December 31,
2012
ASSETS
Current assets:

Cash and cash equivalents
   $ 70,430       $ 36,780
Accounts receivable
   250,755       196,249
Current portion of derivative asset
   64,402       35,351
Subscriptions receivable
   11,036       55,357
Prepaid expenses and other
   72,595       45,255




Total current assets
   469,218       368,992
Property, plant and equipment, net
   4,036,187       3,502,609
Intangible assets, net
   570,999       200,680
Investment in joint ventures
   232,090       86,002
Goodwill, net
   534,105       351,069
Long-term derivative asset
   26,759       16,840
Other assets, net
   92,721       71,002




   $ 5,962,079       $ 4,597,194




LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:

Current portion of long-term debt
   $ 522       $ 10,835
Accounts payable
   94,270       119,028
Liabilities associated with drilling contracts
   —         67,293
Accrued producer liabilities
   140,505       109,725
Current portion of derivative liability
   167       —
Current portion of derivative payable to Drilling Partnerships
   5,969       11,293
Accrued interest
   35,281       11,556
Accrued well drilling and completion costs
   52,425       47,637
Accrued liabilities
   118,006       103,291




Total current liabilities
   447,145       480,658
Long-term debt, less current portion
   1,944,297       1,529,508
Long-term derivative liability
   130       888
Long-term derivative payable to Drilling Partnerships
   38       2,429
Deferred income taxes, net
   35,513       30,258
Asset retirement obligations and other
   77,890       73,605
Commitments and contingencies

Partners’ Capital:

Common limited partners’ interests
   448,808       456,171
Accumulated other comprehensive income
   13,927       9,699




   462,735       465,870
Non-controlling interests
   2,994,331       2,013,978




Total partners’ capital
   3,457,066       2,479,848




   $ 5,962,079       $ 4,597,194

ASSETS	September 30, 2013		December 31, 2012
Current assets:
Cash and cash equivalents	$	29,498	$	36,780
Accounts receivable		289,817		196,249
Current portion of derivative asset		25,733		35,351
Subscriptions receivable		13,900		55,357
Prepaid expenses and other		85,421		45,255
Total current assets		444,369		368,992

Property, plant and equipment, net		4,958,551		3,502,609
Intangible assets, net		547,014		200,680
Investment in joint ventures		238,221		86,002
Goodwill, net		535,721		351,069
Long-term derivative asset		37,504		16,840
Long-term derivative receivable from Drilling Partnerships		182		—
Other assets, net		123,529		71,002
	$	6,885,091	$	4,597,194
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	3,010	$	10,835
Accounts payable		147,114		119,028
Liabilities associated with drilling contracts		—		67,293
Accrued producer liabilities		161,808		109,725
Current portion of derivative liability		1,461		—
Current portion of derivative payable to Drilling Partnerships		4,932		11,293
Accrued interest		39,472		11,556
Accrued well drilling and completion costs		47,149		47,637
Accrued liabilities		126,124		103,291
Total current liabilities		531,070		480,658

Long-term debt, less current portion		2,840,921		1,529,508
Long-term derivative liability		—		888
Long-term derivative payable to Drilling Partnerships		—		2,429
Deferred income taxes, net		34,696		30,258
Asset retirement obligations and other		97,650		73,605

Commitments and contingencies

Partners’ Capital:
Common limited partners’ interests		405,285		456,171
Accumulated other comprehensive income		19,941		9,699
		425,226		465,870
Non-controlling interests		2,955,528		2,013,978
Total partners’ capital		3,380,754		2,479,848
	$	6,885,091	$	4,597,194

See accompanying notes to consolidated financial statements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Revenues:

Gas and oil production
   $ 47,094    $ 19,460    $ 93,158    $ 36,624
Well construction and completion
   24,851    12,241    81,329    55,960
Gathering and processing
   535,922    256,420    956,009    561,561
Administration and oversight
   3,391    1,315    4,476    4,146
Well services
   4,864    5,252    9,680    10,258
Gain on mark-to-market derivatives
   27,107    67,847    15,024    55,812
Other, net
   566    504    6,221    3,305


Total revenues
   643,795    363,039    1,165,897    727,666


Costs and expenses:

Gas and oil production
   19,035    4,447    34,251    8,952
Well construction and completion
   21,609    10,606    70,721    48,301
Gathering and processing
   453,868    213,551    805,609    465,396
Well services
   2,305    2,414    4,623    4,844
General and administrative
   53,874    37,607    94,532    74,855
Depreciation, depletion and amortization
   68,580    32,534    120,246    62,484


Total costs and expenses
   619,271    301,159    1,129,982    664,832


Operating income
   24,524    61,880    35,915    62,834
Loss on asset sales and disposal
   (2,191 ) (16 ) (2,893 ) (7,021 )
Interest expense
   (27,531 ) (10,294 ) (53,341 ) (19,385 )
Loss on early extinguishment of debt
   (19 ) —      (26,601 ) —


Net income (loss) before tax
   (5,217 ) 51,570    (46,920 ) 36,428
Income tax benefit
   28    —      37    —


Net income (loss)
   (5,189 ) 51,570    (46,883 ) 36,428
Loss (income) attributable to non-controlling interests
   (3,058 ) (59,191 ) 26,040    (62,556 )


Net loss attributable to common limited partners
   $ (8,247 ) $ (7,621 ) $ (20,843 ) $ (26,128 )


Net loss attributable to common limited partners per unit:

Basic and Diluted
   $ (0.16 ) $ (0.15 ) $ (0.41 ) $ (0.51 )


Weighted average common limited partner units outstanding:

Basic and Diluted
   51,380    51,318    51,375    51,306

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues:
Gas and oil production	$	83,032		$	24,699		$	176,190		$	61,323
Well construction and completion		10,964			36,317			92,293			92,277
Gathering and processing		582,961			297,868			1,538,970			859,429
Administration and oversight		4,447			4,440			8,923			8,586
Well services		5,023			5,086			14,703			15,344
Gain (loss) on mark-to-market derivatives		(24,517	)		(18,907	)		(9,493	)		36,905
Other, net		(11,921	)		5,270			(5,700	)		8,575
Total revenues		649,989			354,773			1,815,886			1,082,439

Costs and expenses:
Gas and oil production		30,586			7,295			64,837			16,247
Well construction and completion		9,534			31,581			80,255			79,882
Gathering and processing		492,691			245,074			1,298,300			710,470
Well services		2,386			2,232			7,009			7,076
General and administrative		61,914			33,991			156,446			108,846
Chevron transaction expense		—			7,670			—			7,670
Depreciation, depletion and amortization		94,067			37,079			214,313			99,563
Total costs and expenses		691,178			364,922			1,821,160			1,029,754

Operating income (loss)		(41,189	)		(10,149	)		(5,274	)		52,685

Gain (loss) on asset sales and disposal		(661	)		2			(3,554	)		(7,019	)
Interest expense		(38,513	)		(11,245	)		(91,854	)		(30,630	)
Loss on early extinguishment of debt		—			—			(26,601	)		—

Net income (loss) before tax		(80,363	)		(21,392	)		(127,283	)		15,036
Income tax benefit		817			—			854			—
Net income (loss)		(79,546	)		(21,392	)		(126,429	)		15,036
Loss (income) attributable to non-controlling interests		52,022			9,982			78,062			(52,574	)
Net loss attributable to common limited partners	$	(27,524	)	$	(11,410	)	$	(48,367	)	$	(37,538	)

Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.54	)	$	(0.22	)	$	(0.94	)	$	(0.73	)

Weighted average common limited partner units outstanding:
Basic and Diluted		51,390			51,335			51,380			51,316

See accompanying notes to consolidated financial statements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Net income (loss)
   $ (5,189 ) $ 51,570    $ (46,883 ) $ 36,428
Other comprehensive income (loss):

Changes in fair value of derivative instruments accounted for as cash flow hedges
   44,381    (514 ) 19,437    13,655
Less: reclassification adjustment for realized gains of cash flow hedges in net income (loss)
   (2,286 ) (5,631 ) (3,279 ) (7,085 )


Total other comprehensive income (loss):
   42,095    (6,145 ) 16,158    6,570


Comprehensive income (loss):
   36,906    45,425    (30,725 ) 42,998
Comprehensive (income) loss attributable to non-controlling interests
   (29,262 ) (63,760 ) 14,110    (76,255 )


Comprehensive income (loss) attributable to common limited partners
   $ 7,644    $ (18,335 ) $ (16,615 ) $ (33,257 )

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			As Restated 2012			2013			As Restated 2012
Net income (loss)	$	(79,546	)	$	(21,392	)	$	(126,429	)	$	15,036
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		16,438			(19,487	)		35,875			(5,832	)
Less: reclassification adjustment for realized gains of cash flow hedges in net income (loss)		(1,300	)		(5,035	)		(4,579	)		(12,120	)
Total other comprehensive income (loss)		15,138			(24,522	)		31,296			(17,952	)
Comprehensive loss		(64,408	)		(45,914	)		(95,133	)		(2,916	)
Comprehensive (income) loss attributable to non-controlling interests		42,898			16,747			57,008			(59,508	)
Comprehensive loss attributable to common limited partners	$	(21,510	)	$	(29,167	)	$	(38,125	)	$	(62,424	)

See accompanying notes to consolidated financial statements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

   Common Limited
Partners’ Capital Accumulated
Other
Comprehensive
Income    Non-Controlling
Interest Total
Partners’
Capital
   Units    Amount
Balance at January 1, 2013
   51,365,582       $ 456,171    $ 9,699       $ 2,013,978    $ 2,479,848
Distributions to non-controlling interests
   —         —      —         (102,673 ) (102,673 )
Contributions from non-controlling interests
   —         —      —         4,676    4,676
Unissued common units under incentive plan
   —         11,085    —         14,843    25,928
Issuance of units under incentive plans
   19,234       —      —         84    84
Distributions paid to common limited partners
   —         (31,338 ) —         —      (31,338 )
Distribution equivalent rights paid on unissued units under incentive plans
   —         (1,387 ) —         (2,196 ) (3,583 )
Atlas Pipeline Partners, L.P. purchase price allocation
   —         —      —         (30,607 ) (30,607 )
Gain on issuance of Atlas Resource Partners, L.P.’s common units
   —         25,221    —         (25,221 ) —
Gain on issuance of Atlas Pipeline Partners, L.P.’s common units
   —         9,899    —         (9,899 ) —
Non-controlling interests’ capital contribution
   —         —      —         1,145,456    1,145,456
Other comprehensive income
   —         —      4,228       11,930    16,158
Net loss
   —         (20,843 ) —         (26,040 ) (46,883 )






Balance at June 30, 2013
   51,384,816       $ 448,808    $ 13,927       $ 2,994,331    $ 3,457,066

	Common Limited Partners’ Capital					Accumulated Other Comprehensive		Non-Controlling			Total Partners’
	Units		Amount			Income		Interest			Capital
Balance at January 1, 2013		51,365,582	$	456,171		$	9,699	$	2,013,978		$	2,479,848
Distributions to non-controlling interests		—		—			—		(171,551	)		(171,551	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—		8,277			8,277
Unissued common units under incentive plan		—		17,122			—		23,698			40,820
Issuance of units under incentive plans		33,282		—			—		119			119
Distributions paid to common limited partners		—		(53,949	)		—		—			(53,949	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(2,418	)		—		(3,631	)		(6,049	)
Atlas Pipeline Partners, L.P. purchase price allocation		—		—			—		(30,607	)		(30,607	)
Gain on issuance of Atlas Resource Partners, L.P.’s common units		—		25,221			—		(25,221	)		—
Gain on issuance of Atlas Pipeline Partners, L.P.’s common units		—		11,505			—		(11,505	)		—
Non-controlling interests’ capital contributions		—		—			—		1,208,979			1,208,979
Other comprehensive income		—		—			10,242		21,054			31,296
Net loss		—		(48,367	)		—		(78,062	)		(126,429	)
Balance at September 30, 2013		51,398,864	$	405,285		$	19,941	$	2,955,528		$	3,380,754

See accompanying notes to consolidated financial statements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

   Six Months Ended
June 30,
   2013 2012
CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)
   $ (46,883 ) $ 36,428
Adjustments to reconcile net income (loss) to net cash used in operating activities:

Depreciation, depletion and amortization
   120,246    62,484
Amortization of deferred financing costs
   9,228    2,954
Non-cash gain on derivative value, net
   (31,118 ) (61,401 )
Non-cash compensation expense
   26,154    15,835
Loss on asset sales and disposal
   2,893    7,021
Deferred income tax benefit
   (37 ) —
Loss on early extinguishment of debt
   26,601    —
Distributions paid to non-controlling interests
   (104,869 ) (54,407 )
Equity income in unconsolidated companies
   (1,856 ) (3,330 )
Distributions received from unconsolidated companies
   4,329    3,992
Changes in operating assets and liabilities:

Accounts receivable and prepaid expenses and other
   (18,694 ) 59,656
Accounts payable and accrued liabilities
   (70,201 ) (93,917 )


Net cash used in operating activities
   (84,207 ) (24,685 )


CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures
   (345,761 ) (192,040 )
Net cash paid for acquisitions
   (1,000,785 ) (241,925 )
Other
   (5,190 ) 1,049


Net cash used in investing activities
   (1,351,736 ) (432,916 )


CASH FLOWS FROM FINANCING ACTIVITIES:

Borrowings under credit facilities
   1,139,000    648,500
Repayments under credit facilities
   (1,678,425 ) (316,000 )
Net proceeds from issuance of Atlas Pipeline Partners, L.P.’s long-term debt
   1,028,449    —
Net proceeds from issuance of Atlas Resource Partners, L.P.’s long-term debt
   267,811    —
Repayments of Atlas Pipeline Partners, L.P. long-term debt
   (365,822 ) —
Net proceeds from subsidiary equity offerings
   1,145,456    119,389
Distributions paid to unitholders
   (31,338 ) (25,140 )
APL contributions received from non-controlling interests
   4,676    —
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt
   (25,581 ) —
Deferred financing costs and other
   (14,633 ) (13,827 )


Net cash provided by financing activities
   1,469,593    412,922


Net change in cash and cash equivalents
   33,650    (44,679 )
Cash and cash equivalents, beginning of year
   36,780    77,376


Cash and cash equivalents, end of period
   $ 70,430    $ 32,697

	Nine Months Ended September 30,
CASH FLOWS FROM OPERATING ACTIVITIES:	2013			2012
Net income (loss)	$	(126,429	)	$	15,036
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		214,313			99,563
Amortization of deferred financing costs		14,392			4,562
Non-cash (gain) loss on derivative value, net		11,851			(40,636	)
Non-cash compensation expense		41,700			28,487
Loss on asset sales and disposal		3,554			7,019
Deferred income tax benefit		(854	)		—
Loss on early extinguishment of debt		26,601			—
Distributions paid to non-controlling interests		(175,182	)		(86,589	)
Equity income in unconsolidated companies		(2,103	)		(5,582	)
Distributions received from unconsolidated companies		6,129			6,331
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		(71,493	)		30,357
Accounts payable and accrued liabilities		(1,869	)		(30,640	)
Net cash provided by (used in) operating activities		(59,390	)		27,908

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(533,688	)		(315,791	)
Net cash paid for acquisitions		(1,777,881	)		(301,247	)
Investment in joint ventures		(9,813	)		—
Other		(6,154	)		546
Net cash used in investing activities		(2,327,536	)		(616,492	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		1,996,000			940,500
Repayments under credit facilities		(1,884,425	)		(780,500	)
Net proceeds from issuance of Atlas Pipeline Partners, L.P.’s long-term debt		1,028,369			—
Net proceeds from issuance of Atlas Resource Partners, L.P.’s long-term debt		510,518			319,100
Repayments of Atlas Pipeline Partners, L.P. long-term debt		(365,822	)		—
Net proceeds from subsidiary equity offerings		1,208,979			119,389
Distributions paid to unitholders		(53,949	)		(37,971	)
APL contributions received from non-controlling interests		8,277			—
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt		(25,581	)		—
Deferred financing costs and other		(42,722	)		(16,055	)
Net cash provided by financing activities		2,379,644			544,463

Net change in cash and cash equivalents		(7,282	)		(44,121	)
Cash and cash equivalents, beginning of year		36,780			77,376
Cash and cash equivalents, end of period	$	29,498		$	33,255

See accompanying notes to consolidated financial statements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~June~~September 30, 2013

(Unaudited)

NOTE 1 –— BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS).

At ~~June~~September 30, 2013, the Partnership’s operations primarily consisted of its ownership interests in the ~~following entities:~~following:

Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. At ~~June~~September 30, 2013, the Partnership owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate ~~33.1%~~36.9% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) in ~~ARP (see Note 18);~~ARP;

Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services throughout the southwestern region of the United States. At ~~June~~September 30, 2013, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate ~~6.3%~~6.2% common limited partner interest in APL; ~~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 ~~June~~September 30, 2013, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 6); and

Certain natural gas and oil producing assets located inthe Arkoma Basin of eastern Oklahoma (see Note 3).

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

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation. Due to changes in business as a result of the formation of ARP during the ~~year~~three months ended December 31, 2012, management of the Partnership modified its reportable operating segments. As a result, management of the Partnership reclassified the operating segment data for the three and ~~six~~nine months ended ~~June~~September 30, 2012 to be consistent with the three and ~~six~~nine months ended ~~June~~September 30, 2013. The results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2013 may not necessarily be indicative of the results of operations for the full year ending December 31, 2013.

NOTE 2 –— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at ~~June~~September 30, 2013, except for ARP and APL, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the financial statements of

ARP and APL into its consolidated financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP and APL are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which ARP has an interest (“the Drilling Partnerships”). Such interests typically range from 20% to 41%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the West OK natural gas gathering system and processing plants and a 72.8% undivided interest in the West TX 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 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 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 balance sheets.

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

The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”) (see Note 3). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). APL consolidates 100% of this joint venture and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint ventures within partners’ capital on its consolidated balance sheets (see Note 3).

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 represent actual results in all material respects (see“Revenue Recognition”).

Receivables

Accounts receivable on the consolidated balance sheets consist ~~solely~~primarily of the trade accounts receivable associated with ~~ARP’s~~the Partnership and ~~APL’s operations.~~its subsidiaries. In evaluating the realizability of its accounts receivable, management ~~of ARP and APL~~ performs ongoing credit evaluations of ~~its~~ customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of ~~ARP’s and APL’s~~ customers’ credit information. ~~ARP~~The Partnership and ~~APL~~its subsidiaries extend credit on sales on an unsecured basis to many of its customers. At ~~June~~September 30, 2013 and December 31, 2012, ~~ARP and APL~~the Partnership had recorded no allowance for uncollectible accounts receivable on ~~the Partnership’s~~its consolidated balance sheets.

Inventory

~~ARP and APL~~

The Partnership had ~~$15.4~~$25.8 million and $13.5 million of inventory at ~~June~~September 30, 2013 and December 31, 2012, respectively, which were included within prepaid expenses and other current assets on ~~the Partnership’s~~its consolidated balance sheets. ~~ARP values~~The Partnership and its subsidiaries value inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price.

Property, Plant and Equipment

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

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

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

Upon the sale or retirement of ~~an ARP~~a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual ~~ARP~~ well, ~~ARP credits~~ the proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon ~~ARP’s~~ sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

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

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a 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 such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s ~~agreement, and in~~agreement. In general, ~~must be at~~ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the drilling Partnership based upon ARP’s determination of fair market ~~value supported by an appraisal of an independent expert selected by ARP.~~value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that ~~ARP~~the Partnership and ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded ~~by ARP~~on the Partnership’s consolidated statements of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2012, the Partnership recognized $9.5 million of asset impairments related to ARP’s gas and oil properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara Shales. These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. There were no impairments of proved gas and oil properties recorded ~~by ARP~~on the Partnership’s consolidated statements of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

Capitalized Interest

ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were ~~5.8%~~6.1% and ~~5.8%~~5.1% for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and 6.0% and ~~6.2%~~5.9% for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were ~~$4.8~~$5.1 million and ~~$2.3~~$2.8 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$10.7~~$15.8 million and ~~$4.6~~$7.3 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, 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 it 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.ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at ~~June~~September 30, 2013 and December 31, 2012 (in thousands):

   June 30,
2013 December 31,
2012 Estimated
Useful Lives
In Years
Gross Carrying Amount:

Customer contracts and relationships
   $ 726,072    $ 325,246    7 – 10
Partnership management and operating contracts
   14,344    14,344    13


   $ 740,416    $ 339,590


Accumulated Amortization:

Customer contracts and relationships
   $ (156,229 ) $ (125,886 )
Partnership management and operating contracts
   (13,188 ) (13,024 )


   $ (169,417 ) $ (138,910 )


Net Carrying Amount:

Customer contracts and relationships
   $ 569,843    $ 199,360
Partnership management and operating contracts
   1,156    1,320


   $ 570,999    $ 200,680

	September 30, 2013			December 31, 2012			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	726,072		$	325,246			7–10
Partnership management and operating contracts		14,344			14,344			13
	$	740,416		$	339,590

Accumulated Amortization:
Customer contracts and relationships	$	(180,117	)	$	(125,886	)
Partnership management and operating contracts		(13,285	)		(13,024	)
	$	(193,402	)	$	(138,910	)

Net Carrying Amount:
Customer contracts and relationships	$	545,955		$	199,360
Partnership management and operating contracts		1,059			1,320
	$	547,014		$	200,680

Amortization expense on intangible assets was ~~$22.3~~$24.0 million and ~~$6.0~~$6.3 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$30.5~~$54.5 million and ~~$11.9~~$18.1 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2013 ~~– $78.5~~- $78.4 million; 2014 –- $92.3 million; 2015 –- $87.0 million; 2016 ~~– $86.7~~- $86.9 million; and 2017 –- $80.9 million.

Goodwill

At ~~June~~September 30, 2013, the Partnership had ~~$534.1~~$535.7 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and ~~$502.3~~$503.9 million related to APL’s Cardinal and TEAK acquisitions (see Note 3). At December 31, 2012, the Partnership had $351.1 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $319.3 million related to APL’s acquisitions during the year ended December 31, 2012, of which $310.9 million related to the Cardinal acquisition (see Note 3). The change in goodwill is primarily related to an addition of ~~$279.3~~$280.3 million of goodwill from the TEAK acquisition offset by a ~~$97.2~~$96.4 million reduction in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the Cardinal acquisition (see Note 3). The goodwill related to APL’s Cardinal acquisition is a result of the strategic industry position of the assets and potential future synergies. The goodwill related to the TEAK acquisition is a result of the strategic industry position. The valuation assessments for the TEAK and Cardinal acquisitions have not been completed as of ~~June~~September 30, 2013. The estimated goodwill allocation as of ~~June~~September 30, 2013 is subject to change and may be material. There were no changes in the carrying amount of goodwill for ARP for the three and ~~six~~nine months ended ~~June~~September 30, ~~2013.~~

2013 and 2012.

ARP and APL test their goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership.

Capital Leases

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 8).

Derivative Instruments

~~ARP~~

The Partnership and ~~APL~~its subsidiaries enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 9). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in ~~ARP’s and APL’s~~the fair value of derivative ~~instrument’s fair value~~instruments are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

The Partnership and ARP ~~recognizes~~recognize an estimated liability for the plugging and abandonment of ~~its~~their respective gas and oil wells and related facilities (see Note 7). The Partnership and ARP also ~~recognizes~~recognize a liability for ~~its~~their respective future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to ~~2009.~~2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of ~~June~~September 30, 2013, except ~~for: 1)~~for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through ~~2011; and 2) an examination by the IRS related to one of ARP’s subsidiaries’ Federal Partnership Return for the period ended December 31,~~ 2011.

Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal Acquisition (see Note 3), the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of ~~June~~September 30, 2013 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 11).

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values (see Note 16).

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 16), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership

declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data):

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Net income (loss)
   $ (5,189 ) $ 51,570    $ (46,883 ) $ 36,428
Loss (income) attributable to non-controlling interests
   (3,058 ) (59,191 ) 26,040    (62,556 )


Net loss attributable to common limited partners
   (8,247 ) (7,621 ) (20,843 ) (26,128 )
Less: Net income attributable to participating securities – phantom units⁽¹⁾
   —      —      —      —


Net loss utilized in the calculation of net loss attributable to common limited partners per unit
   $ (8,247 ) $ (7,621 ) $ (20,843 ) $ (26,128 )

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income (loss)	$	(79,546	)	$	(21,392	)	$	(126,429	)	$	15,036
Loss (income) attributable to non-controlling interests		52,022			9,982			78,062			(52,574	)
Net loss attributable to common limited partners		(27,524	)		(11,410	)		(48,367	)		(37,538	)
Less: Net income attributable to participating securities – phantom units⁽¹⁾		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	$	(27,524	)	$	(11,410	)	$	(48,367	)	$	(37,538	)

⁽¹⁾

Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended ~~June~~September 30, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately ~~2,274,000~~2,322,000 and ~~2,101,000~~2,106,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately ~~2,245,000~~2,271,000 and ~~2,015,000~~2,046,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 16).

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Weighted average number of common limited partners per unit – basic
   51,380       51,318       51,375       51,306
Add effect of dilutive incentive awards⁽¹⁾
   —         —         —         —








Weighted average number of common limited partners per unit – diluted
   51,380       51,318       51,375       51,306

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Weighted average number of common limited partners per unit—basic		51,390		51,335		51,380		51,316
Add effect of dilutive incentive awards⁽¹⁾		—		—		—		—
Weighted average number of common limited partners per unit—diluted		51,390		51,335		51,380		51,316

⁽¹⁾

For the three months ended ~~June~~September 30, 2013 and 2012, approximately ~~4,092,000~~4,196,000 units and ~~3,084,000~~3,011,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, approximately ~~3,845,000~~3,963,000 units and ~~2,673,000~~2,786,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Accrued Producer Liabilities

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

Revenue Recognition

Natural gas and oil production. The Partnership and ARP generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership or ARP has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

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

ARP generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, ARP’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which ARP has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

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

•

~~Fee-Based Contracts.~~ These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. APL is also paid a separate compression fee on many of its gathering 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.

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. APL is also paid a separate compression fee on many of its gathering 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.

•

~~Percentage of Proceeds (“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.

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 processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. To offset the make-up obligation, APL retains the NGL which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/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 help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

~~ARP~~Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. 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 Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/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 help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

The Partnership and its subsidiaries accrue unbilled revenue and APL accrues the related purchase costs due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data ~~from ARP’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” for further description). ~~ARP~~The Partnership and ~~APL~~its subsidiaries had unbilled revenues at ~~June~~September 30, 2013 and December 31, 2012 of ~~$155.6~~$192.1 million and $134.2 million, respectively, which were included in accounts receivable within ~~the Partnership’s~~its consolidated balance sheets. APL’s accrued purchase costs at ~~June~~September 30, 2013 and December 31, 2012 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and ~~at June 30, 2013,~~for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 9). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

On October 23, 2013, the Partnership ~~revised~~filed a Form 10-K/A (“Form 10-K/A”) to amend its previously filed Annual Report on Form 10-K for the ~~presentation of its~~year ended December 31, 2012. In the Form 10-K/A, the Partnership restated the consolidated statements of comprehensive income (loss) ~~in order~~of the Partnership and subsidiaries for the years ended December 31, 2012, 2011 and 2010 to ~~more clearly distinguish~~reorder certain line items and subtotals presented, separately disclose the amounts of total other comprehensive income (loss), consolidated comprehensive income (loss), including amounts attributable to the common limited partners and attributable to non-controlling interests, and revise certain headings in such consolidated financial statements. The accompanying consolidated statements of comprehensive income (loss) for the three and nine month periods ended September 30, 2012 have been restated to conform with the presentation included within the Form 10-K/A. The previously reported amounts of comprehensive income (loss) attributable to each of the Partnership and the non-controlling interest. This change in presentation has been applied to all periods presented. The previously reported amounts of other comprehensive income (loss) attributable to the Partnershipcommon limited partners did not change for any ~~period.~~

of the previously reported periods.

Recently Adopted Accounting Standards

In ~~February~~July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10,Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes(“Update 2013-10”), which amends Accounting Standards Codification Topic 815. Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU No. 2013-02,Comprehensive Income (Topic 220)(“Update 2013-02”).Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In July 2013, the FASB issued ASU 2013-11,Income Taxes (Topic 740) ~~– Presentation~~–Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists(“Update 2013-11”),

which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption is permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership will apply the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

~~In July 2013, the FASB issued ASU 2013-10,~~~~Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes~~(“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (UST) and the London Interbank Offered Rate (LIBOR) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (OIS), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership will apply the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-04,Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date(“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 ��– ACQUISITIONS

ARP EP Energy Acquisition

On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P (“EP Energy”). Pursuant to the purchase and sale agreement, ARP acquired certain assets from EP Energy for approximately $705.9 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% ARP Senior Notes due August 15, 2021 (see Note 8), and the issuance of 14,950,000 common limited partner units and 3,749,986 newly created Class C convertible preferred units (see Note 14). The ARP assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The accompanying consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). All costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date

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

Assets:
Property, plant and equipment	$	720,118

Liabilities:



Asset retirement obligation

14,142

Net assets acquired
$
705,976

Revenues and net loss of $25.8 million and $4.8 million, respectively, have been included in the Partnership’s consolidated statements of operations related to the EP Energy Acquisition for the three and nine months ended September 30, 2013.

ARP’s DTE Acquisition

On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, LLC from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million, subject to certain post-closing adjustments (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 14). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s term loan credit facility (see Note 8).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

Assets:
Accounts receivable	$	10,721
Prepaid expenses and other		2,100
Total current assets		12,821

Property, plant and equipment		263,194
Other assets, net		273
Total assets acquired	$	276,288

Liabilities:
Accounts payable	$	7,760
Accrued liabilities		2,910
Total current liabilities		10,670

Asset retirement obligation and other		8,169
Total liabilities assumed		18,839
Net assets acquired	$	257,449

ARP’s Titan Acquisition

On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 14). The cash paid at closing was funded through borrowings under ARP’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 14).

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

Assets:

Cash and cash equivalents
   $ 372
Accounts receivable
   5,253
Prepaid expenses and other
   131


Total current assets
   5,756
Natural gas and oil properties
   208,491
Other assets, net
   2,344


Total assets acquired
   $ 216,591


Liabilities:

Accounts payable
   $ 676
Revenue distribution payable
   3,091
Accrued liabilities
   1,816


Total current liabilities
   5,583
Asset retirement obligation and other
   2,418


Total liabilities assumed
   8,001


Net assets acquired
   $ 208,590

Assets:



Cash and cash equivalents
$
372

Accounts receivable

5,253

Prepaid expenses and other

131

Total current assets

5,756





Property, plant and equipment

208,491

Other assets, net

2,344

Total assets acquired
$
216,591





Liabilities:



Accounts payable
$
676

Revenue distribution payable

3,091

Accrued liabilities

1,816

Total current liabilities

5,583





Asset retirement obligation and other

2,418

Total liabilities assumed

8,001

Net assets acquired
$
208,590

ARP’s Carrizo Acquisition

On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 14).

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

Assets:

Natural gas and oil properties
   $ 190,946
Liabilities:

Asset retirement obligation
   3,903


Net assets acquired
   $ 187,043

Assets:



Property, plant and equipment
$
190,946

Liabilities:



Asset retirement obligation

3,903

Net assets acquired
$
187,043

APL’s TEAK Acquisition.

On May 7, 2013, APL completed the acquisition of 100% of the equity interests held by TEAK Midstream, LLC (“TEAK”) for $1.0 billion in cash, subject to customary purchase price adjustments, less cash received (the “TEAK Acquisition”), including $50.0 million placed into escrow pending final settlement of working capital adjustments and to cover potential indemnity claims. The funds placed into escrow were recognized within prepaid expenses and other on the Partnership’s consolidated balance sheet as of ~~June~~September 30, 2013. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in southern Texas, including two cryogenic processing facilities, related gathering pipelines, a 75% interest in T2 LaSalle Gathering Company (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings, LLC (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”).

APL funded the purchase price for the TEAK Acquisition through:

the private placement of $400.0 million of its Class D convertible preferred units (“Class D Preferred ~~Units~~Units”) for net proceeds of $397.7 million, including the Partnership’s general partner contribution of $8.2 million to maintain its 2.0% general partner interest in APL (see Note 14);

the sale ~~of 11,845,000~~of11,845,000 APL common limited partner units in a public offering at a negotiated purchase price of $34.00 per unit, generating net proceeds of approximately $388.4 million, plus the Partnership’s general partner contribution of $8.3 million to maintain its 2.0% general partner interest in APL (see Note 14); and

borrowings under its senior secured revolving credit facility.

Subsequent to the closing of the TEAK Acquisition, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 (“4.75% APL Senior Notes”) on May 10, 2013 for net proceeds of $391.5 million to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 8).

APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet. In conjunction with APL’s issuance of the 4.75% APL Senior Notes and an amendment to its revolving credit facility (see Note 8), APL recorded $9.5 million of transaction fees as deferred financing costs, which are included in other assets, net on the Partnership’s consolidated balance sheet at September 30, 2013. All other costs associated with the acquisition were expensed as incurred.

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

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

Assets:

Cash
   $ 8,157
Accounts receivable
   11,837
Prepaid expenses and other
   567


Total current assets
   20,561
Property, plant and equipment
   290,118
Intangible assets
   285,000
Goodwill
   279,286
Equity method investment in joint ventures
   148,120


Total assets acquired
   $ 1,023,085


Liabilities:

Accounts payable and accrued liabilities
   15,405


Total liabilities assumed
   15,405


Net assets acquired
   1,007,680
Less cash received
   (8,157 )


Net cash paid for acquisition
   $ 999,523

Assets:
Cash	$	8,157
Accounts receivable		11,837
Prepaid expenses and other		1,871
Total current assets		21,865
Property, plant and equipment		290,118
Intangible assets		285,000
Goodwill		280,331
Equity method investment in joint ventures		148,120
Total assets acquired	$	1,025,434

Liabilities:
Accounts payable and accrued liabilities		17,754
Total liabilities assumed		17,754
Net assets acquired		1,007,680
Less cash received		(8,157	)
Net cash paid for acquisition	$	999,523

Revenues and net loss of ~~$20.2~~$39.2 million and ~~$2.5~~$8.8 million, respectively, for the three months ended September 30, 2013, and $59.2 million and $11.3 million, respectively, for the nine months ended September 30, 2013 from the acquisition date of May 7, 2013 have been included in the Partnership’s consolidated financial statements related to the TEAK ~~Acquisition for the three and six months ended June 30, 2013, respectively.~~Acquisition. Net income of ~~$1.1~~$1.0 million which was contributed from the TEAK Acquisition from April 1, 2013 (the effective date) to May 7, 2013 (the closing date) was included as a reduction to the purchase price adjustment.

APL’s Cardinal Acquisition

On December 20, 2012, APL completed the Cardinal Acquisition for $599.1 million in cash, including final purchase price adjustments. The assets from this acquisition, which are referred to as the APL Arkoma assets, include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas and a 60% interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by Mark-West Energy Partners, L.P. (NYSE: MWE)

(“MarkWest”). APL funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due 2020 (“6.625% APL Senior Notes”) at a premium of 3.0%, for net proceeds of $176.5 million (see Note 8); and from the sale of 10,507,033 APL common limited partner units in a public offering at a negotiated purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the Partnership’s contribution of $6.7 million to maintain its 2.0% general partner interest in APL (see Note 14). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 8). As part of the Cardinal Acquisition, APL placed $25.0 million into escrow to cover potential indemnity claims and was recognized within prepaid expenses and other on the Partnership’s consolidated balance sheet at December 31, 2012. The $25.0 million was released to the sellers ~~during the three and six months ended~~in June ~~30,~~ 2013.

APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the ~~preliminary~~ values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands):

Assets:

Cash
   $ 1,184
Accounts receivable
   13,783
Prepaid expenses and other
   1,289
Property, plant and equipment
   246,787
Intangible assets
   232,740
Goodwill
   213,677


Total assets acquired
   709,460


Liabilities:

Current portion of long-term debt
   341
Accounts payable and accrued liabilities
   14,128
Deferred tax liability, net
   35,353
Long-term debt, less current portion
   604


Total liabilities acquired
   50,426


Non-controlling interest
   58,703


Net assets acquired
   600,331
Less cash received
   (1,184 )


Net cash paid for acquisition
   $ 599,147

Assets:
Cash	$	1,184
Accounts receivable		13,783
Prepaid expenses and other		1,289
Property, plant and equipment		246,787
Intangible assets		232,740
Goodwill		214,532
Total assets acquired		710,315

Liabilities:
Current portion of long-term debt		341
Accounts payable and accrued liabilities		14,854
Deferred tax liability, net		35,353
Long-term debt, less current portion		604
Total liabilities acquired		51,152

Non-controlling interest		58,832

Net assets acquired		600,331
Less cash received		(1,184	)
Net cash paid for acquisition	$	599,147

The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was based upon the purchase price allocated to the 60% controlling interest APL acquired using an income approach. This measurement uses significant inputs that are not observable in the market and thus represents a fair value measurement categorized within Level 3 of the fair value hierarchy. The 40% non-controlling interest in Centrahoma was reduced by a 5.0% adjustment for lack of control that market participants would consider when measuring its fair value.

Pro Forma Financial Information

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the EP Energy and TEAK ~~acquisition,~~acquisitions, including the related borrowings, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2012. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the EP Energy and TEAK ~~acquisition~~acquisitions and related offerings and borrowings had occurred on January 1, 2012 or the results that will be attained in future periods (in thousands, except per share data; unaudited):

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Total revenues and other
   $ 653,846    $ 369,603    $ 1,197,892    $ 735,624
Net income (loss)
   (8,717 ) 38,631    (61,457 ) 12,081
Net loss attributable to common limited partners
   (9,409 ) (10,764 ) (25,031 ) (32,080 )
Net loss attributable to common limited partners per unit:

Basic and Diluted
   $ (0.18 ) $ (0.21 ) $ (0.49 ) $ (0.63 )

	Three Months Ended September 30,						NineMonthsEnded September30,
	2013			2012			2013			2012
Total revenues and other	$	662,914		$	391,511		$	1,925,582		$	1,185,573
Net loss		(57,948	)		(36,221	)		(89,270	)		(73,624	)
Net loss attributable to common limited partners		(19,351	)		(14,183	)		(38,589	)		(62,103	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.38	)	$	(0.28	)	$	(0.75	)	$	(1.21	)

Other Acquisitions

On July 31, 2013, the Partnership completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of the Partnership’s term loan facility (see Note 8). The Arkoma Acquisition had an effective date of May 1, 2013.

On September 20, 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013.

NOTE 4 –— APL EQUITY METHOD INVESTMENTS

The Partnership’s consolidated financial statements include APL’s 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), 75% interest in T2 LaSalle, 50% interest in T2 Eagle Ford and 50% interest in T2 EF Co-Gen. APL acquired its interests in T2 LaSalle, T2 Eagle Ford, and T2 EF Co-Gen (“T2 Joint Ventures”) as part of the TEAK Acquisition. The T2 Joint Ventures do meet the qualifications of a Variable Interest Entity (“VIE”), but APL does not meet the qualifications as the primary beneficiary. Under the terms of the respective joint venture agreements, APL is not the operator, does not have a controlling financial interest and shares equal management rights with TexStar Midstream Services, L.P. (“TexStar”). APL’s maximum exposure to loss as a result of its involvement with the joint ventures is limited to its equity investment, additional capital contribution commitments and APL’s share of any operating expenses incurred by the joint venture. Therefore, APL accounts for its investments in the joint ventures under the equity method of accounting. APL’s proportionate share of the net income of the joint ventures is included within other, net on the Partnership’s consolidated statement of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations.

The following ~~table presents~~tables present the Partnership’s equity method investments and equity income (loss) in joint ventures as of ~~June~~September 30, 2013 and December 31, 2012 (in thousands):

   Investment in Joint Venture
   June 30,
2013    December 31,
2012
WTLPG
   $ 86,129       $ 86,002
T2 LaSalle
   50,591       —
T2 Eagle Ford
   85,925       —
T2 EF Co-Gen
   9,445       —




Equity method investment in joint ventures
   $ 232,090       $ 86,002

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013 2012    2013 2012
Equity income in WTLPG
   $ 1,687    $ 1,917       $ 3,727    $ 2,813
Equity loss in T2 LaSalle
   (898 ) —         (898 ) —
Equity loss in T2 Eagle Ford
   (1,078 ) —         (1,078 ) —
Equity loss in T2 EF Co-Gen
   (183 ) —         (183 ) —




Equity income (loss) in joint ventures
   $ (472 ) $ 1,917       $ 1,568    $ 2,813

	Investment in Joint Venture
	September 30, 2013		December 31, 2012
WTLPG	$	85,718	$	86,002
T2 LaSalle		49,337		—
T2 Eagle Ford		88,693		—
T2 EF Co-Gen		14,473		—
Equity method investment in joint ventures	$	238,221	$	86,002

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
Equity income in WTLPG	$	1,389		$	1,422	$	5,116		$	4,235
Equity loss in T2 LaSalle		(1,263	)		—		(2,162	)		—
Equity loss in T2 Eagle Ford		(1,120	)		—		(2,198	)		—
Equity loss in T2 EF Co-Gen		(888	)		—		(1,070	)		—
Equity income (loss) in joint ventures	$	(1,882	)	$	1,422	$	(314	)	$	4,235

NOTE 5 –— PROPERTY, PLANT AND EQUIPMENT

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

   June 30,
2013 December 31,
2012 Estimated
Useful Lives
in Years
Natural gas and oil properties:

Proved properties:

Leasehold interests
   $ 257,863    $ 244,476
Pre-development costs
   3,750    1,935
Wells and related equipment
   1,350,304    1,222,475


Total proved properties
   1,611,917    1,468,886
Unproved properties
   293,631    292,053
Support equipment
   14,300    13,110


Total natural gas and oil properties
   1,919,848    1,774,049
Pipelines, processing and compression facilities
   2,804,533    2,326,186    2 – 40
Rights of way
   186,863    179,018    20 – 40
Land, buildings and improvements
   28,956    25,609    3 – 40
Other
   31,698    26,656    3 – 10


   4,971,898    4,331,518
Less – accumulated depreciation, depletion and amortization
   (935,711 ) (828,909 )


   $ 4,036,187    $ 3,502,609

	September 30, 2013			December 31, 2012			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	293,397		$	244,476
Pre-development costs		4,328			1,935
Wells and related equipment		2,202,330			1,222,475
Total proved properties		2,500,055			1,468,886
Unproved properties		266,827			292,053
Support equipment		17,447			13,110
Total natural gas and oil properties		2,784,329			1,774,049
Pipelines, processing and compression facilities		2,924,666			2,326,186			2–40
Rights of way		191,034			179,018			20–40
Land, buildings and improvements		29,542			25,609			3–40
Other		33,097			26,656			3–10
		5,962,668			4,331,518
Less – accumulated depreciation, depletion and amortization		(1,004,117	)		(828,909	)
	$	4,958,551		$	3,502,609

During the three and ~~six~~nine months ended ~~June~~September 30, 2013, ARP recognized $0.7 million and ~~$1.4~~$2.0 million, respectively, of loss on asset sales and disposal, pertaining to its decision not to drill wells on leasehold property that expired during the three and ~~six~~nine months ended ~~June~~September 30, 2013 in Indiana and Tennessee. During the ~~three and six~~nine months ended ~~June~~September 30, 2013, APL recognized $1.5 million of loss on asset sales and disposal primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired. No gain or loss was recognized by APL during the three months ended September 30, 2013.

During the ~~six~~nine months ended ~~June~~September 30, 2012, ARP recognized a $7.0 million loss on asset sales and disposal pertaining to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve

due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the year ended December 31, 2012.

During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Antrim and Niobrara Shales. These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

NOTE 6 –— OTHER ASSETS

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

   June 30,
2013    December 31,
2012
Deferred financing costs, net of accumulated amortization of $35,281 and $26,053 at June 30, 2013 and December 31, 2012, respectively
   $ 62,090       $ 45,629
Investment in Lightfoot
   19,440       19,882
ARP’s notes receivable
   4,312       —
Security deposits
   2,159       2,390
Other
   4,720       3,101




   $ 92,721       $ 71,002

	September 30, 2013		December 31, 2012
Deferred financing costs, net of accumulated amortization of $40,445 and $26,053 at September 30, 2013 and December 31, 2012, respectively	$	88,572	$	45,629
Investment in Lightfoot		21,570		19,882
ARP’s notes receivable		4,127		—
Security deposits		3,552		2,390
Other		5,708		3,101
	$	123,529	$	71,002

Deferred ~~finance~~financing costs.Deferred financing costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). Amortization expense of deferred ~~finance~~financing costs was ~~$3.0~~$5.2 million and $1.6 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$6.0~~$11.1 million and ~~$3.0~~$4.6 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations.

During the ~~six~~three and nine months ended ~~June~~September 30, 2013, the Partnership capitalized $10.2 million and $10.6 million, respectively, of deferred financing costs related to its revolving and term loan credit facilities (see Note 8). During the three and nine months ended September 30, 2013, ARP capitalized $21.3 million of deferred financing costs related to its amended revolving credit facility and the 9.25% ARP Senior Notes due August 15, 2021 (see Note 8). During the nine months ended September 30, 2013, ARP also recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of senior unsecured notes due 2021 (“7.75% ARP Senior Notes”) (see Note 8).

APL capitalized $0.1 million and $6.0 million of deferred financing costs during the three months ended September 30, 2013 and 2012, respectively, and $22.5 million and $9.4 million of deferred financing costs during the nine months ended September 30, 2013 and 2012, respectively. During the ~~six~~nine months ended ~~June~~September 30, 2013, APL recorded $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% unsecured senior notes due 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 8). There was no accelerated amortization of deferred financing costs during the three months ended ~~June~~September 30, 2013 and 2012 and during the ~~six~~nine months ended ~~June~~September 30, 2012.

Notes Receivable.At ~~June~~September 30, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which ~~was~~were included within other assets on the Partnership’s consolidated balance sheet. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For the three and ~~six~~nine months ended ~~June~~September 30, 2013, approximately $25,000 and $50,000, respectively, of interest income was recognized within other, net on the Partnership’s consolidated ~~statement~~statements of operations. There was no interest income recognized for the three and ~~six~~nine months ended ~~June~~September 30, 2012. At ~~June~~September 30, 2013, ARP recorded no allowance for credit losses within the Partnership’s consolidated balance sheet based upon payment history and ongoing credit evaluations.

Investment in Lightfoot.At ~~June~~September 30, 2013, the Partnership ~~owns~~owned an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen,

Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot LP focuses its investments primarily on incubating new master limited partnerships (“MLPs”) and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three and ~~six~~nine months ended ~~June~~September 30, 2013, the Partnership recognized equity income of approximately ~~$0.3~~$2.1 million and $2.4 million, respectively, within other, net on the Partnership’s consolidated statements of operations. During the three and ~~six~~nine months ended ~~June~~September 30, 2012, the Partnership recognized equity income of ~~$0.2~~$0.8 million and ~~$0.5~~$1.3 million, respectively. During the three months ended ~~June~~September 30, 2013, no cash distribution was received by the Partnership. During the three months ended September 30, 2012, the Partnership received net cash distributions of approximately $0.5 million. During the nine months ended September 30, 2013 and 2012, the Partnership received net cash distributions of approximately $0.7 million and ~~$0.2 million, respectively. During the six months ended June 30, 2013 and 2012, the Partnership received net cash distributions of approximately $0.7 million and $0.4~~$0.9 million, respectively.

NOTE 7 –— ASSET RETIREMENT OBLIGATIONS

The Partnership and ARP recognized an estimated liability for the plugging and abandonment of ~~its~~their respective gas and oil wells and related facilities. The Partnership and ARP also recognized a liability for ~~its~~their respective future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability was based on ~~ARP’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 was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership and ARP ~~has~~have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership and ARP’s gas and oil properties, the Partnership and its subsidiaries determined that there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At ~~June~~September 30, 2013, the Drilling Partnerships had ~~$58.4~~$62.3 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. During ~~both~~ the three and ~~six~~nine months ended ~~June~~September 30, 2013, ARP withheld approximately ~~$40,000~~$0.1 and $0.2 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the three and ~~six~~nine months ended ~~June~~September 30, 2012. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of ~~the~~their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity ~~prices,~~price trends, the natural decline in the production of the wells, and current and future costs.

Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

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

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Asset retirement obligations, beginning of period
   $ 66,386    $ 46,538    $ 64,794    $ 45,779
Liabilities incurred
   599    3,911    1,244    4,092
Liabilities settled
   (216 ) (132 ) (223 ) (250 )
Accretion expense
   963    729    1,917    1,425


Asset retirement obligations, end of period
   $ 67,732    $ 51,046    $ 67,732    $ 51,046

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Asset retirement obligations, beginning of period	$	67,732		$	51,046		$	64,794		$	45,779
Liabilities incurred		17,306			2,424			18,550			6,516
Liabilities settled		(158	)		(198	)		(381	)		(448	)
Accretion expense		1,353			768			3,270			2,193
Asset retirement obligations, end of period	$	86,233		$	54,040		$	86,233		$	54,040

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Partnership’s consolidated balance sheets. During the three and nine months ended September 30, 2013, the

Partnership incurred $2.6 million of future plugging and abandonment costs related to the Arkoma Acquisition it consummated during the period. During the three and nine months ended September 30, 2013, ARP incurred $14.1 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period. During the three and nine months ended September 30, 2012, ARP incurred $2.0 million and $5.9 million, respectively, of future plugging and abandonment costs related to other acquisitions it consummated during those respective periods.

NOTE 8 –— DEBT

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

   June 30,
2013 December 31,
2012
Revolving credit facility
   $ 34,000    $ 9,000
ARP revolving credit facility
   —      276,000
ARP term loan credit facility
   —      75,425
ARP 7.75 % Senior Notes – due 2021
   275,000    —
APL revolving credit facility
   80,000    293,000
APL 8.75 % Senior Notes – due 2018
   —      370,184
APL 6.625 % Senior Notes – due 2020
   504,894    505,231
APL 5.875 % Senior Notes – due 2023
   650,000    —
APL 4.750 % Senior Notes – due 2021
   400,000    —
APL capital leases
   925    11,503


Total debt
   1,944,819    1,540,343
Less current maturities
   (522 ) (10,835 )


Total long-term debt
   $ 1,944,297    $ 1,529,508

September 30,
2013


December 31,
2012

Term loan facility
$
240,000


$
—

Revolving credit facility

—



9,000

ARP revolving credit facility

425,000



276,000

ARP term loan credit facility

—



75,425

ARP 7.75 % Senior Notes – due 2021

275,000



—

ARP 9.25 % Senior Notes – due 2021

248,279



—

APL revolving credit facility

100,000



293,000

APL 8.75 % Senior Notes – due 2018

—



370,184

APL 6.625 % Senior Notes – due 2020

504,725



505,231

APL 5.875 % Senior Notes – due 2023

650,000



—

APL 4.750 % Senior Notes – due 2021

400,000



—

APL capital leases

927



11,503

Total debt

2,843,931



1,540,343

Less current maturities

(3,010
)


(10,835
)
Total long-term debt
$
2,840,921


$
1,529,508

Partnership’s ~~Credit Facility~~Term Loan Facility.

~~In May 2012,~~

On July 31, 2013, in connection with the Arkoma Acquisition, the Partnership ~~entered into~~received net proceeds of $230.2 million under a ~~credit~~$240.0 million secured term facility with a ~~syndicate~~group of ~~banks that matures in May 2016 (see Note 18)~~outside investors (the “Term Facility”). On March 1, 2013, the Partnership amended its credit facility to increase its maximum lender commitments to $100.0 million, of which up to $5.0 million of the credit facility may be in the form of standby letters of credit. At ~~June~~September 30, 2013, ~~$34.0~~$240.0 million was outstanding under the ~~credit facility.~~Term Facility. The ~~Partnership’s obligations~~Term Facility has a maturity date of July 31, 2019. Borrowings under the credit facility are secured by substantially all of its assets, including its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility may be guaranteed by future subsidiaries. AtTerm Facility bear interest, at the Partnership’s election ~~interest on borrowings under the credit facility is determined by~~at either LIBOR plus an applicable margin of ~~between 3.50% and 4.50%~~5.50% per annum or the alternate base rate (“ABR”) plus an applicable margin of ~~between 2.50% and 3.50%~~4.50% per annum. ~~The applicable margin will fluctuate based on~~Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the ~~utilization of~~interest periods selected by the ~~facility.~~Partnership. The Partnership is required to ~~pay a fee between 0.5%~~repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and ~~0.625% per annum on~~continuing until the ~~unused portion of~~maturity date when the ~~borrowing base, which~~remaining balance is ~~included within interest expense on the Partnership’s consolidated statement of operations.~~due. At ~~June~~September 30, 2013, the weighted average interest rate on its outstanding ~~credit facility~~Term Facility borrowings was ~~4.2%~~6.5%.

The ~~credit agreement~~Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a ~~commitment deficiency exists or a~~ default ~~under the credit agreement~~ exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Term Facility also contains a covenant that requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility) the same as those in the Partnership’s credit facility. At September 30, 2013, the Partnership was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, asdefaults in the payment of ~~June~~other indebtedness over a specified threshold, insolvency and change of control.

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

Partnership’s Revolving Credit Facility

On July 31, 2013, in connection with the Arkoma Acquisition, the Partnership entered into an amended and restated credit agreement with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At September 30, ~~2013.~~2013, no amounts were outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility are guaranteed by its material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either LIBOR plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

The credit ~~agreement~~facility contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The credit facility also contains covenants that (i) require the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit ~~agreement)~~facility) to EBITDA (as defined in the credit ~~agreement)~~facility) not greater than ~~3.25~~4.5 to 1.0 as of the last day of ~~any fiscal~~the quarter ~~and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75~~ending September 30, 2013; 4.0 to 1.0 as of the last day of ~~any fiscal quarter.~~each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) require the Partnership to enter into swaps agreements with respect to the assets acquired in the Arkoma Acquisition. Based on the ~~definitions contained~~definition in the Partnership’s credit ~~agreement, its~~facility, the Partnership’s ratio of Total Funded Debt to EBITDA was ~~0.5~~2.8 to ~~1.0 and its ratio of EBITDA~~1.0. During the three months ended September 30, 2013, the Partnership entered into swap agreements with respect to ~~Consolidated Interest Expense was 97.0~~the assets acquired in the Arkoma Acquisition.

The credit facility is subject to ~~1.0 at June 30, 2013.~~

an intercreditor agreement as described above under the “Partnership’s Term Loan Facility”.

At ~~June~~September 30, 2013, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

ARP’s Credit Facility

~~At June 30,~~

On July 31, 2013, in connection with the acquisition of assets from EP Energy (see Note 3), ARP ~~had~~entered into a second amended and restated credit agreement (“ARP Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amended and restated ARP’s existing revolving credit facility. The Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of ~~$430.0~~$835.0 million and a maximum facility amount of $1.5 billion, which is scheduled to mature in ~~March 2016 (see Note 18).~~July 2018. At ~~June~~September 30, 2013, ~~no amounts were~~$425.0 million was outstanding under the credit facility. ~~In January 2013, ARP repaid in full its $75.4 million term loan credit facility, which was scheduled to mature in May 2014, with proceeds from its issuance of 7.75% ARP Senior Notes.~~ Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which ~~$0.6~~$2.1 million was outstanding at ~~June~~September 30, 2013. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by ~~substantially all~~certain of ARP’s ~~subsidiaries.~~material subsidiaries, and any subsidiaries of ARP, other than subsidiary guarantors, are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either LIBOR plus an applicable margin between 1.75% and ~~3.00%~~2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal Funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and ~~2.00%~~1.75% per annum. ARP is also required to pay a fee ~~of 0.5% per annum~~ on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At September 30, 2013, the weighted average interest rate on outstanding borrowings under the credit facility was 2.2%.

The ~~revolving credit agreement~~ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of ~~June~~September 30, 2013. The ~~credit agreement~~ARP Credit Agreement also requires ARP 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 4.50 to 1.0 as of the last

day of the quarter ended September 30, 2013, 4.25 to 1.0 as of the last day of ~~any fiscal quarter ending on or before~~the quarters ended December 31, 2013 and March 31, 2014 and 4.0 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit agreement, ~~its~~at September 30, 2013, ARP’s ratio of current assets to current liabilities was ~~3.9~~2.7 to 1.0 and its ratio of Total Funded Debt to EBITDA was ~~2.3~~4.2 to ~~1.0 at June 30, 2013.~~1.0.

ARP Senior Notes

On September 30, 2013, ARP had $275.0 million principal outstanding of 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) and $248.3 million principal outstanding of 9.25% Senior Notes due 2021 (“9.25% ARP Senior Notes”). On July 30, 2013, ARP issued $250.0 million of its 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs, of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of September 30, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date being February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time periods, the 9.25% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes due 2021 in a private placement transaction at par. ARP used the net proceeds of approximately ~~$267.8~~$267.7 million, net of underwriting fees and other offering costs of ~~$7.2~~$7.3 million, to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. ~~Under~~In connection with the ~~terms~~retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility ~~the~~ borrowing base, ~~was reduced by 15%~~ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the ~~7.75% ARP Senior Notes to $368.8 million.~~nine months ended September 30, 2013 (see Note 6). Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. ~~The indenture governing~~

In connection with the issuance of the 7.75% ARP Senior Notes, ~~contains~~ARP entered into registration rights agreements, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by January 23, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 7.75% ARP Senior Notes. If ARP fails to comply with its obligations to register the 7.75% ARP Senior Notes within the specified time period, the 7.75% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes.

The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. As of September 30, 2013, ARP was a holding company and had no independent assets or operations of its own. The

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

The indentures governing the 7.75% and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of ~~June~~September 30, 2013.

APL Credit Facility

At ~~June~~September 30, 2013, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which ~~$80.0~~$100.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus ~~1.00%~~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 ~~June~~September 30, 2013 was 3.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.4 million was outstanding at ~~June~~September 30, 2013. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at ~~June~~September 30, 2013. At ~~June~~September 30, 2013, APL had ~~$519.6~~$499.6 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK and West TX entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies.

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

The events which constitute an event of default under the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. On April 19, 2013, APL entered into an amendment to the credit agreement which, among other changes, adjusted certain covenant ratio limits and adjusted the method of calculation in connection with the TEAK acquisition. APL was in compliance with these covenants as of ~~June~~September 30, 2013.

APL Senior Notes Issuances

At ~~June~~September 30, 2013, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes due 2020, $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $400.0 million of 4.75% Senior Notes due 2021 (with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.5 million after underwriting commissions and other transactions costs and utilized the proceeds to repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see Note 3). Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In connection with the issuance of the 4.75% APL Senior Notes, APL entered into a registration rights ~~agreements,~~agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by May 5, 2014. If APL does not meet the aforementioned deadline, the 4.75% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated. On October 4, 2013, APL filed a registration statement with the SEC for an exchange offer for the 4.75% Senior Notes.

On February 11, 2013, APL issued $650.0 million of 5.875% ~~senior notes~~Senior Notes in a private placement transaction. The 5.875%APLSenior Notes were issued at par. APL received net proceeds of $637.3 million after underwriting commissions and other transaction costs and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In connection with the issuance of the 5.875% APL Senior Notes, APL entered into a registration rights ~~agreements,~~agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued 5.875% APL Senior Notes for registered notes, and (b) cause the exchange offer to be consummated by February 6, 2014. If APL does not meet the aforementioned deadline, the 5.875% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated.

On October 4, 2013, APL filed a registration statement with the SEC for an exchange offer for the 5.875% Senior Notes.

On September 28, 2012 and December 20, 2012, APL issued an aggregate of $500.0 million of its 6.625% ~~senior notes~~APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were presented combined with a net ~~$4.9~~$4.7 million unamortized premium as of ~~June~~September 30, 2013. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. ~~On July 22, 2013,~~The registration statement APL filed ~~its registration statement~~ with the SEC ~~in satisfaction of~~for the ~~registration requirements~~exchange offer for the 6.625% APL Senior Notes became effective on September 17, 2013. APL commenced an exchange offering for the 6.625% APL Senior Notes on September 18, 2013 and the exchange offer was completed on October 16, 2013. Pursuant to the terms of the registration rights ~~agreement.~~agreement, because the exchange offer was not consummated within the required timeframe, APL incurred a 0.25% interest penalty from September 23, 2013 through consummation of the exchange offer on October 16, 2013.

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

Indentures governing the APL Senior Notes contain covenants, including limitations on APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets. APL was in compliance with these covenants as of ~~June~~September 30, 2013.

APL Senior Notes Redemptions

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% APL Senior Notes due 2018 plus a $6.3 million premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes due 2023. During the ~~six~~nine months ended ~~June~~September 30, 2013, APL recognized a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid, $8.0 million consent payment and a $5.3 million write-off of deferred financing costs (see Note 6), partially offset by $4.2 million of unamortized premium recognized.

and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture. APL also ~~issued a notice to redeem~~redeemed all the 8.75% APL Senior Notes not purchased in connection with the tender offer.

APL Capital Leases

The following is a summary of the leased property under capital leases as of ~~June~~September 30, 2013 and December 31, 2012, which are included within property, plant and equipment, net (see Note 5) (in thousands):

   June 30,
2013 December 31,
2012
Pipelines, processing and compression facilities
   $ 2,085    $ 15,457
Less – accumulated depreciation
   (240 ) (1,066 )


   $ 1,845    $ 14,391

	September 30, 2013			December 31, 2012
Pipelines, processing and compression facilities	$	2,281		$	15,457
Less – accumulated depreciation		(284	)		(1,066	)
	$	1,997		$	14,391

On May 30, 2013, APL accelerated payment on certain leases and purchased the leased property by paying approximately $7.5 million in accordance with the lease agreements. These leases were to mature in August 2013.

Depreciation expense for leased properties was approximately ~~$39,000~~$44,000 and $0.2 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and $0.3 million and ~~$0.4~~$0.5 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively. Depreciation expense for leased properties is included within depreciation, depletion and amortization expense on the Partnership’s consolidated statements of operations.

Cash payments for interest by the Partnership and its subsidiaries were ~~$29.3~~$62.3 million and ~~$19.5~~$23.8 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively.

NOTE 9 –— DERIVATIVE INSTRUMENTS

The Partnership ~~ARP~~ and ~~APL~~its subsidiaries use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. The Partnership ~~ARP~~ and ~~APL~~its subsidiaries enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership ~~ARP~~ and ~~APL~~its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

The Partnership ~~ARP~~ and ~~APL~~its subsidiaries formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership ~~ARP~~ and ~~APL~~its subsidiaries 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 ~~ARP~~ and ~~APL~~its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management ~~of the Partnership, ARP 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 statements of operations. For derivatives qualifying as hedges, the Partnership ~~ARP~~ and ~~APL~~its subsidiaries recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income (loss) and reclassify the portion relating to the Partnership and ARP’s commodity derivatives 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 statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, ~~the Partnership, ARP and APL recognize~~ changes in fair value are recognized within fair value within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations as they occur.

The Partnership ~~ARP~~ and ~~APL~~its subsidiaries enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options.

The Partnership ~~ARP~~ and ~~APL~~its subsidiaries enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated balance sheets of ~~$90.9~~$61.8 million and $51.3 million at ~~June~~September 30, 2013 and December 31, 2012, respectively. Of the ~~$13.9~~$19.9 million of net gain in accumulated other comprehensive income ~~(loss)~~ within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at ~~June~~September 30, 2013, if the fair values of the instruments remain at current market values, the Partnership will reclassify ~~$8.7~~$7.5 million of gains to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of ~~$5.2~~$12.4 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. Approximately ~~$0.5~~$1.4 million and $0.9 million of derivative ~~loss was~~gains were reclassified from other comprehensive income related to derivative instruments entered into during the three and ~~six~~nine months ended ~~June 30, 2013.~~

~~In June 2013, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through~~ September 30, 2013, for production volumes related to assets acquired from EP Energy E&P Company L.P. (“EP Energy”) (see Note 18). In connection with the swaption contracts, the Partnership paid premiums of $2.0 million which represented their fair value on the date the transactions were initiated and was initially recorded as a derivative asset on the Partnership’s consolidated balance sheet. Swaption contract premiums paid are amortized over the period from initiation on the contract through their termination date. For the three months ended June 30, 2013, the Partnership recognized approximately $0.2 million of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.respectively.

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

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
(Gain) loss reclassified from accumulated other comprehensive income (loss):

Gas and oil production revenue
   $ (2,286 ) $ (6,739 ) $ (3,279 ) $ (9,339 )
Gathering and processing revenue
   —      1,108    —      2,254


Total
   $ (2,286 ) $ (5,631 ) $ (3,279 ) $ (7,085 )

Three Months Ended
September 30,


Nine Months Ended
September 30,


2013


2012


2013


2012

(Gain) loss reclassified from accumulated other comprehensive income (loss):















Gas and oil production revenue
$
(1,300
)

$
(6,114
)

$
(4,579
)

$
(15,453
)
Gathering and processing revenue

—



1,079



—



3,333

Total
$
(1,300
)

$
(5,035
)

$
(4,579
)

$
(12,120
)

The Partnership

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

   Gross
Amounts of
Recognized
Assets    Gross
Amounts
Offset in the
Consolidated
Balance Sheets    Net Amount of
Assets Presented
in the Consolidated
Balance Sheets
Offsetting Derivative Assets

As of June 30, 2013

Current portion of derivative assets
   $ 3,592       $ —         $ 3,592
Long-term portion of derivative assets
   —         —         —
Current portion of derivative liabilities
   —         —         —
Long-term portion of derivative liabilities
   —         —         —






Total derivative assets
   $ 3,592       $ —         $ 3,592






As of December 31, 2012

Current portion of derivative assets
   $ —         $ —         $ —
Long-term portion of derivative assets
   —         —         —
Current portion of derivative liabilities
   —         —         —
Long-term portion of derivative liabilities
   —         —         —






Total derivative assets
   $ —         $ —         $ —

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2013
Current portion of derivative assets	$	1,082	$	—		$	1,082
Long-term portion of derivative assets		1,549		(3	)		1,546
Current portion of derivative liabilities		—		—			—
Long-term portion of derivative liabilities		—		—			—
Total derivative assets	$	2,631	$	(3	)	$	2,628
As of December 31, 2012
Current portion of derivative assets	$	—	$	—		$	—
Long-term portion of derivative assets		—		—			—
Current portion of derivative liabilities		—		—			—
Long-term portion of derivative liabilities		—		—			—
Total derivative assets	$	—	$	—		$	—

~~Gross~~
~~Amounts of~~
~~Recognized~~
~~Liabilities~~ ~~Gross~~
~~Amounts~~
~~Offset in the~~
~~Consolidated~~
~~Balance Sheets~~ ~~Net Amount of~~
~~Liabilities Presented~~
~~in the Consolidated~~
~~Balance Sheets~~
~~Offsetting Derivative Liabilities~~
~~As of June 30, 2013~~
~~Current portion of derivative assets~~
$ —   $ —   $ —
~~Long-term portion of derivative assets~~
—   —   —
~~Current portion of derivative liabilities~~
—   —   —
~~Long-term portion of derivative liabilities~~
—   —   —


Gross
Amounts of
Recognized
Liabilities


Gross Amounts
Offset in the
Consolidated
Balance Sheets


Net Amount of Liabilities
Presented in the
Consolidated
Balance Sheets

Offsetting Derivative Liabilities












As of September 30, 2013












Current portion of derivative assets

$
—


$
—


$
—

Long-term portion of derivative assets


(3
)


3



—

Current portion of derivative liabilities


—



—



—

Long-term portion of derivative liabilities


—



—



—

Total derivative liabilities

$
(3
)

$
3


$
—

As of December 31, 2012












Current portion of derivative assets

$
—


$
—


$
—

Long-term portion of derivative assets


—



—



—

Current portion of derivative liabilities


—



—



—

Long-term portion of derivative liabilities


—



—



—

Total derivative liabilities

$
—


$
—


$
—


~~Total derivative liabilities~~
$ —   $ —   $ —
~~As of December 31, 2012~~
~~Current portion of derivative assets~~
$ —   $ —   $ —
~~Long-term portion of derivative assets~~
—   —   —
~~Long-term portion of derivative liabilities~~
—   —   —
~~Total derivative liabilities~~
$ —   $ —   $ —

During the three and ~~six~~nine months ended ~~June~~September 30, 2013, ~~and 2012,~~ the Partnership ~~had no~~recorded gains ~~or losses~~of $0.2 million on settled derivative contracts within its consolidated statements of operations. These gains were included within gas and oil production revenue in the Partnership’s consolidated statement of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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

September 30, 2013, the Partnership recognized approximately $2.1 million and $2.3 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

At ~~June~~September 30, 2013, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price ~~Swaptions~~Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price    Fair Value
Asset
   (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾    (in thousands)⁽²⁾
2014
   2,760,000       $ 4.156       $ 1,343
2015
   2,280,000       $ 4.295       850
2016
   1,440,000       $ 4.423       416
2017
   1,200,000       $ 4.590       272
2018
   420,000       $ 4.797       84


         $ 2,965

~~Natural Gas Put Options~~

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2013		750,000	$	4.058	$	347
2014		2,760,000	$	4.177		875
2015		2,280,000	$	4.302		555
2016		1,440,000	$	4.433		377
2017		1,200,000	$	4.590		333
2018		420,000	$	4.797		141
		The Partnership’s net asset			$	2,628

Production Period Ending December 31,
   Option Type    Volumes    Average
Fixed Price    Fair Value
Asset
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾    (in thousands)⁽²⁾
2013
   Puts purchased    1,500,000       $ 3.958       $ 627


            $ 627


Total Partnership net assets
            $ 3,592

⁽¹⁾	“MMBtu” represents million British Thermal Units.

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

Atlas Resource Partners

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

   Gross
Amounts of
Recognized
Assets    Gross
Amounts
Offset in the
Consolidated
Balance Sheets Net Amount of
Assets Presented
in the Consolidated
Balance Sheets
Offsetting Derivative Assets

As of June 30, 2013

Current portion of derivative assets
   $ 37,766       $ (2,191 ) $ 35,575
Long-term portion of derivative assets
   18,377       (6,209 ) 12,168
Current portion of derivative liabilities
   20       (20 )
Long-term portion of derivative liabilities
   622       (622 ) —




Total derivative assets
   $ 56,785       $ (9,042 ) $ 47,743




As of December 31, 2012

Current portion of derivative assets
   $ 14,248       $ (1,974 ) $ 12,274
Long-term portion of derivative assets
   14,724       (5,826 ) 8,898
Long-term portion of derivative liabilities
   800       (800 ) —




Total derivative assets
   $ 29,772       $ (8,600 ) $ 21,172

									Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities

As of June 30, 2013
Offsetting Derivative Assets
As of September 30, 2013
Current portion of derivative assets	$	(2,191	)	$	2,191	$	—		$	23,643	$	(4,169	)	$	19,474
Long-term portion of derivative assets		(6,209	)		6,209		—			32,060		(3,560	)		28,500
Current portion of derivative liabilities		(92	)		20		(72	)		254		(254	)		—
Long-term portion of derivative liabilities		(752	)		622		(130	)		—		—			—


Total derivative liabilities	$	(9,244	)	$	9,042	$	(202	)


Total derivative assets									$	55,957	$	(7,983	)	$	47,974
As of December 31, 2012
Current portion of derivative assets	$	(1,974	)	$	1,974	$	—		$	14,248	$	(1,974	)	$	12,274
Long-term portion of derivative assets		(5,826	)		5,826		—			14,724		(5,826	)		8,898
Long-term portion of derivative liabilities		(1,688	)		800		(888	)		800		(800	)		—


Total derivative liabilities	$	(9,488	)	$	8,600	$	(888	)

Total derivative assets									$	29,772	$	(8,600	)	$	21,172

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2013
Current portion of derivative assets	$	(4,169	)	$	4,169		$	—
Long-term portion of derivative assets		(3,560	)		3,560			—
Current portion of derivative liabilities		(572	)		254			(318	)
Long-term portion of derivative liabilities		—			—			—
Total derivative liabilities	$	(8,301	)	$	7,983		$	(318	)
As of December 31, 2012
Current portion of derivative assets	$	(1,974	)	$	1,974		$	—
Long-term portion of derivative assets		(5,826	)		5,826			—
Long-term portion of derivative liabilities		(1,688	)		800	��		(888	)
Total derivative liabilities	$	(9,488	)	$	8,600		$	(888	)

In June 2012, ARP received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility (see Note 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income (loss) and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

In ~~June 2013,~~connection with the EP Energy Acquisition, ARP entered into swaption contracts ~~which provided the option to enter into swaptions~~ up through September 30, 2013 for production volumes related to assets ARP acquired from EP Energy (see Note ~~18)~~3). In connection with the swaption contracts, ARP paid premiums of ~~$11.3~~$14.5 million which represented their fair value on the date the transactions were initiated and ~~was~~were initially recorded as a derivative ~~asset~~assets on the Partnership’s consolidated balance ~~sheet.~~sheet and was fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through ~~their~~ termination date. For the three and nine months ended ~~June~~September 30, 2013, ARP recognized ~~approximately $1.3~~$13.2 million and $14.5 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

In ~~March 2012,~~connection with the Carrizo Acquisition, ARP entered into swaption contracts ~~which provided the option to enter into swaptions~~ up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 3). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented their fair value on the date the transactions were initiated and was initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and was fully amortized as of ~~June~~September 30, 2012. For the ~~three and six~~nine months ended ~~June~~September 30, 2012, ARP recorded ~~$3.6 million and~~ $4.6 million of amortization expense in other, net on the Partnership’s consolidated statements of operations related to the swaption contracts.

No amortization expense was recorded on the Partnership’s consolidated statements of operations for the three months ended September 30, 2012.

ARP recognized gains of ~~$2.3~~approximately $1.1 million and ~~$6.7~~$6.1 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and gains of ~~$3.3~~$4.4 million and ~~$9.3~~$15.5 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At ~~June~~September 30, 2013, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,


   Volumes    Average
Fixed Price    Fair Value
Asset/(Liability)
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾    (in thousands)⁽²⁾
2013
      14,694,800       $ 3.821       $ 2,599
2014
      31,353,000       $ 4.139       7,160
2015
      27,234,500       $ 4.237       2,580
2016
      33,746,300       $ 4.359       990
2017
      24,120,000       $ 4.538       (720 )
2018
      3,960,000       $ 4.716       (472 )


            $ 12,137

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2013		15,597,400	$	3.909	$	4,881
2014		60,153,000	$	4.152		17,536
2015		50,274,500	$	4.240		9,113
2016		43,946,300	$	4.318		6,556
2017		24,840,000	$	4.532		5,501
2018		3,960,000	$	4.716		1,030
					$	44,617

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⁾
2013
   Puts purchased    2,760,000       $ 4.395       $ 2,252
2013
   Calls sold    2,760,000       $ 5.443       (32 )
2014
   Puts purchased    3,840,000       $ 4.221       2,287
2014
   Calls sold    3,840,000       $ 5.120       (418 )
2015
   Puts purchased    3,480,000       $ 4.234       1,903
2015
   Calls sold    3,480,000       $ 5.129       (731 )


            $ 5,261

~~Natural Gas Put Options~~


Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset		Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾			(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2013	Puts purchased		14,280,000	$	3.957	$	5,965	Puts purchased		1,380,000	$	4.395	$	1,134
2013								Calls sold		1,380,000	$	5.443		(2	)
2014								Puts purchased		3,840,000	$	4.221		2,257
2014								Calls sold		3,840,000	$	5.120		(284	)
2015								Puts purchased		3,480,000	$	4.234		2,059
2015								Calls sold		3,480,000	$	5.129		(655	)
													$	4,509
						$	5,965

Natural Gas Put Options – Drilling ~~Partnership~~Partnerships

Production Period Ending December 31,
   Option Type    Volumes    Average
Fixed Price    Fair Value
Asset
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾    (in thousands)⁽²⁾
2013
   Puts purchased    1,080,000       $ 3.450       $ 124
2014
   Puts purchased    1,800,000       $ 3.800       574
2015
   Puts purchased    1,440,000       $ 4.000       546
2016
   Puts purchased    1,440,000       $ 4.150       584


            $ 1,828

~~Natural Gas Fixed Price Swaptions~~


Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset		Option Type	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾			(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾		(in thousands)⁽²⁾
2013							Puts purchased		540,000	$	3.450	$	25
2014		26,880,000	$	4.159		12,816	Puts purchased		1,800,000	$	3.800		541
2015		17,760,000	$	4.297		6,649	Puts purchased		1,440,000	$	4.000		608
2016							Puts purchased		1,440,000	$	4.150		762
												$	1,936
					$	19,465

Natural Gas Liquids Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price    Fair Value
Asset/(Liability)
   (Bbl)⁽¹⁾    (per Bbl)⁽¹⁾    (in thousands)⁽³⁾
2013
   63,000       $ 93.656       $ (99 )
2014
   105,000       $ 91.571       169
2015
   96,000       $ 88.550       282
2016
   84,000       $ 85.651       233
2017
   60,000       $ 83.780       157


         $ 742

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		(in thousands)⁽³⁾
2013		36,000	$	93.656	$	(327	)
2014		105,000	$	91.571		(389	)
2015		96,000	$	88.550		—
2016		84,000	$	85.651		68
2017		60,000	$	83.780		45
					$	(603	)

Natural Gas Liquids Ethane Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price    Fair Value
Asset
   (Gal)⁽¹⁾    (per Gal)⁽¹⁾    (in thousands)⁽⁴⁾
2014
   2,520,000       $ 0.303       $ 98


         $ 98

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾		(in thousands)⁽⁴⁾
2014		2,520,000	$	0.303	$	100
					$	100

Natural Gas Liquids Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾		(in thousands)⁽⁵⁾
2013		3,864,000	$	1.084	$	4
2014		11,592,000	$	0.996		(11	)
					$	(7	)

Crude Oil Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price    Fair Value
Asset/(Liability)
   (Bbl)⁽¹⁾    (per Bbl)⁽¹⁾    (in thousands)⁽³⁾
2013
   262,850       $ 92.307       $ (766 )
2014
   414,000       $ 91.727       692
2015
   411,000       $ 88.030       1,009
2016
   165,000       $ 85.931       503
2017
   72,000       $ 84.175       215


         $ 1,653

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		(in thousands)⁽³⁾
2013		170,200	$	93.738	$	(1,530	)
2014		552,000	$	92.668		(1,515	)
2015		567,000	$	88.144		(211	)
2016		225,000	$	85.523		155
2017		132,000	$	83.305		39
					$	(3,062	)

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⁾
2013
   Puts purchased    35,000       $ 90.000       $ 75
2013
   Calls sold    35,000       $ 116.396       (10 )
2014
   Puts purchased    41,160       $ 84.169       227
2014
   Calls sold    41,160       $ 113.308       (63 )
2015
   Puts purchased    29,250       $ 83.846       240
2015
   Calls sold    29,250       $ 110.654       (77 )


            $ 392


Total ARP net assets
            $ 47,541

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		(in thousands)⁽³⁾
2013	Puts purchased		20,000	$	90.000	$	12
2013	Calls sold		20,000	$	116.396		(5	)
2014	Puts purchased		41,160	$	84.169		132
2014	Calls sold		41,160	$	113.308		(76	)
2015	Puts purchased		29,250	$	83.846		181
2015	Calls sold		29,250	$	110.654		(78	)
						$	166
				ARP’s net asset		$	47,656

⁽¹⁾	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

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

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

⁽⁴⁾	Fair value based on forward Mt. Belvieu ethane prices, as applicable.

⁽⁵⁾	Fair value based on forward Mt. Belvieu propane prices, as applicable.

At ~~June~~September 30, 2013, ARP had net cash proceeds of ~~$4.2~~$5.9 million related to ARP’s hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts.

The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of ~~June~~September 30, 2013 and December 31, 2012.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At ~~June~~September 30, 2013, net unrealized derivative assets of ~~$1.8~~$1.9 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

The derivatives payable to the Drilling Partnerships related to both the hedge monetization proceeds and future natural gas production of the Drilling Partnerships at June 30, 2013 and December 31, 2012 were included in the Partnership’s consolidated balance sheets as follows (in thousands):

   June 30,
2013 December 31,
2012
Current portion of derivative payable to Drilling Partnerships:

Hedge monetization proceeds
   $ (5,560 ) $ (10,748 )
Hedge contracts covering future natural gas production
   (409 ) (545 )
Long-term portion of derivative payable to Drilling Partnerships:

Hedge monetization proceeds
   1,381    (205 )
Hedge contracts covering future natural gas production
   (1,419 ) (2,224 )


   $ (6,007 ) $ (13,722 )

At ~~June~~September 30, 2013, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships ~~will~~ have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 8), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

Atlas Pipeline Partners

APL has elected not to apply hedge accounting for derivative contracts entered into in July 2008 and after. Changes in the fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting was reclassified from within accumulated other comprehensive income ~~(loss)~~ on the Partnership’s consolidated balance sheets to gathering and processing revenue on the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. During the three and ~~six~~nine months ended ~~June~~September 30, 2012, APL reclassified losses of $1.1 million and ~~$2.3~~$3.3 million, respectively, out of accumulated other comprehensive income ~~(loss)~~ related to derivative contracts entered into prior to July 2008. As of December 31, 2012, all amounts had been reclassified out of accumulated other comprehensive income, ~~(loss),~~ and APL had no amounts outstanding within accumulated other comprehensive ~~income (loss).~~income.

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

   Gross
Amounts of
Recognized
Assets Gross
Amounts
Offset in the
Consolidated
Balance Sheets Net Amounts of
Assets Presented in
the Consolidated
Balance Sheets
Offsetting Derivative Assets

As of June 30, 2013

Current portion of derivative assets
   $ 25,877    $ (642 ) $ 25,235
Long-term portion of derivative assets
   15,630    (1,039 ) 14,591
Current portion of derivative liabilities
   5    (5 ) —


Total derivative assets
   $ 41,512    $ (1,686 ) $ 39,826


As of December 31, 2012

Current portion of derivative assets
   $ 23,534    $ (457 ) $ 23,077
Long-term portion of derivative assets
   9,637    (1,695 ) 7,942


Total derivative assets
   $ 33,171    $ (2,152 ) $ 31,019


   Gross
Amounts of
Recognized
Liabilities Gross
Amounts
Offset in the
Consolidated
Balance Sheets Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheets
Offsetting Derivative Liabilities

As of June 30, 2013

Current portion of derivative assets
   $ (642 ) $ 642    $ —
Long-term portion of derivative assets
   (1,039 ) 1,039    —
Current portion of derivative liabilities
   (100 ) 5    (95 )


Total derivative liabilities
   $ (1,781 ) $ 1,686    $ (95 )


As of December 31, 2012

Current portion of derivative liabilities
   $ (457 ) $ 457    $ —
Long-term portion of derivative liabilities
   (1,695 ) 1,695    —


Total derivative liabilities
   $ (2,152 ) $ 2,152    $ —

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2013
Current portion of derivative assets	$	7,981	$	(2,804	)	$	5,177
Long-term portion of derivative assets		9,186		(1,728	)		7,458
Current portion of derivative liabilities		1,171		(1,171	)		—
Total derivative assets	$	18,338	$	(5,703	)	$	12,635
As of December 31, 2012
Current portion of derivative assets	$	23,534	$	(457	)	$	23,077
Long-term portion of derivative assets		9,637		(1,695	)		7,942
Total derivative assets	$	33,171	$	(2,152	)	$	31,019

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2013
Current portion of derivative assets	$	(2,804	)	$	2,804	$	—
Long-term portion of derivative assets		(1,728	)		1,728		—
Current portion of derivative liabilities		(2,314	)		1,171		(1,143	)
Total derivative liabilities	$	(6,846	)	$	5,703	$	(1,143	)
As of December 31, 2012
Current portion of derivative liabilities		(457	)		457		—
Long-term portion of derivative liabilities		(1,695	)		1,695		—
Total derivative liabilities	$	(2,152	)	$	2,152	$	—

As of ~~June~~September 30, 2013, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period
   Purchased/
Sold    Commodity    Volumes⁽²⁾    Average
Fixed Price    Fair Value⁽¹⁾
Asset/(Liability)
(in thousands)
Natural Gas

2013
   Sold    Natural Gas    3,100,000       $ 3.689       $ 85
2014
   Sold    Natural Gas    12,600,000       $ 3.983       454
2015
   Sold    Natural Gas    15,160,000       $ 4.235       1,342
2016
   Sold    Natural Gas    3,750,000       $ 4.399       193
Natural Gas Liquids

2013
   Sold    Natural Gas Liquids    27,468,000       $ 1.247       10,880
2014
   Sold    Natural Gas Liquids    55,566,000       $ 1.248       8,278
2015
   Sold    Natural Gas Liquids    23,688,000       $ 1.110       2,213
Crude Oil

2013
   Sold    Crude Oil    153,000       $ 96.873       159
2014
   Sold    Crude Oil    312,000       $ 92.368       412
2015
   Sold    Crude Oil    60,000       $ 85.130       (65 )


Total Fixed Price Swaps
               $ 23,951

Production Period	Purchased/ Sold	Commodity	Volumes⁽²⁾	Average Fixed Price		Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
Natural Gas
2013	Sold	Natural Gas	1,570,000	$	3.752	$	245
2014	Sold	Natural Gas	12,600,000	$	3.983		1,344
2015	Sold	Natural Gas	15,160,000	$	4.235		2,745
2016	Sold	Natural Gas	3,750,000	$	4.399		769
Natural Gas Liquids
2013	Sold	Natural Gas Liquids	18,774,000	$	1.200		2,234
2014	Sold	Natural Gas Liquids	75,978,000	$	1.185		(2,007)
2015	Sold	Natural Gas Liquids	27,216,000	$	1.097		191
Crude Oil
2013	Sold	Crude Oil	75,000	$	96.660		(385)
2014	Sold	Crude Oil	312,000	$	92.368		(1,181)
2015	Sold	Crude Oil	60,000	$	85.130		(213)
Total Fixed Price Swaps						$	3,742

Options

Production Period
   Purchased/
Sold    Type Commodity    Volumes⁽²⁾    Average
Strike Price    Fair Value⁽¹⁾
Asset
(in thousands)
Natural Gas

2014
   Purchased    Put    Natural Gas    600,000       $ 4.125       $ 319
Natural Gas Liquids

2013
   Purchased    Put    Natural Gas Liquids    23,184,000       $ 1.897       6,646
2014
   Purchased    Put    Natural Gas Liquids    3,150,000       $ 1.030       377
2015
   Purchased    Put    Natural Gas Liquids    1,260,000       $ 0.883       183
Crude Oil

2013
   Purchased    Put    Crude Oil    147,000       $ 100.100       989
2014
   Purchased    Put    Crude Oil    448,500       $ 94.685       4,313
2015
   Purchased    Put    Crude Oil    270,000       $ 89.175       2,953


Total Options
                  $ 15,780


Total APL net assets
                  $ 39,731

Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset (in thousands)
Natural Gas
2014	Purchased	Put	Natural Gas	600,000	$	4.125	$	312
Natural Gas Liquids
2013	Purchased	Put	Natural Gas Liquids	11,844,000	$	1.900		1,893
2014	Purchased	Put	Natural Gas Liquids	4,410,000	$	1.001		261
2015	Purchased	Put	Natural Gas Liquids	1,890,000	$	0.901		173
Crude Oil
2013	Purchased	Put	Crude Oil	75,000	$	100.100		164
2014	Purchased	Put	Crude Oil	448,500	$	94.685		2,591
2015	Purchased	Put	Crude Oil	270,000	$	89.175		2,356
Total Options							$	7,750
				APL’s net asset			$	11,492

⁽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.

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Gain recognized in gain on mark-to-market derivatives:

Commodity contract – realized⁽¹⁾
   $ 2,844       $ 3,685       $ 4,480       $ 2,922
Commodity contract – unrealized⁽²⁾
   24,263       64,162       10,544       52,890








Gain on mark-to-market derivatives
   $ 27,107       $ 67,847       $ 15,024       $ 55,812

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Gain (loss) recognized in gain (loss) on mark-to-market derivatives:
Commodity contract—realized⁽¹⁾	$	(907	)	$	4,157		$	3,573		$	7,079
Commodity contract – unrealized⁽²⁾		(23,610	)		(23,064	)		(13,066	)		29,826
Gain (loss) on mark-to-market derivatives	$	(24,517	)	$	(18,907	)	$	(9,493	)	$	36,905

⁽¹⁾	Realized gain represents the gain incurred when the derivative contract expires and/or is cash settled.

⁽²⁾	Unrealized gain represents the mark-to-market gain recognized on open derivative contracts, which have not yet ~~been~~ settled.

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

   June 30,
2013 December 31,
2012
Current portion of derivative asset
   $ 64,402    $ 35,351
Long-term derivative asset
   26,759    16,840
Current portion of derivative liability
   (167 ) —
Long-term derivative liability
   (130 ) (888 )


Total Partnership net asset
   $ 90,864    $ 51,303

	September 30, 2013			December 31, 2012
Current portion of derivative asset	$	25,733		$	35,351
Long-term derivative asset		37,504			16,840
Current portion of derivative liability		(1,461	)		—
Long-term derivative liability		—			(888	)
Total Partnership net asset	$	61,776		$	51,303

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership and its subsidiaries own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level ~~1 –~~1–Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 –Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 –Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership ~~ARP~~ and ~~APL~~its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 9). The Partnership ~~ARP~~ and ~~APL~~its subsidiaries manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. The Partnership ~~ARP’s~~ and ~~APL’s~~its subsidiaries’ commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which isare considered to be Level 3 inputs. The prices for propane, isobutene, normal butane and natural gasoline are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying

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

Information for the Partnership’s ~~ARP’s~~ and ~~APL’s~~its subsidiaries’ assets and liabilities measured at fair value at ~~June~~September 30, 2013 and December 31, 2012 was as follows (in thousands):

   Level 1    Level 2 Level 3 Total
As of June 30, 2013

Derivative assets, gross

Commodity puts
   $ —         $ 627    $ —      $ 627
Commodity swaptions
   —         2,965    —      2,965
ARP Commodity swaps
   —         22,544    —      22,544
ARP Commodity puts
   —         7,793    —      7,793
ARP Commodity options
   —         6,983    —      6,983
ARP Commodity swaptions
   —         19,465    —      19,465
APL Commodity swaps
   —         4,041    21,691    25,732
APL Commodity options
   —         8,574    7,206    15,780




Total derivative assets, gross
   —         72,992    28,897    101,889




Derivative liabilities, gross

Commodity puts
   —         —      —      —
Commodity swaptions
   —         —      —      —
ARP Commodity swaps
   —         (7,914 ) —      (7,914 )
ARP Commodity puts
   —         —      —      —
ARP Commodity options
   —         (1,330 ) —      (1,330 )
ARP Commodity swaptions
   —         —      —      —
APL Commodity swaps
   —         (1,462 ) (319 ) (1,781 )




Total derivative liabilities, gross
   —         (10,706 ) (319 ) (11,025 )




Total derivatives, fair value, net
   $ —         $ 62,286    $ 28,578    $ 90,864




As of December 31, 2012

Derivative assets, gross

ARP Commodity swaps
   $ —         $ 15,859    $ —      $ 15,859
ARP Commodity puts
   —         2,991    —      2,991
ARP Commodity options
   —         10,923    —      10,923
APL Commodity swaps
   —         2,007    17,573    19,580
APL Commodity options
   —         7,322    6,269    13,591




Total derivative assets, gross
   —         39,102    23,842    62,944




Derivative liabilities, gross

ARP Commodity swaps
   —         (6,813 ) —      (6,813 )
ARP Commodity puts
   —         —      —      —
ARP Commodity options
   —         (2,676 ) —      (2,676 )
APL Commodity swaps
   —         (1,393 ) (759 ) (2,152 )




Total derivative liabilities, gross
   —         (10,882 ) (759 ) (11,641 )




Total derivatives, fair value, net
   $ —         $ 28,220    $ 23,083    $ 51,303

	Level 1		Level 2			Level 3			Total
As of September 30, 2013
Derivative assets, gross
Commodity swaps	$	—	$	2,631		$	—		$	2,631
ARP Commodity swaps		—		48,248			—			48,248
ARP Commodity puts		—		1,936			—			1,936
ARP Commodity options		—		5,773			—			5,773
APL Commodity swaps		—		5,362			5,226			10,588
APL Commodity options		—		5,423			2,327			7,750
Total derivative assets, gross		—		69,373			7,553			76,926
Derivative liabilities, gross
Commodity swaps		—		(3	)		—			(3	)
ARP Commodity swaps		—		(7,202	)		—			(7,202	)
ARP Commodity options		—		(1,099	)		—			(1,099	)
APL Commodity swaps		—		(2,038	)		(4,808	)		(6,846	)
Total derivative liabilities, gross		—		(10,342	)		(4,808	)		(15,150	)
Total derivatives, fair value, net	$	—	$	59,031		$	2,745		$	61,776
As of December 31, 2012
Derivative assets, gross
ARP Commodity swaps	$	—	$	15,859		$	—		$	15,859
ARP Commodity puts		—		2,991			—			2,991
ARP Commodity options		—		10,923			—			10,923
APL Commodity swaps		—		2,007			17,573			19,580
APL Commodity options		—		7,322			6,269			13,591
Total derivative assets, gross		—		39,102			23,842			62,944
Derivative liabilities, gross
ARP Commodity swaps		—		(6,813	)		—			(6,813	)
ARP Commodity puts		—		—			—			—
ARP Commodity options		—		(2,676	)		—			(2,676	)
APL Commodity swaps		—		(1,393	)		(759	)		(2,152	)
Total derivative liabilities, gross		—		(10,882	)		(759	)		(11,641	)
Total derivatives, fair value, net	$	—	$	28,220		$	23,083		$	51,303

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

   NGL Fixed Price Swaps NGL Put Options Total
   Gallons Amount Gallons Amount Amount
Balance – January 1, 2013
   87,066    $ 16,814    38,556    $ 6,269    $ 23,083
New contracts⁽¹⁾
   48,132    —      5,670    619    619
Cash settlements from unrealized gain (loss)⁽²⁾⁽³⁾
   (28,476 ) (8,831 ) (16,632 ) 3,497    (5,334 )
Net change in unrealized loss⁽²⁾
   —      13,389    —      2,002    15,391
Option premium recognition⁽³⁾
   —      —      —      (5,181 ) (5,181 )


Balance – June 30, 2013
   106,722    $ 21,372    27,594    $ 7,206    $ 28,578

	NGL Fixed Price Swaps						NGL Put Options						Total
	Gallons			Amount			Gallons			Amount			Amount
Balance – January 1, 2013		87,066		$	16,814			38,556		$	6,269		$	23,083
New contracts⁽¹⁾		77,364			—			7,560			816			816
Cash settlements from unrealized gain (loss)⁽²⁾⁽³⁾		(42,462	)		(11,769	)		(27,972	)		5,680			(6,089	)
Net change in unrealized loss⁽²⁾		—			(4,627	)		—			(1,482	)		(6,109	)
Option premium recognition⁽³⁾		—			—			—			(8,956	)		(8,956	)
Balance – September 30, 2013		121,968		$	418			18,144		$	2,327		$	2,745

⁽¹⁾	Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade.

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

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

The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at ~~June~~September 30, 2013 and December 31, 2012 (in thousands):

   Gallons    Third Party
Quotes⁽¹⁾ Adjustments⁽²⁾ Total
Amount
As of June 30, 2013

Propane swaps
   81,900       $ 16,565    $ (180 ) $ 16,385
Isobutane swaps
   5,040       (1,072 ) 752    (320 )
Normal butane swaps
   3,780       952    169    1,121
Natural gasoline swaps
   16,002       6,460    (2,274 ) 4,186




Total NGL swaps – June 30, 2013
   106,722       $ 22,905    $ (1,533 ) $ 21,372




As of December 31, 2012

Propane swaps
   69,678       $ 16,302    $ (552 ) $ 15,750
Isobutane swaps
   1,134       (219 ) 187    (32 )
Normal butane swaps
   6,174       (909 ) 242    (667 )
Natural gasoline swaps
   10,080       3,247    (1,484 ) 1,763




Total NGL swaps – December 31, 2012
   87,066       $ 18,421    $ (1,607 ) $ 16,814

	Gallons		Third Party Quotes⁽¹⁾			Adjustments⁽²⁾			Total Amount
As of September 30, 2013
Propane swaps		92,106	$	645		$	(88	)	$	557
Isobutane swaps		6,300		(2,208	)		1,006			(1,202	)
Normal butane swaps		7,560		1			335			336
Natural gasoline swaps		16,002		1,533			(806	)		727
Total NGL swaps — September 30, 2013		121,968	$	(29	)	$	447		$	418

As of December 31, 2012
Propane swaps		69,678	$	16,302		$	(552	)	$	15,750
Isobutane swaps		1,134		(219	)		187			(32	)
Normal butane swaps		6,174		(909	)		242			(667	)
Natural gasoline swaps		10,080		3,247			(1,484	)		1,763
Total NGL swaps – December 31, 2012		87,066	$	18,421		$	(1,607	)	$	16,814

⁽¹⁾	Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.

⁽²⁾

Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three year historical period.

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

   Adjustment Based upon Regression
Coefficient
   Level 3
Fair Value
Adjustments Lower
95%    Upper
95%    Average
Coefficient
As of June 30, 2013

Propane swaps
   $ (180 ) 0.8951       0.9050       0.9001
Isobutane swaps
   752    1.1225       1.1319       1.1272
Normal butane swaps
   169    1.0361       1.0405       1.0383
Natural gasoline swaps
   (2,274 ) 0.9116       0.9321       0.9219



Total NGL swaps – June 30, 2013
   $ (1,533 )



As of December 31, 2012

Propane swaps
   $ (552 ) 0.9019       0.9122       0.9071
Isobutane swaps
   187    1.1285       1.1376       1.1331
Normal butane swaps
   242    1.0370       1.0416       1.0393
Natural gasoline swaps
   (1,484 ) 0.8988       0.9169       0.9078



Total NGL swaps – December 31, 2012
   $ (1,607 )

				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of September 30, 2013
Propane swaps	$	(88	)		0.8959		0.9060		0.9009
Isobutane swaps		1,006			1.1194		1.1291		1.1242
Normal butane swaps		335			1.0345		1.0389		1.0367
Natural gasoline swaps		(806	)		0.9729		0.9754		0.9741
Total NGL swaps – September 30, 2013	$	447

				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of December 31, 2012
Propane swaps	$	(552	)		0.9019		0.9122		0.9071
Isobutane swaps		187			1.1285		1.1376		1.1331
Normal butane swaps		242			1.0370		1.0416		1.0393
Natural gasoline swaps		(1,484	)		0.8988		0.9169		0.9078
Total NGL swaps – December 31, 2012	$	(1,607	)

APL had ~~$9.1~~$20.0 million and $7.8 million of NGL linefill at ~~June~~September 30, 2013 and December 31, 2012, respectively, which were included within prepaid expenses and other on the Partnership’s consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill is defined as a Level 3 asset and is valued using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of ~~$0.3~~$0.4 million and $0.4 million as of ~~June~~September 30, 2013 and December 31, 2012, respectively.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the ~~six~~nine months ended ~~June~~September 30, 2013 (in thousands):

   NGL Linefill
   Gallons    Amount
Balance – January 1, 2013
   9,148       $ 7,783
NGL linefill additions⁽¹⁾
   2,862       2,659
Net change in NGL linefill valuation⁽²⁾
   —         (1,366 )




Balance – June 30, 2013
   12,010       $ 9,076

	NGL Linefill
	Gallons			Amount
Balance – January 1, 2013		9,148		$	7,783
Deliveries into NGL linefill		52,334			41,950
NGL linefill sales		(39,787	)		(30,769	)
Net change in NGL linefill valuation⁽¹⁾		—			(332	)
Acquired NGL linefill⁽²⁾		2,213			1,368
Balance – September 30, 2013		23,908		$	20,000

~~(1)~~

~~NGL linefill resulting from the addition of new transportation contracts.~~

~~(2)~~	⁽¹⁾Included within gathering and processing revenues on the ~~Partnership’s~~Partnership’s consolidated statements of ~~operations.~~operations..
⁽²⁾NGL linefill acquired as part of the TEAK Acquisition (see Note 3).

Other Financial Instruments

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

The Partnership and its subsidiaries’ other current assets and liabilities on its consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Partnership and its subsidiaries’ debt at ~~June~~September 30, 2013 and December 31, 2012, which consist principally of ARP’s and APL’s senior notes and borrowings under the Partnership’s, ARP’s and APL’s revolving and term loan credit facilities, were ~~$1,838.2~~$2,754.4 million and $1,576.9 million, respectively, compared with the carrying amounts of ~~$1,944.8~~$2,843.9 million and $1,540.3 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP and APL senior notes were based upon the market approach and calculated using the yields of the ARP and APL senior notes as provided by financial institutions and thus were categorized as a Level 3 value.

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

The Partnership and ARP ~~estimates~~estimate the fair value of ~~its~~their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and ARP and estimated inflation rates (see Note 7).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 was as follows (in thousands):

   Three Months Ended June 30,
   2013    2012
   Level 3    Total    Level 3    Total
Asset retirement obligations
   $ 599       $ 599       $ 3,911       $ 3,911








Total
   $ 599       $ 599       $ 3,911       $ 3,911








   Six Months Ended June 30,
   2013    2012
   Level 3    Total    Level 3    Total
Asset retirement obligations
   $ 1,244       $ 1,244       $ 4,092       $ 4,092








Total
   $ 1,244       $ 1,244       $ 4,092       $ 4,092

~~On May 7,~~

	Three Months Ended September 30,
	2013				2012
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	17,306	$	17,306	$	2,424	$	2,424
Total	$	17,306	$	17,306	$	2,424	$	2,424

	Nine Months Ended September 30,
	2013				2012
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	18,550	$	18,550	$	6,516	$	6,516
Total	$	18,550	$	18,550	$	6,516	$	6,516

During the three months ended September 2013, the Partnership completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the nine months ended September 30, 2013, APL completed the TEAK Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan and the DTE Acquisition, while APL completed the Cardinal Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. AsThe fair values of ~~June 30, 2013,~~natural gas and oil properties were measured using a discounted cash flow model, which considered the ~~accounting~~estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Partnership’s and ARP’s existing methodology for recognizing an estimated liability for the ~~TEAK Acquisition has not been completed.~~plugging and abandonment of its gas and oil wells (see Note 7). These inputs require significant judgments and estimates by ~~APL’s~~the Partnership’s and ARP’s management at the time of the valuation and are subject to change.

In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period (“Trigger Payments”). Sufficient volumes were achieved in December 2012, and APL paid the first Trigger Payment of $6.0 million in January 2013. As of ~~June~~September 30, 2013, the fair value

of the remaining Trigger Payment resulted in a $6.0 million long-term liability, which was recorded within other long-term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amounts APL could pay related to the remaining Trigger Payment is up to $6.0 million.

NOTE 11 – INCOME TAXES

In connection with the Cardinal Acquisition (see Note 3), APL acquired a taxable subsidiary in December 2012. The components of the federal and state income tax benefit for APL’s taxable subsidiary at ~~June~~September 30, 2013 are as follows (in thousands):

   Three Months Ended
June 30,
2013 Six Months Ended
June 30,
2013
Deferred benefit:

Federal
   $ (25 ) $ (33 )
State
   (3 ) (4 )


Total income tax benefit
   $ (28 ) $ (37 )

	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Deferred benefit:
Federal	$	(732	)	$	(765	)
State		(85	)		(89	)
Total income tax benefit	$	(817	)	$	(854	)

As of ~~June~~September 30, 2013 and December 31, 2012, APL had non-current net deferred income tax liabilities of ~~$35.5~~$34.7 million and $30.3 million, respectively. The components of net deferred tax liabilities as of ~~June~~September 30, 2013 and December 31, 2012 consist of the following (in thousands):

   June 30,
2013 December 31,
2012
Deferred tax assets:

Net operating loss tax carryforwards and alternative minimum tax credits
   $ 11,536    $ 10,277
Deferred tax liabilities:

Excess of asset carrying value over tax basis
   (47,049 ) (40,535 )


Net deferred tax liabilities
   $ (35,513 ) $ (30,258 )

	September 30, 2013			December 31, 2012
Deferred tax assets:
Net operating loss tax carryforwards and alternative minimum tax credits	$	12,732		$	10,277
Deferred tax liabilities:
Excess of asset carrying value over tax basis		(47,428	)		(40,535	)
Net deferred tax liabilities	$	(34,696	)	$	(30,258	)

As of ~~June~~September 30, 2013, APL had net operating loss carry forwards for federal income tax purposes of approximately ~~$29.6~~$32.8 million, which expire at various dates from 2029 to ~~2032.~~2033. APL believes it more likely than not that the deferred tax asset will be fully utilized. APL estimates approximately $280.3 million of goodwill recorded as a result of the TEAK Acquisition to be deductible for tax purposes.

NOTE 12 –— CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

Relationship between ARP and APL. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For ~~both~~the three ~~month periods~~months ended ~~June~~September 30, 2013 and 2012, $0.1 million and $0.2 million, respectively, of gathering fees paid by ARP to APL were eliminated in consolidation. For the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, $0.2 million and ~~$0.2~~$0.4 million, respectively, of gathering fees paid by ARP to APL ~~respectively,~~ were eliminated in consolidation.

In addition, in Lycoming County, Pennsylvania, APL has agreed to provide assistance in the design and construction management services for ARP with respect to a pipeline. The total estimated price for the project is under $2.5 ~~million.~~million, of which $1.6 million had been reimbursed to APL as of September 30, 2013.

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

NOTE 13 –— COMMITMENTS AND CONTINGENCIES

General Commitments

~~General Commitments~~

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by ARP, as managing general

partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of ~~June~~September 30, 2013, the management of ARP believes that any such liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the three months ended ~~June~~September 30, 2013 and 2012, ~~$2.1~~$2.2 million and ~~$1.4~~$1.8 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. For the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, ~~$4.3 million and $1.8~~$6.5 millionand $3.6 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

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

APL has certain long-term unconditional purchase obligations and commitments, primarily transportation contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts were ~~$3.1~~$7.2 million and ~~$2.5~~$2.6 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$6.1~~$24.8 million and ~~$5.0~~$7.6 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively. The future fixed and determinable portions of APL’s obligations as of ~~June~~September 30, 2013 were as follows: ~~2013 – $4.9~~2013—$2.8 million; ~~2014 – $9.5~~2014—$9.5 million; and ~~2015-2017 – $3.5~~2015-2017—$3.5 million per year.

As of ~~June~~September 30, 2013, ~~ARP~~the Partnership and ~~APL~~its subsidiaries are committed to expend approximately ~~$219.7~~$263.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

On August 3, 2011, CNX Gas Company LLC (“CNX”) filed a lawsuit in the United States District Court for the Eastern District of Tennessee at Knoxville styledCNX Gas Company LLC vs. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC, and Scott Boruff, No. 3:11-cv-00362. On April 16, 2012, Atlas Energy Tennessee, LLC, a subsidiary of the Partnership, was brought in to the lawsuit by way of Amended Complaint. On April 23, 2012, the Court dismissed Chevron Appalachia, LLC as a party on the grounds of lack of subject matter jurisdiction over that entity.

The lawsuit ~~alleges~~alleged that CNX entered into a Letter of Intent with Miller Energy Resources, Inc. (“Miller Energy”) for the purchase by CNX of certain leasehold interests containing oil and natural gas rights, representing around 30,000 acres in East Tennessee. The lawsuit also ~~alleges~~alleged that Miller Energy breached the Letter of Intent by refusing to close by the date provided and by allegedly entertaining offers from third parties for the same leasehold interests. Allegations of inducement of breach of contract and related claims ~~are~~were made by CNX against the remaining defendants, on the theory that these parties knew of the terms of the Letter of Intent and induced Miller Energy to breach the Letter of Intent. CNX iswas seeking $15.5 million in damages. The Partnership ~~asserts~~asserted that it acted in good faith and believes that the outcome of the litigation ~~will~~would be resolved in its favor.

In early September 2013, Atlas Energy Tennessee, LLC, was dismissed as a party on jurisdictional grounds.

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

NOTE 14 ~~– ISSUANCES~~–ISSUANCES OF UNITS

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

The Partnership

Purchase of ARP Preferred Units.

In July 2013, in connection with ARP’s EP Energy Acquisition (see Note 3), the Partnership purchased 3,746,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the

Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, the Partnership, as purchaser of the Class C preferred units, also received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

Atlas Resource Partners

Equity Offerings

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

~~Equity Offerings~~

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

In June 2013, in connection with ~~entering into a purchase agreement to acquire certain producing wells and net acreage from~~the EP Energy Acquisition (see Note ~~18)~~3), ARP sold an aggregate of 14,950,000 of its common limited partner units (including a 1,950,000 over-allotment) ~~of its~~

~~common limited partner units~~ in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 8).

In May 2013, ARP entered into an equity distribution program with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution program, ARP may sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act of 1933, as amended, including sales made directly on the New York Stock Exchange, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the ~~three and six~~nine months ended ~~June~~September 30, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of ~~$7.1~~$7.0 million, net of ~~$0.3~~$0.4 million in commissions paid. No common limited partner units were issued under the equity distribution program during the three months ended September, 30, 2013. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility.

In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate of 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its term loan credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million ARP common units and 3.8 million newly-created convertible ARP Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 3). The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.

ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the ARP common units issued on the acquisition closing date and those issuable upon conversion of the Class B preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012.

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 3). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s common and preferred units, the Partnership recorded gains of $25.2 ~~million and $48.4~~ million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated statements of partners’ capital during the ~~six~~nine months ended ~~June~~September 30, ~~2013 and 2012, respectively.~~2013.

ARP Common Unit Distribution

In February 2012, the board of directors of the Partnership’s general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see Note 1).

Atlas Pipeline Partners

Equity Offerings

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

In May 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction, at a negotiated price per unit of $29.75, resulting in net proceeds of $397.7 million pursuant to the Class D preferred unit purchase agreement dated April 16, 2013 (the “Commitment Date”). The Partnership, as general partner, contributed $8.2 million to maintain its 2.0% general partnership interest in APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see Note 3).

The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL has the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units at the end of eight full quarterly periods following their issuance. In the event of any liquidation, dissolution or winding up of APL or the sale or other disposition of all or substantially all of the assets of APL, the holders of the Class D Preferred Units are entitled to receive, out of the assets of APL available for distribution to unit holders, prior and in preference to any distribution of any assets of APL to the holders of any other existing or subsequently issued units, an amount equal to $29.75 per Class D Preferred Unit plus any unpaid preferred distributions.

The fair value of APL’s common units on the Commitment Date of the Class D Preferred Units was $36.52 per unit, resulting in an embedded beneficial conversion discount on the Class D Preferred Units of $91.0 million. The Partnership recognized the ~~intrinsic~~fair value of the Class D Preferred Units with the offsetting intrinsic discount within non-controlling ~~interests on~~interestson the Partnership’s consolidated balance sheet as of ~~June~~September 30, 2013. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL recorded ~~$6.7~~$11.4 million and $18.1 million, respectively, within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the beneficial conversion discount. APL’s Class D Preferred Units are presented combined with a net ~~$84.3~~$72.9 million unaccreted beneficial conversion discount within non-controlling interests on the Partnership’s consolidated balance sheet at ~~June~~September 30, 2013.

The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of the Partnership, as general partner. Cash distributions will be paid to the Class D Preferred Unit holders prior to any other distributions of available cash. Distributions will be determined based upon the cash distribution declared each quarter on APL’s common limited partner units plus a preferred yield premium. Class D Preferred Unit distributions, whether in kind units or in cash, will be accounted for as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL recorded costs related to preferred unit distributions of ~~$5.3~~$9.1 million and $14.4 million, respectively, within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. During the three and nine months ended September 30, 2013, APL distributed 138,598 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution for the quarter ended June 30, 2013.

Upon the issuance of the Class D Preferred Units, APL entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. APL agreed to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion.

APL has an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL may offer and sell from time to time through Citigroup, as its sales agent, common units having an aggregate value of up to $150.0 million. Sales of common limited partner units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act of 1933, as amended, including sales made directly on the New York Stock Exchange, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. APL

will pay Citigroup a commission, which in each case shall not be more than 2.0% of the gross sales price of common limited partner units sold. During the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL issued ~~642,495~~1,722,800 and ~~1,090,280~~2,863,080 common units, respectively, under the equity distribution program for net proceeds of ~~$24.5~~$63.7 million and ~~$38.9~~$102.7 million, net of ~~$0.5~~$1.3 million and ~~$0.8~~$2.1 million, respectively, in commission incurred from Citigroup. APL also received capital contributions from the Partnership of ~~$0.5~~$1.3 million and ~~$0.8~~$2.1 million during the three and ~~six~~nine months ended ~~June~~September 30, 2013, respectively, to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the ~~sale to repay borrowings outstanding under its revolving credit facility.~~common unit offering for general partnership purposes.

In connection with the issuance of APL’s common units during the ~~six~~nine months ended ~~June~~September 30, 2013, the Partnership recorded ~~a $9.9~~an $11.5 million gain within partner’s capital and a corresponding decrease in non-controlling interests on its consolidated statement of partners’ capital during the ~~six~~nine months ended ~~June~~September 30, 2013. ~~No gain was recorded during the six months ended June 30, 2012.~~

In December 2012, APL completed the sale of 10,507,033 APL common units in a public offering at an offering price of $31.00 per unit and received net proceeds of $319.3 million, including $6.7 million contributed by the Partnership to maintain its 2.0% general partner interest in APL. APL used the net proceeds from this offering to fund a portion of the Cardinal Acquisition. In connection with the issuance of APL common units, the Partnership recorded a $7.9 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet at December 31, 2012. In November 2012, APL entered into an agreement to issue $200.0 million of newly created Class D convertible preferred units in a private placement in order to finance a portion of the Cardinal Acquisition. Under the terms of the agreement, the private placement of the Class D convertible preferred units was nullified upon APL’s issuance of common units in excess of $150.0 million prior to the closing date of the Cardinal Acquisition. As a result of APL’s December 2012 issuance of $319.3 million common units, the private placement agreement terminated without the issuance of the Class D preferred units, and APL paid a commitment fee equal to 2.0%, or $4.0 million.

NOTE 15 – CASH DISTRIBUTIONS

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, 2012 through ~~June~~September 30, 2013 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid
   For Quarter
Ended    Cash Distribution per
Common Limited
Partner Unit    Total Cash Distributions
Paid to Common
Limited Partners
May 18, 2012
   March 31, 2012    $ 0.25       $ 12,830
August 17, 2012
   June 30, 2012    $ 0.25       $ 12,831
November 19, 2012
   September 30, 2012    $ 0.27       $ 13,866
February 19, 2013
   December 31, 2012    $ 0.30       $ 15,410
May 20, 2013
   March 31, 2013    $ 0.31       $ 15,928

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partners
May 18, 2012	March 31, 2012	$	0.25	$	12,830
August 17, 2012	June 30, 2012	$	0.25	$	12,831
November 19, 2012	September 30, 2012	$	0.27	$	13,866
February 19, 2013	December 31, 2012	$	0.30	$	15,410

May 20, 2013	March 31, 2013	$	0.31	$	15,928
August 19, 2013	June 30, 2013	$	0.44	$	22,611

On ~~July~~October 24, 2013, the Partnership declared a cash distribution of ~~$0.44~~$0.46 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$22.6~~$23.6 million distribution will be paid on ~~August~~November 19, 2013 to unitholders of record at the close of business on ~~August~~November 6, 2013.

ARP Cash Distributions.ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.

Distributions declared by ARP from its formation through ~~June~~September 30, 2013 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid
   For Quarter Ended    Cash
Distribution
per Common
Limited
Partner Unit Total Cash
Distribution
to Common
Limited
Partners    Total Cash
Distribution
To Preferred
Limited
Partners    Total Cash
Distribution to the
General Partner
May 15, 2012
   March 31, 2012    $ 0.12 ⁽¹⁾ $ 3,144       $ —         $ 64
August 14, 2012
   June 30, 2012    $ 0.40    $ 12,891       $ —         $ 263
November 14, 2012
   September 30, 2012    $ 0.43    $ 15,510       $ 1,652       $ 350
February 14, 2013
   December 31, 2012    $ 0.48    $ 21,107       $ 1,841       $ 618
May 15, 2013
   March 31, 2013    $ 0.51    $ 22,428       $ 1,957       $ 946

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners		Total Cash Distribution to the General Partner
May 15, 2012	March 31, 2012	$	0.12	⁽¹⁾	$	3,144	$	—	$	64
August 14, 2012	June 30, 2012	$	0.40		$	12,891	$	—	$	263
November 14, 2012	September 30, 2012	$	0.43		$	15,510	$	1,652	$	350
February 14, 2013	December 31, 2012	$	0.48		$	21,107	$	1,841	$	618

May 15, 2013	March 31, 2013	$	0.51		$	22,428	$	1,957	$	946
August 14, 2013	June 30, 2013	$	0.54		$	32,097	$	2,072	$	1,884

⁽¹⁾	Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012.

On ~~July~~October 24, 2013, ARP declared a cash distribution of ~~$0.54~~$0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$36.1~~$40.0 million distribution, including ~~$1.9~~$2.4 million and $4.2 million to the Partnership, as general partner, and ~~$2.1 million to its~~ preferred limited partners, respectively, will be paid on ~~August~~November 14, 2013 to unitholders of record at the close of business on ~~August~~November 6, 2013.

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

Common unit and general partner distributions declared by APL for the period from January 1, 2012 through ~~June~~September 30, 2013 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
May 15, 2012
   March 31, 2012    $ 0.56       $ 30,030       $ 2,217
August 14, 2012
   June 30, 2012    $ 0.56       $ 30,085       $ 2,221
November 14, 2012
   September 30, 2012    $ 0.57       $ 30,641       $ 2,409
February 14, 2013
   December 31, 2012    $ 0.58       $ 37,442       $ 3,117
May 15, 2013
   March 31, 2013    $ 0.59       $ 45,382       $ 3,980

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
May 15, 2012	March 31, 2012	$	0.56	$	30,030	$	2,217
August 14, 2012	June 30, 2012	$	0.56	$	30,085	$	2,221
November 14, 2012	September 30, 2012	$	0.57	$	30,641	$	2,409
February 14, 2013	December 31, 2012	$	0.58	$	37,442	$	3,117

May 15, 2013	March 31, 2013	$	0.59	$	45,382	$	3,980
August 14, 2013	June 30, 2013	$	0.62	$	48,165	$	5,875

On ~~July 23,~~October 24, 2013, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$54.0~~$55.3 million distribution, including ~~$5.9~~$6.0 million to the Partnership as general partner, will be paid on ~~August~~November 14, 2013 to unitholders of record at the close of business on ~~August~~November 7, 2013. Based on this declaration, APL estimates that approximately 234,000 Class D Preferred Units will be distributed to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended September 30, 2013 (see Note 18).

NOTE 16 – 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 General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At ~~June~~September 30, 2013, the Partnership had ~~4,472,652~~4,554,036 phantom units and unit options outstanding under the 2010 LTIP, with ~~1,263,078~~1,167,646 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, following a change in control, 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.

In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;
•
accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s

common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

2010 Phantom Units.A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units granted under the 2010 LTIP will vest over a three or four year period from the date of grant. Of the phantom units outstanding under the 2010 LTIP at ~~June~~September 30, 2013, there are ~~443,367~~485,201 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at ~~June~~September 30, 2013 include DERs. During the three months ended ~~June~~September 30, 2013 and 2012, the Partnership paid ~~$0.6~~$0.9 million and $0.5 million, respectively, with respect to the 2010 LTIP DERs. During the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, the Partnership paid ~~$1.2~~$2.2 million and ~~$1.0~~$1.5 million, respectively, with respect to the 2010 LTIP DERs.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of period
   2,041,291    $ 20.91       2,051,706    $ 20.46
Granted
   10,000    48.99       17,650    34.23
Vested⁽¹⁾
   —      —         —      —
Forfeited
   (41,423 ) 20.88       (3,997 ) 17.47




Outstanding, end of period⁽²⁾
   2,009,868    $ 21.10       2,065,359    $ 20.58




Non-cash compensation expense recognized (in thousands)
   $ 2,615       $ 2,884

   Six Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of year
   2,044,227    $ 20.90       1,838,164    $ 22.11
Granted
   10,000    48.99       72,950    28.49
Vested⁽¹⁾
   (2,936 ) 17.47       (7,226 ) 20.67
Forfeited
   (41,423 ) 20.88       (3,997 ) 17.47
ARP anti-dilution adjustment⁽³⁾
   —      —         165,468    —




Outstanding, end of period⁽²⁾
   2,009,868    $ 21.10       2,065,359    $ 20.58




Non-cash compensation expense recognized (in thousands)
   $ 5,723       $ 5,886

	Three Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		2,009,868		$	21.10		2,065,359		$	20.58
Granted		102,000			50.38		60,130			31.71
Vested⁽¹⁾		(14,048	)		19.86		(1,693	)		27.28
Forfeited		—			—		(59,058	)		20.28
Outstanding, end of period⁽²⁾		2,097,820		$	22.54		2,064,738		$	20.92
Vested and not yet issued⁽⁴⁾		—			—		9,290		$	18.37

Non-cash compensation expense recognized (in thousands)				$	3,467				$	2,796

	Nine Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		2,044,227		$	20.90		1,838,164		$	22.11
Granted		112,000			50.26		133,080			29.95
Vested⁽¹⁾		(16,984	)		19.45		(8,919	)		21.93
Forfeited		(41,423	)		20.88		(63,055	)		20.10
ARP anti-dilution adjustment⁽³⁾		—			—		165,468			—
Outstanding, end of period⁽²⁾		2,097,820		$	22.54		2,064,738		$	20.92
Vested and not yet issued⁽⁴⁾		—			—		9,290		$	18.37

Non-cash compensation expense recognized (in thousands)				$	9,190				$	8,682

~~(1)~~

⁽¹⁾During the ~~six~~nine months ended ~~June~~ September 30, 2013 and 2012, the aggregate intrinsic values of phantom unit awards vested were $0.7 million and $0.3 million, respectively, and $0.8 million and $0.1 million ~~and $0.2 million, respectively. No phantom unit awards vested during~~for the three months ended ~~June~~September 30, 2013 and ~~2012.~~2012, respectively.

⁽²⁾	The aggregate intrinsic value of phantom unit awards outstanding at ~~June~~ September 30, 2013 was ~~$98.5~~$114.6 million.

⁽³⁾	The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units. ⁽⁴⁾The intrinsic value of phantom unit awards vested, but not yet issued at September 30, 2012 was $0.3 million. No phantom unit awards had vested but had not yet been issued.

At ~~June~~September 30, 2013, the Partnership had approximately ~~$18.4~~$20.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options.A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are ~~572,372~~595,253 unit options outstanding under the 2010 LTIP at ~~June~~September 30, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended ~~June~~September 30, 2013 and 2012. No cash was received from the exercise of options for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Unit
Options Weighted
Average
Exercise
Price    Number of
Unit
Options Weighted
Average
Exercise
Price
Outstanding, beginning of period
   2,502,099    $ 20.52       2,581,322    $ 20.45
Granted
   —      —         —      —
Exercised⁽¹⁾
   —      —         —      —
Forfeited
   (39,315 ) 20.92       (542 ) 17.47




Outstanding, end of period⁽²⁾⁽³⁾
   2,462,784    $ 20.51       2,580,780    $ 20.45




Options exercisable, end of period⁽⁴⁾
   3,398    $ 20.85       —      $ —




Non-cash compensation expense recognized (in thousands)
   $ 1,296       $ 1,573

   Six Months Ended June 30,
   2013    2012
   Number of
Unit
Options Weighted
Average
Exercise
Price    Number of
Unit
Options Weighted
Average
Exercise
Price
Outstanding, beginning of year
   2,504,703    $ 20.51       2,304,300    $ 22.12
Granted
   —      —         69,229    26.27
Exercised⁽¹⁾
   —      —         —      —
Forfeited
   (41,919 ) 20.88       (542 ) 17.47
ARP anti-dilution adjustment⁽⁵⁾
   —      —         207,793    —




Outstanding, end of period⁽²⁾⁽³⁾
   2,462,784    $ 20.51       2,580,780    $ 20.45




Options exercisable, end of period⁽⁴⁾
   3,398    $ 20.85       —      $ —




Non-cash compensation expense recognized (in thousands)
   $ 2,811       $ 3,134

	Three Months Ended September 30,
	2013					2012
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		2,462,784		$	20.51		2,580,780		$	20.45
Granted		—			—		8,480			37.26
Exercised⁽¹⁾		—			—		—			—
Forfeited		(6,568	)		17.39		(78,306	)		20.30
Outstanding, end of period⁽²⁾⁽³⁾		2,456,216		$	20.52		2,510,954		$	20.51
Options exercisable, end of period⁽⁴⁾		7,068		$	21.62		8,836		$	19.37

Non-cash compensation expense recognized (in thousands)				$	1,466				$	1,317

	Nine Months Ended September 30,
	2013					2012
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		2,504,703		$	20.51		2,304,300		$	22.12
Granted		—			—		77,438			27.52
Exercised⁽¹⁾		—			—		—			—
Forfeited		(48,487	)		20.32		(78,577	)		20.35
ARP anti-dilution adjustment⁽⁵⁾		—			—		207,793			—
Outstanding, end of period⁽²⁾⁽³⁾		2,456,216		$	20.52		2,510,954		$	20.51
Options exercisable, end of period⁽⁴⁾		7,068		$	21.62		8,836		$	19.37

Non-cash compensation expense recognized (in thousands)				$	4,278				$	4,451

~~(1)~~

⁽¹⁾No options were exercised during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

⁽²⁾	The weighted average remaining contractual life for outstanding options at ~~June~~ September 30, 2013 was ~~7.7~~7.5 years.

⁽³⁾	The options outstanding at ~~June~~ September 30, 2013 had an aggregate intrinsic value of ~~$70.1~~$83.8 million.

⁽⁴⁾

The weighted average remaining contractual life for exercisable options at ~~June~~ September 30, 2013 was ~~8.1~~7.8 years. The intrinsic ~~value~~values of exercisable options at ~~June~~September 30, 2013 ~~was~~and 2012 were $0.2 million and $0.1 million. ~~No options were exercisable at June 30, 2012.~~

⁽⁵⁾	The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

At ~~June~~September 30, 2013, the Partnership had approximately ~~$8.7~~$7.2 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Expected dividend yield
   —         —         —         3.7 %
Expected unit price volatility
   —         —         —         47.0 %
Risk-free interest rate
   —         —         —         1.4 %
Expected term (in years)
   —         —         —         6.88
Fair value of unit options granted
   —         —         —         $ 8.50

Three Months Ended
September 30,


Nine Months Ended
September 30,


2013


2012


2013


2012

Expected dividend yield

—



3.7
%


—



3.7
%
Expected unit price volatility

—



32.0
%


—



45.0
%
Risk-free interest rate

—



1.2
%


—



1.4
%
Expected term (in years)

—



6.63



—



6.84

Fair value of unit options granted

—


$
5.18



—


$
8.08

2006 Long-Term Incentive Plan

The Board of Directors approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At ~~June~~September 30, 2013, the Partnership had 1,177,031 phantom units and unit options outstanding under the 2006 LTIP, with 764,062 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

2006 Phantom Units.Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant. 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 ~~June~~September 30, 2013, ~~80,719~~85,798 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at ~~June~~September 30, 2013 include DERs. During the three months ended ~~June~~September 30, 2013 and 2012, respectively, the Partnership paid approximately ~~$75,000~~$104,000 and ~~$9,000~~$12,000 with respect to 2006 LTIP’s DERs. During the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively, the Partnership paid approximately ~~$148,000~~$252,000 and ~~$17,000~~$29,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units    Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of period
   250,036    $ 34.92       37,053       $ 15.42
Granted
   —      —         9,996       30.01
Vested⁽¹⁾⁽²⁾
   (11,944 ) 22.90       —         —
Forfeited
   (1,000 ) 36.45       —         —






Outstanding, end of period⁽³⁾⁽⁴⁾
   237,092    $ 35.52       47,049       $ 18.52






Non-cash compensation expense recognized (in thousands)
   $ 1,659          $ 111

											Three Months Ended September 30,
	Six Months Ended June 30,										2013				2012
	2013					2012					Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		50,759		$	21.02		32,641		$	15.99
Outstanding, beginning of period												237,092	$	35.52		47,049	$	18.52
Granted		204,777			37.92		17,684			28.27		—		—		—		—
Vested⁽¹⁾⁽²⁾		(17,444	)		21.40		(6,253	)		24.06
Vested⁽¹⁾⁽²⁾												—		—		—		—
Forfeited		(1,000	)		36.45		—			—		—		—		—		—
ARP anti-dilution adjustment⁽⁵⁾		—			—		2,977			—

Outstanding, end of period⁽³⁾⁽⁴⁾		237,092		$	35.52		47,049		$	18.52

Outstanding, end of period⁽³⁾⁽⁴⁾												237,092	$	35.52		47,049	$	18.52

Non-cash compensation expense recognized (in thousands)				$	2,806				$	278	Non-cash compensation expense recognized (in thousands)		$	1,424			$	215

	Nine Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		50,759		$	21.02		32,641		$	15.99
Granted		204,777			37.92		17,684			28.27
Vested⁽¹⁾⁽²⁾		(17,444	)		21.40		(6,253	)		24.06
Forfeited		(1,000	)		36.45		—			—
ARP anti-dilution adjustment⁽⁵⁾		—			—		2,977			—
Outstanding, end of period⁽³⁾⁽⁴⁾		237,092		$	35.52		47,049		$	18.52

Non-cash compensation expense recognized (in thousands)				$	4,230				$	493

~~(1)~~

~~The intrinsic value for phantom unit awards vested during the three months ended June 30, 2013 was $0.6 million.~~

⁽¹⁾	The intrinsic values for phantom unit awards vested during the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 were $0.8 million and $0.2 million, respectively. No phantom unit awards vested during the three months ended ~~June~~September 30, 2013 and 2012.

⁽²⁾

There were ~~624 and~~ 1,146 vested units during the ~~three and six~~nine months ended ~~June~~September 30, 2013 ~~respectively,~~ that were settled for approximately ~~$33,000 and~~ $52,000 ~~cash, respectively.~~cash. No units were settled in cash during the three ~~and six~~ months ended ~~June~~September 30, 2013 and 2012, and the nine months ended September 30, 2012.

⁽³⁾	The aggregate intrinsic value for phantom unit awards outstanding at ~~June~~September 30, 2013 was ~~$11.6~~$13.0 million.

⁽⁴⁾

There was ~~$0.9 million, $0.7~~$1.2 million and ~~$0.4~~$0.7 million recognized as liabilities on the Partnership’s consolidated balance sheets at ~~June~~September 30, 2013 and December 31, ~~2012 and June 30,~~ 2012, respectively, representing 41,677 ~~44,234~~ and ~~40,524~~44,234 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $27.93 ~~$23.25~~ and ~~$20.55~~$23.25 as of ~~June~~September 30, 2013 and December 31, 2012, ~~and June 30, 2012,~~ respectively.

⁽⁵⁾	The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units.

At ~~June~~September 30, 2013, the Partnership had approximately ~~$6.0~~$4.8 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options.The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. There are 2,500 unit options outstanding under the 2006 LTIP at ~~June~~September 30, 2013 that will vest within the following twelve months. For ~~both~~ the three and ~~six~~nine month periods ended ~~June~~September 30, 2012, the Partnership received cash of $0.1 million and $0.2 million, respectively, from the exercise of options. No cash was received from the exercise of options during the three and ~~six~~nine months ended ~~June~~September 30, 2013.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Unit
Options    Weighted
Average
Exercise
Price    Number of
Unit
Options Weighted
Average
Exercise
Price
Outstanding, beginning of period
   939,939       $ 20.94       966,499    $ 20.08
Granted
   —         —         —      —
Exercised⁽¹⁾
   —         —         (16,315 ) 2.98
Forfeited
   —         —         —      —






Outstanding, end of period⁽²⁾⁽³⁾
   939,939       $ 20.94       950,184    $ 20.37






Options exercisable, end of period⁽⁴⁾
   929,939       $ 20.75       950,184    $ 20.37






Non-cash compensation expense recognized (in thousands)
      $ 9       $ —

										Three Months Ended September 30,
	Six Months Ended June 30,									2013				2012
	2013				2012					Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		929,939	$	20.75		903,614		$	21.52
Outstanding, beginning of period											939,939	$	20.94		950,184		$	20.37
Granted		10,000		38.51		—			—		—		—		—			—
Exercised⁽¹⁾		—		—		(31,753	)		2.98		—		—		(20,245	)		2.98
Forfeited		—		—		—			—		—		—		—			—
ARP anti-dilution adjustment⁽⁵⁾		—		—		78,323			—

Outstanding, end of period⁽²⁾⁽³⁾		939,939	$	20.94		950,184		$	20.37		939,939	$	20.94		929,939		$	20.75


Options exercisable, end of period⁽⁴⁾		929,939	$	20.75		950,184		$	20.37		929,939	$	20.75		929,939		$	20.75


Non-cash compensation expense recognized (in thousands)			$	16				$	—	Non-cash compensation expense recognized (in thousands)		$	10				$	—

	Nine Months Ended September 30,
	2013				2012
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		929,939	$	20.75		903,614		$	21.52
Granted		10,000		38.51		—			—
Exercised⁽¹⁾		—		—		(51,998	)		2.98
Forfeited		—		—		—			—
ARP anti-dilution adjustment⁽⁵⁾		—		—		78,323			—
Outstanding, end of period⁽²⁾⁽³⁾		939,939	$	20.94		929,939		$	20.75
Options exercisable, end of period⁽⁴⁾		929,939	$	20.75		929,939		$	20.75

Non-cash compensation expense recognized (in thousands)			$	26				$	—

~~(1)~~

⁽¹⁾	The intrinsic value of options exercised during the three and ~~six~~nine months ended ~~June~~September 30, 2012 was ~~$0.5~~$0.6 million and ~~$0.9~~$1.5 million, respectively. No options were exercised during the three and ~~six~~nine months ended ~~June~~September 30, 2013.

⁽²⁾	The weighted average remaining contractual life for outstanding options at ~~June~~September 30, 2013 was ~~3.4~~3.2 years.

⁽³⁾	The aggregate intrinsic value of options outstanding at ~~June~~September 30, 2013 was approximately ~~$26.4~~$31.7 million.

⁽⁴⁾

The weighted average remaining contractual lives for exercisable options at ~~June~~September 30, 2013 and 2012 were ~~3.4~~3.1 years and ~~4.4~~4.1 years, respectively. The aggregate intrinsic values of options exercisable at ~~June~~September 30, 2013 and 2012 were ~~$26.3~~$31.5 million and ~~$9.6~~$12.8 million, respectively.

⁽⁵⁾	The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

At ~~June~~September 30, 2013, the Partnership had ~~$0.1 million~~approximately $49,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013 2012
Expected dividend yield
   —         —         3.2 % —
Expected unit price volatility
   —         —         30.0 % —
Risk-free interest rate
   —         —         0.7 % —
Expected term (in years)
   —         —         6.25    —
Fair value of unit options granted
   —         —         $ 7.54    —

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013			2012
Expected dividend yield		—		—		3.2	%		—
Expected unit price volatility		—		—		30.0	%		—
Risk-free interest rate		—		—		0.7	%		—
Expected term (in years)		—		—		6.25			—
Fair value of unit options granted		—		—	$	7.54			—

The transfer of assets to ARP on March 5, 2012 and the subsequent distribution of ARP common units on March 13, 2012 resulted in an adjustment to the Partnership’s 2010 and 2006 long-term incentive plans. Concurrent with the distribution of ARP common units, the number of phantom units, restricted units and options in the plans were increased in an amount equivalent to the percentage change in the Partnership’s publicly traded unit price from the closing price on March 13, 2012 to the opening price on March 14, 2012. In addition, the strike price of unit option awards was decreased by the same percentage change.

ARP Long-Term Incentive Plan

ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At ~~June~~September 30, 2013, ARP had ~~2,340,682~~2,338,500 phantom units, restricted units and unit options outstanding under the ARP LTIP, with ~~355,109~~350,668 phantom units, restricted units and unit options available for grant.

Upon a change in control, as defined in the ARP LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, following a change in control, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), ~~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.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

ARP Phantom Units.Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the next four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at ~~June~~September 30, 2013, ~~235,565~~279,387 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at ~~June~~September 30, 2013 include DERs. During the three and ~~six~~nine months ended ~~June~~September 30, 2013, ARP paid $0.5 million and ~~$1.0~~$1.5 million, respectively, with respect to the 2012 ARP LTIP’s DERs. During the three and ~~six~~nine months ended ~~June~~September 30, 2012, ARP paid approximately ~~$400~~$0.3 million with respect to DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units    Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of period
   1,025,261    $ 24.53       —         —
Granted
   8,540    24.09       810,476       24.69
Vested and issued⁽¹⁾
   (168,994 ) 24.69       —         —
Forfeited
   (18,875 ) 24.03       —         —






Outstanding, end of period⁽²⁾⁽³⁾
   845,932    $ 24.51       810,476       $ 24.69






Vested and not yet issued⁽⁴⁾
   32,750    $ 24.67       —         $ —






Non-cash compensation expense recognized (in thousands)
   $ 2,231          $ 1,740

   Six Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units    Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of year
   948,476    $ 24.76       —         $ —
Granted
   91,790    22.15       810,476       24.69
Vested and issued⁽¹⁾
   (171,459 ) 24.69       —         —
Forfeited
   (22,875 ) 24.23       —         —






Outstanding, end of period⁽²⁾⁽³⁾
   845,932    $ 24.51       810,476       $ 24.69






Vested and not yet issued⁽⁴⁾
   32,750    $ 24.67       —         $ —






Non-cash compensation expense recognized (in thousands)
   $ 5,284          $ 1,740

	Three Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		845,932		$	24.51		810,476		$	24.69
Granted		37,191			21.86		129,500			25.23
Vested and issued⁽¹⁾		(33,123	)		24.72		—			—
Forfeited		—			—		(1,000	)		24.67
Outstanding, end of period⁽²⁾⁽³⁾		850,000		$	24.38		938,976		$	24.76
Vested and not yet issued⁽⁴⁾		7,749		$	25.51		—		$	—

Non-cash compensation expense recognized (in thousands)				$	2,045				$	2,915

	Nine Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		948,476		$	24.76		—		$	—
Granted		128,981			22.07		939,976			24.76
Vested and issued⁽¹⁾		(204,582	)		24.70		—			—
Forfeited		(22,875	)		24.23		(1,000	)		24.67
Outstanding, end of period⁽²⁾⁽³⁾		850,000		$	24.38		938,976		$	24.76
Vested and not yet issued⁽⁴⁾		7,749		$	25.51		—			—

Non-cash compensation expense recognized (in thousands)				$	7,329				$	4,655

~~(1)~~

⁽¹⁾

The intrinsic value of phantom unit awards vested and issued during the three and ~~six~~nine months ended ~~June~~September 30, 2013 was ~~$4.1~~$0.7 million and ~~$4.2~~$4.9 million, respectively. No phantom unit awards vested and were issued during the three and ~~six~~nine months ended ~~June~~September 30, 2012.

⁽²⁾	The aggregate intrinsic value for phantom unit awards outstanding at ~~June~~September 30, 2013 was ~~$18.5~~$17.8 million.

⁽³⁾

There was approximately ~~$38,000,~~$40,000 and $31,000 ~~and $12,000~~ recognized as liabilities on the Partnership’s consolidated balance sheets at ~~June~~September 30, 2013 and December 31, 2012, ~~and June 30, 2012,~~ respectively, representing ~~6,748, 3,476~~7,939 and 3,476 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were ~~$25.93, $28.75~~$25.19 and $28.75 at ~~June~~September 30, 2013 and December 31, 2012, ~~and June 30, 2012,~~ respectively.

⁽⁴⁾	The intrinsic value of phantom unit awards vested, but not yet issued at ~~June~~September 30, 2013 was ~~$0.8~~$0.2 million. No phantom unit awards had vested, but had not yet been issued at ~~June~~September 30, 2012.

At ~~June~~September 30, 2013, ARP had approximately ~~$12.0~~$10.8 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.

ARP Unit Options.The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 372,000 unit options outstanding under the ARP LTIP at ~~June~~September 30, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Unit
Options Weighted
Average
Exercise
Price    Number of
Unit
Options    Weighted
Average
Exercise
Price
Outstanding, beginning of period
   1,513,500    $ 24.67       —         $ —
Granted
   500    25.35       1,499,500       24.67
Exercised⁽¹⁾
   —      —         —         —
Forfeited
   (19,250 ) 24.68       —         —






Outstanding, end of period⁽²⁾⁽³⁾
   1,494,750    $ 24.67       1,499,500       $ 24.67






Options exercisable, end of period⁽⁴⁾
   374,375    $ 24.67       —         $ —






Non-cash compensation expense recognized (in thousands)
   $ 771          $ 1,274

   Six Months Ended June 30,
   2013    2012
   Number of
Unit
Options Weighted
Average
Exercise
Price    Number of
Unit
Options    Weighted
Average
Exercise
Price
Outstanding, beginning of year
   1,515,500    $ 24.68       —         $ —
Granted
   2,500    22.88       1,499,500       24.67
Exercised⁽¹⁾
   —      —         —         —
Forfeited
   (23,250 ) 24.76       —         —






Outstanding, end of period⁽²⁾⁽³⁾
   1,494,750    $ 24.67       1,499,500       $ 24.67






Options exercisable, end of period⁽⁴⁾
   374,375    $ 24.67       —         $ —






Non-cash compensation expense recognized (in thousands)
   $ 1,965          $ 1,274

	Three Months Ended September 30,
	2013					2012
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		1,494,750		$	24.67		1,499,500		$	24.67
Granted		—			—		18,000			25.18
Exercised⁽¹⁾		—			—		—			—
Forfeited		(6,250	)		24.67		(2,000	)		24.67
Outstanding, end of period⁽²⁾⁽³⁾		1,488,500		$	24.67		1,515,500		$	24.68
Options exercisable, end of period⁽⁴⁾		371,375		$	24.67		—		$	—

Non-cash compensation expense recognized (in thousands)				$	915				$	1,927

	Nine Months Ended September 30,
	2013					2012
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		1,515,500		$	24.68		—		$	—
Granted		2,500			22.88		1,517,500			24.68
Exercised⁽¹⁾		—			—		—			—
Forfeited		(29,500	)		24.74		(2,000	)		24.67
Outstanding, end of period⁽²⁾⁽³⁾		1,488,500		$	24.67		1,515,500		$	24.68
Options exercisable, end of period⁽⁴⁾		371,375		$	24.67		—		$	—

Non-cash compensation expense recognized (in thousands)				$	2,880				$	3,201

⁽¹⁾	No options were exercised during the three and ~~six~~nine months ended ~~June~~ September 30, 2013 and 2012.

⁽²⁾	The weighted average remaining contractual life for outstanding options at ~~June~~ September 30, 2013 was ~~8.9~~8.6 years.

⁽³⁾	There was no aggregate intrinsic value of options outstanding at ~~June~~ September 30, 2013.

⁽⁴⁾	The weighted average remaining contractual life for exercisable options at ~~June~~ September 30, 2013 was ~~8.9~~8.6 years. There were no aggregate intrinsic values of options exercisable at ~~June~~September 30, 2013 and 2012. No options were exercisable at ~~June~~September 30, 2012.

At ~~June~~September 30, 2013, ARP had approximately ~~$3.9~~$3.5 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Expected dividend yield
   7.3 % 1.5 % 6.7 % 1.5 %
Expected unit price volatility
   44.0 % 47.0 % 44.0 % 47.0 %
Risk-free interest rate
   1.1 % 1.0 % 1.1 % 1.0 %
Expected term (in years)
   6.88    6.25    6.35    6.25
Fair value of unit options granted
   $ 4.91    $ 9.79    $ 4.86    $ 9.79

Three Months Ended
September 30,


Nine Months Ended
September 30,


2013


2012


2013


2012

Expected dividend yield

—



2.5
%


6.7
%


1.5
%
Expected unit price volatility

—



46.0
%


35.8
%


47.0
%
Risk-free interest rate

—



0.8
%


1.1
%


1.0
%
Expected term (in years)

—



6.25



6.35



6.25

Fair value of unit options granted

—


$
8.72


$
3.63


$
9.78

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by APL’s compensation committee (the “APL LTIP Committee”). Under the APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At ~~June~~September 30, 2013, APL had ~~909,012~~1,522,822 phantom units outstanding under the APL LTIPs, with ~~1,482,642~~809,720 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options, which have vested and have been exercised. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value. There were no unit options outstanding as of ~~June~~September 30, 2013.

APL Phantom Units.Through ~~June~~September 30, 2013, phantom units granted under the APL LTIPs generally had vesting periods of four years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of APL’s board automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at ~~June~~September 30, 2013, ~~301,226~~468,544 units will vest within the following twelve months.

All phantom units outstanding under the APL LTIPs at ~~June~~September 30, 2013 include DERs. The amounts paid with respect to APL LTIP DERs were ~~$0.6~~$1.0 million and $0.6 million for the three months ended ~~June~~September 30, 2013 and 2012,

respectively, and ~~$1.2~~$2.2 million and ~~$0.8~~$1.4 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet.

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

   Three Months Ended June 30,
   2013    2012
   Number of
Units Weighted
Average
Grant Date
Fair Value    Number of
Units Weighted
Average
Grant Date
Fair Value
Outstanding, beginning of period
   1,057,083    $ 33.22       390,567    $ 21.41
Granted
   36,971    38.10       693,952    34.97
Vested and issued⁽¹⁾
   (182,942 ) 32.65       (108,167 ) 11.35
Forfeited
   (2,100 ) 32.95       (3,950 ) 24.66




Outstanding, end of period⁽²⁾⁽³⁾
   909,012    $ 33.54       972,402    $ 32.19




Vested and not issued⁽⁴⁾
   39,347    $ 24.91       48,647    $ 24.12




Non-cash compensation expense recognized (in thousands)
   $ 3,436       $ 2,940

											Three Months Ended September 30,
	Six Months Ended June 30,										2013					2012
	2013					2012					Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		1,053,242		$	33.21		394,489		$	21.63
Outstanding, beginning of period												909,012		$	33.54		972,402		$	32.19
Granted		43,775			37.32		698,084			34.98		697,122			39.07		85,103			33.61
Vested and issued⁽¹⁾		(185,905	)		32.59		(116,221	)		13.32		(59,112	)		27.81		(45,587	)		23.75
Forfeited		(2,100	)		32.95		(3,950	)		24.66		(24,200	)		36.74		(51,000	)		29.83

Outstanding, end of period⁽²⁾⁽³⁾		909,012		$	33.54		972,402		$	32.19		1,522,822		$	36.24		960,918		$	32.84


Vested and not issued⁽⁴⁾		39,347		$	24.91		48,647		$	24.12		2,450		$	32.95		6,800		$	27.46


Non-cash compensation expense recognized (in thousands)				$	7,820				$	3,918	Non-cash compensation expense recognized (in thousands)			$	5,998				$	3,619

	Nine Months Ended September 30,
	2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		1,053,242		$	33.21		394,489		$	21.63
Granted		740,897			38.97		783,187			34.83
Vested and issued⁽¹⁾		(245,017	)		31.44		(161,808	)		16.26
Forfeited		(26,300	)		36.44		(54,950	)		29.46
Outstanding, end of period⁽²⁾⁽³⁾		1,522,822		$	36.24		960,918		$	32.84
Vested and not issued⁽⁴⁾		2,450		$	32.95		6,800		$	27.46

Non-cash compensation expense recognized (in thousands)				$	13,818				$	7,538

~~(1)~~

⁽¹⁾The intrinsic values for phantom unit awards vested and issued were ~~$6.6~~$2.2 million and ~~$3.2~~$1.4 million, respectively, during the three months ended ~~June~~September 30, 2013 and 2012 and ~~$6.7~~$8.9 million and ~~$3.5~~$4.9 million, respectively, during the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

⁽²⁾	There were ~~22,546,~~23,565 and 17,926 ~~and 17,852~~ outstanding phantom unit awards at ~~June~~September 30, 2013 and December 31, ~~2012 and June 30,~~ 2012, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

⁽³⁾	The aggregate intrinsic values for phantom unit awards outstanding at ~~June~~ September 30, 2013 and 2012 were ~~$34.7~~$59.1 million and ~~$30.3~~$32.8 million, respectively.

⁽⁴⁾	The aggregate intrinsic values for phantom unit awards vested but not issued at ~~June~~September 30, 2013 and 2012 ~~was $1.5~~were $0.1 million and ~~$1.5~~$0.2 million, respectively.

At ~~June~~September 30, 2013, APL had approximately ~~$17.2~~$37.5 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of ~~2.0~~2.2 years.

NOTE 17 –— OPERATING SEGMENT INFORMATION

The Partnership’s operations include three reportable operating segments (see Note 1). These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands):

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Atlas Resource:

Revenues
   $ 83,326    $ 37,045    $ 195,374    $ 108,146
Operating costs and expenses
   (62,125 ) (41,958 ) (150,751 ) (103,004 )
Depreciation, depletion and amortization expense
   (22,197 ) (10,822 ) (43,405 ) (19,930 )
Loss on asset sales and disposal
   (672 ) (16 ) (1,374 ) (7,021 )
Interest expense
   (4,508 ) (956 ) (11,397 ) (1,106 )


Segment loss
   $ (6,176 ) $ (16,707 ) $ (11,553 ) $ (22,915 )


Atlas Pipeline:

Revenues
   $ 560,467    $ 325,998    $ 970,419    $ 619,213
Operating costs and expenses
   (479,874 ) (220,165 ) (841,592 ) (477,360 )
Depreciation, depletion and amortization expense
   (46,383 ) (21,712 ) (76,841 ) (42,554 )
Loss on asset sales and disposal
   (1,519 ) —      (1,519 ) —
Interest expense
   (22,581 ) (9,269 ) (41,267 ) (17,977 )
Loss on early extinguishment of debt
   (19 ) —      (26,601 ) —


Segment income (loss)
   $ 10,091    $ 74,852    $ (17,401 ) $ 81,322


Corporate and other:

Revenues
   $ 2    $ —      $ 104    $ 307
Operating costs and expenses
   (8,664 ) (6,506 ) (17,356 ) (21,984 )
Interest expense
   (442 ) (69 ) (677 ) (302 )


Segment loss
   $ (9,104 ) $ (6,575 ) $ (17,929 ) $ (21,979 )


Reconciliation of segment income (loss) to net loss:

Segment income (loss):

Atlas Resource
   $ (6,176 ) $ (16,707 ) $ (11,553 ) $ (22,915 )
Atlas Pipeline
   10,091    74,852    (17,401 ) 81,322
Corporate and other
   (9,104 ) (6,575 ) (17,929 ) (21,979 )


Net income (loss)
   $ (5,189 ) $ 51,570    $ (46,883 ) $ 36,428


Capital expenditures:

Atlas Resource
   $ 71,565    $ 26,694    $ 130,052    $ 45,652
Atlas Pipeline
   107,193    65,221    215,709    146,388
Corporate and other
   —      —      —      —


Total capital expenditures
   $ 178,758    $ 91,915    $ 345,761    $ 192,040

					Three Months Ended September 30,						Nine Months Ended September 30,
	June 30, 2013		December 31, 2012		2013			2012			2013			2012
Atlas Resources:
Revenues					$	91,085		$	74,743		$	286,459		$	182,889
Operating costs and expenses						(77,717	)		(69,483	)		(228,468	)		(172,487	)
Depreciation, depletion and amortization expense						(41,656	)		(13,918	)		(85,061	)		(33,848	)
Gain (loss) on asset sales and disposal						(661	)		2			(2,035	)		(7,019	)
Interest expense						(10,748	)		(1,423	)		(22,145	)		(2,529	)
Segment loss					$	(39,697	)	$	(10,079	)	$	(51,250	)	$	(32,994	)

Balance sheet:
Goodwill:
Atlas Pipeline:
Revenues					$	555,988		$	279,292		$	1,526,407		$	898,505
Operating costs and expenses						(506,125	)		(252,795	)		(1,347,717	)		(730,155	)
Depreciation, depletion and amortization expense						(51,080	)		(23,161	)		(127,921	)		(65,715	)
Loss on asset sales and disposal						—			—			(1,519	)		—
Interest expense						(24,347	)		(9,692	)		(65,614	)		(27,669	)
Loss on early extinguishment of debt						—			—			(26,601	)		—
Segment income (loss)					$	(25,564	)	$	(6,356	)	$	(42,965	)	$	74,966

Corporate and other:
Revenues					$	2,916		$	738		$	3,020		$	1,045
Operating costs and expenses						(12,452	)		(5,565	)		(29,808	)		(27,549	)
Depreciation, depletion and amortization expense						(1,331	)		—			(1,331	)		—
Interest expense						(3,418	)		(130	)		(4,095	)		(432	)
Segment loss					$	(14,285	)	$	(4,957	)	$	(32,214	)	$	(26,936	)

Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	31,784	$	31,784	$	(39,697	)	$	(10,079	)	$	(51,250	)	$	(32,994	)
Atlas Pipeline		502,321		319,285		(25,564	)		(6,356	)		(42,965	)		74,966
Corporate and other		—		—		(14,285	)		(4,957	)		(32,214	)		(26,936	)
Net income (loss)					$	(79,546	)	$	(21,392	)	$	(126,429	)	$	15,036

	$	534,105	$	351,069


Total assets:
Capital expenditures:
Atlas Resource	$	1,624,895	$	1,498,952	$	73,944		$	27,727		$	203,996		$	73,379
Atlas Pipeline		4,304,174		3,065,638		112,152			96,024			327,861			242,412
Corporate and other		33,010		32,604		1,831			—			1,831			—

	$	5,962,079	$	4,597,194

Total capital expenditures					$	187,927		$	123,751		$	533,688		$	315,791

	September 30, 2013		December 31, 2012
Balance sheet:
Goodwill:
Atlas Resource	$	31,784	$	31,784
Atlas Pipeline		503,937		319,285
Corporate and other		—		—
	$	535,721	$	351,069
Total assets:
Atlas Resource	$	2,386,852	$	1,498,952
Atlas Pipeline		4,373,595		3,065,638
Corporate and other		124,644		32,604
	$	6,885,091	$	4,597,194

NOTE 18 – SUBSEQUENT EVENTS

~~Arkoma Acquisition.~~Arc Logistics Partners IPO. On ~~July 31,~~November 6, 2013, the Partnership completed the acquisition of the Arkoma assets from EP Energy, a wholly-owned subsidiary of EP Energy, LLC, and EPE Nominee Corp. Pursuant to the purchase and sale agreement with EP Energy, the Partnership acquired the Arkoma basin assets for approximately $64.5 million in cash, net of purchase price adjustments (the “Arkoma Acquisition”Arc Logistics Partners, LP (“ARCX”), ~~while ARP acquired certain assets from EP Energy for approximately $705.9 million~~a master limited partnership owned and controlled by Lightfoot, which is involved in ~~cash, net~~terminalling, storage, throughput and transloading of ~~purchase price adjustments (collectively~~crude oil and petroleum products, began trading publicly on the ~~“EP Energy Acquisition”). The EP Energy Acquisition had an effective date of May 1, 2013.~~

~~Secured Term Facility.~~On July 31, 2013, in connection with the Arkoma Acquisition, the Partnership received net proceeds of $237.6 million under a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). The Term Facility has a maturity date of July 31, 2019. BorrowingsNew York Stock Exchange under the Term Facility bear interest, at the Partnership’s election at either LIBOR plus an applicable margin of 5.50% per annum or the alternate base rate, as defined (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by the Partnership. The Partnership is required to repay principal at the rate of $0.6 million per quarter until the maturity date when the balance is due.

The Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Term Facility also contains a covenant that requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility) the same as those in the Partnership’s credit facility. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

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

~~Credit Facility.~~On July 31, 2013, in connection with the Arkoma Acquisition, the Partnership entered into an amended and restated credit agreement with a syndicate of banks that matures in July 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. The Partnership’s obligations under the amended credit facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility are guaranteed by its material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either LIBOR plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit agreement.

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 default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The credit agreement also contains covenants that (i) require the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 4.50 to 1.0 as of the last day of the quarter ending September 30, 2013; 4:00 to 1:00 as of the last day of each of the quarters ending on or before September 30, 2015; and 3:50 to 1:00 for the last day of each of the quarters thereafter, and (ii) require the Partnership to enter into swaps agreements with respect to the assets being acquired in Arkoma Acquisition.

~~Purchase of ARP Preferred Units.~~In connection with the closing of the EP Energy Acquisition on July 31, 2013, the Partnership purchased $86.6 million of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, which was the face value of the units. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution will be paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time prior to the date that is three years following the date of the issuance of the Class C preferred units. Unless previously converted, all Class C preferred units will convert into common units on the date that is three years following the date of the issuance of the Class C preferred units. Upon issuance of the Class C preferred units, the Partnership, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The Partnership was granted certain registration rights with respect to the common units underlying the Class C preferred units and the common units issuable upon exercise of the warrants (see “~~Issuance of Preferred Units~~”)ticker symbol “ARCX”.

~~Cash~~ Distribution.On ~~July~~October 24, 2013, the Partnership declared a cash distribution of ~~$0.44~~$0.46 per unit on its outstanding common units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$22.6~~$23.6 million distribution will be paid on ~~August~~November 19, 2013 to unitholders of record at the close of business on ~~August~~November 6, 2013.

Atlas ~~Resource~~

~~EP Energy Acquisition.~~On July 31, 2013, ARP completed the acquisition of assets from EP Energy for approximately $705.9 million in cash, net of purchase price adjustments. The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama. The EP Energy acquisition had an effective date of May 1, 2013.

~~Issuance of Preferred Units.~~ In connection with the closing of the EP Energy Acquisition on July 31, 2013, ARP issued $86.6 million of its newly created Class C convertible preferred units to the Partnership, at a negotiated price per unit of $23.10, which was the face value of the units. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4 (2) of the Securities Act.

~~Credit Facility Amendment.~~On July 31, 2013, in connection with the acquisition of assets from EP Energy, ARP entered into a second amended and restated credit agreement (“ARP Credit Agreement”), which included the following changes:Resources

~~extended the maturity date of the facility to July 31, 2018;~~

~~increased the borrowing base to $835.0 million and the maximum facility amount to $1.5 billion;~~

decreased the applicable margin on Eurodollar loans to between 1.75% and 2.75%, and the applicable margin on alternative base rate loans to between 0.75% and 1.75%, in each case depending upon the utilization of the borrowing base;

revised the ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (or, in the case of quarters ending on or before December 31, 2013, Annualized EBITDA) to be 4.50 to 1.0 as of the last day of the quarter ended September 13, 2013, 4.25 to 1.0 as of the last day of the quarters ended December 31, 2013 and March 31, 2014, and 4.00 to 1.0 as of the last day of each quarter thereafter;

~~removed the interest coverage covenant; and~~

~~added covenants requiring ARP to enter into natural gas derivative swaps agreements with respect to the assets acquired in the EP Energy acquisition.~~

~~Senior Notes.~~Distribution. On July 30, 2013, ARP issued $250.0 million of 9.25% Senior Notes due August 15, 2021 (“9.25% ARP Senior Notes”) in a private placement transaction at a discount of 99.297%, resulting in net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs. Interest will accrue from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date being February 15, 2014. At any time prior to August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.624%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2019, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

~~Cash Distribution.~~ ~~On July~~October 24, 2013, ARP declared a cash distribution of ~~$0.54~~$0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$36.1~~$40.0 million distribution, including ~~$1.9~~$2.4 million and $4.2 million to the Partnership, as general partner, and ~~$2.1 million to its~~ preferred limited partners, respectively, will be paid on ~~August~~November 14, 2013 to unitholders of record at the close of business on ~~August~~November 6, 2013.

Atlas Pipeline

~~Cash~~ Distribution. On ~~July 23,~~October 24, 2013, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended ~~June~~September 30, 2013. The ~~$54.0~~$55.3 million distribution, including ~~$5.9~~$6.0 million to the Partnership as general partner, will be paid on ~~August~~November 14, 2013 to unitholders of record at the close of business on ~~August~~November 7, 2013. Based on this declaration, APL estimates that approximately 234,000 Class D Preferred Units will be distributed to the holders of the Class D Preferred Units as a preferred unit distribution for the quarter ended September 30, 2013. The in kind distribution will be issued on November 14, 2013 to the preferred unitholders of record at the close of business on November 7, 2013 (see Note 14).

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, 2012. 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 master limited partnership, whose common units are listed on the New York Stock Exchange under the symbol “ATLS”.

At ~~June~~September 30, 2013, our operations primarily consisted of our ownership interests in the ~~following entities:~~following:

Atlas Resource Partners, L.P. (“~~ARP”~~Atlas Resources” or “ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At ~~June~~September 30, 2013, we owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate ~~33.1%~~36.9% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) in ARP;

Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the natural gas gathering, processing and treating services in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services throughout the southwestern region of the United States. At ~~June~~September 30, 2013, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate ~~6.3%~~6.2% common limited partner interest in APL; ~~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 ~~June~~September 30, 2013, we had an approximate 16% general partner interest and 12% limited partner interest in ~~Lightfoot.~~Lightfoot; and

Certain natural gas and oil producing assets located in the Arkoma Basin of eastern Oklahoma (see“Recent Developments”).

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

FINANCIAL PRESENTATION

Our consolidated financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at ~~June~~September 30, 2013, except for ARP and APL, which we control. Due to the structure of our ownership interests in ARP and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income attributable to non-controlling interests in our consolidated statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP and APL, adjusted for non-controlling interests in ARP and APL. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements.

SUBSEQUENT EVENTS

Arc Logistics Partners IPO. Lightfoot Capital Partners, LP (“Lightfoot”), a privately managed partnership, in which we own an approximate 12% interest as well as an approximate 16% interest in its general partner (an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board) owns and controls the general partner of Arc Logistics Partners, LP. On November 6, 2013, Arc Logistics Partners, LP (ARCX), a master limited partnership which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the New York Stock Exchange under the ticker symbol “ARCX”. ARCX’s cash flows are primarily fee-based under multi-year contracts, and their assets are located on the East Coast, Gulf Coast and Midwest regions of the U.S.

Distribution.On October 24, 2013, we declared a cash distribution of $0.46 per unit on our outstanding common units, representing the cash distribution for the quarter ended September 30, 2013. The $23.6 million distribution will be paid on November 19, 2013 to unitholders of record at the close of business on November 6, 2013.

Atlas Resources

Distribution.On October 24, 2013, ARP declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2013. The $40.0 million distribution, including $2.4 million and $4.2 million to us, as general partner, and preferred limited partners, respectively, will be paid on November 14, 2013 to unitholders of record at the close of business on November 6, 2013.

Atlas Pipeline

Distribution. On October 24, 2013, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2013. The $55.3 million distribution, including $6.0 million to us as general partner, will be paid on November 14, 2013 to unitholders of record at the close of business on November 7, 2013. Based on this declaration, APL estimates that approximately 234,000 Class D Preferred Units will be distributed to the holders of the Class D Preferred Units as a preferred unit distribution for the quarter ended September 30, 2013. The in kind distribution will be issued on November 14, 2013 to the preferred unitholders of record at the close of business on November 7, 2013 (see “Issuances of Units”).

RECENT DEVELOPMENTS

Arkoma Acquisition.On July 31, 2013, we completed the acquisition of certain natural gas and oil producing assets in the Arkoma ~~assets~~basin from EP Energy ~~a wholly-owned subsidiary of~~ E&P Company, L.P. (“EP ~~Energy, LLC, and EPE Nominee Corp.~~Energy”). Pursuant to the purchase and sale agreement with EP Energy, we acquired the Arkoma basin assets for approximately $64.5 million in cash, net of purchase price adjustments (the “Arkoma Acquisition”)~~, while ARP acquired certain assets~~. The Arkoma Acquisition was funded with a portion of the proceeds from ~~EP Energy for approximately $705.9 million in cash, net~~the issuance of ~~purchase price adjustments (collectively the “EP Energy Acquisition”~~our term loan facility (see “Term Loan Facility”). The ~~EP Energy~~Arkoma Acquisition had an effective date of May 1, 2013.

~~Secured~~ Term Loan Facility.On July 31, 2013, in connection with the Arkoma Acquisition, we received net proceeds of ~~$237.6~~$230.2 million under a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at our election at either LIBOR plus an applicable margin of 5.50% per annum or the alternate base rate, as defined (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest

periods selected by us. We are required to repay principal at the rate of $0.6 million per quarter until the maturity date when the balance is due.

The Term Facility contains customary covenants, similar to those in our credit facility, that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The Term Facility also contains a covenant that requires us to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility) the same as those in our credit facility. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

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

Credit Facility.On July 31, 2013, in connection with the Arkoma Acquisition, we entered into an amended and restated credit agreement with a syndicate of banks that matures in July 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. Our obligations under the ~~amended~~ credit facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under the credit facility are guaranteed by our material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. At our election, interest on borrowings under the credit agreement is determined by reference to either LIBOR plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by us for LIBOR loans. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit ~~agreement.~~facility.

The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that (i) require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than ~~4.50~~4.5 to 1.0 as of the last day of the quarter ending September 30, 2013; ~~4:00~~4.0 to ~~1:00~~1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and ~~3:50~~3.5 to ~~1:00~~1.0 for the last day of each of the quarters thereafter, and (ii) require us to enter into swaps agreements with respect to the assets ~~being~~ acquired in the Arkoma Acquisition.

Purchase of ARP Preferred Units.In July 2013, in connection with ~~the closing~~ARP’s acquisition of ~~the~~assets from EP Energy, ~~Acquisition on July 31, 2013,~~ we purchased ~~$86.6 million~~3,749,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10,

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

~~Cash Distribution.~~On July 24, 2013, we declared a cash distribution of $0.44 per unit on our outstanding common units, representing the cash distribution for the quarter ended June 30, 2013. The $22.6 million distribution will be paid on August 19, 2013 to unitholders of record at the close of business on August 6, 2013.

Atlas Pipeline

~~Atlas Resource~~Senior Note Exchange Offer.

~~EP Energy Acquisition.~~~~On July 31, 2013, ARP completed the acquisition of assets from EP Energy for approximately $705.9 million in cash, net of purchase price adjustments.~~ The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama. The EP Energy acquisition had an effective date of May 1, 2013.

~~Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a~~ registration statement APL filed with the SEC ~~to register~~for the ~~resale~~exchange offer for $500.0 million of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

~~Credit Facility Amendment.~~~~On July 31, 2013, in connection with the acquisition of assets from EP Energy, ARP entered into a second amended and restated credit agreement~~6.625% unsecured senior notes due October 2020 (“~~ARP Credit Agreement”), which included the following changes:~~

~~extended the maturity date of the facility to July 31, 2018;~~

~~increased the borrowing base to $835.0 million and the maximum facility amount to $1.5 billion;~~

~~removed the interest coverage covenant; and~~

~~added covenants requiring ARP to enter into natural gas derivative swaps agreements with respect to the assets acquired in the EP Energy acquisition.~~

~~Senior Notes.~~ ~~On July 30, 2013, ARP issued $250.0 million of 9.25% Senior Notes due August 15, 2021 (“9.25% ARP~~6.625 APL Senior Notes”) in ~~a private placement transaction at a discount~~satisfaction of ~~99.297%, resulting in net proceeds~~the registration requirements of ~~approximately $242.8 million, net of underwriting fees and other offering costs. Interest will accrue from July 30,~~the registration rights agreements was declared effective on September 17, 2013. APL commenced an exchange offer for the 6.625% APL Senior Notes on September 18, 2013 and ~~is payable semi-annually~~the exchange offer was consummated on ~~February 15 and August 15, with~~October 16, 2013. Pursuant to the ~~first interest payment date being February 15, 2014. At any time prior to August 15, 2017, ARP may redeem some or all~~terms of the ~~9.25% ARP~~registration rights agreement relating to the 6.625% APL Senior Notes, atbecause the exchange offer was not completed by the September 23, 2013 deadline for the 6.625% APL Senior Notes issued in September 2012, APL incurred a ~~redemption price of 104.624%. On or after August 15, 2018, ARP may redeem some or all~~0.25% additional interest penalty from September 23, 2013 through consummation of the ~~9.25% ARP Senior Notes at the redemption price~~exchange offer on October 16, 2013 (see “Issuance of ~~102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%~~Units”). In addition, at any time prior to August 15, 2019, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

~~Cash Distribution.~~ On July 24, 2013, ARP declared a cash distribution of $0.54 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2013. The $36.1 million distribution, including $1.9 million to the Partnership as general partner and $2.1 million to its preferred limited partners, will be paid on August 14, 2013 to unitholders of record at the close of business on August 6, 2013.

~~Atlas Pipeline~~

~~Cash Distribution.~~ On July 23, 2013, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2013. The $54.0 million distribution, including $5.9 million to the Partnership as general partner, will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013.

~~RECENT DEVELOPMENTS~~

~~Atlas Pipeline~~

Senior Note Offering.On May 10, 2013, APL issued $400.0 million of 4.75% unsecured senior notes due November 15, 2021 (“4.75% APL Senior Notes”) in a private placement transaction. The 4.75% APL Senior Notes were issued at par.APL received net proceeds of $391.5 million after underwriting commissions and other ~~transactions~~transaction costs. APL utilized the proceeds repay a portion of its outstanding indebtedness under its revolving credit agreement (see “Issuance of Units”).

TEAK Acquisition. On May 7, 2013, APL completed the acquisition of 100% of the equity interests held by TEAK Midstream, LLC (“TEAK”) for $1.0 billion in cash, subject to customary purchase price adjustments, less cash received (the “TEAK Acquisition”). The assets of these companies, which are referred to as the South TX assets, include the following gas gathering and processing facilities in Texas:

the Silver Oak I plant, which is a 200 MMCFD cryogenic processing facility;

a second 200 MMCFD cryogenic processing facility, the Silver Oak II plant, to be in service ~~the first~~thesecond quarter of 2014;

265 miles of primarily 20-24 inch gathering and residue lines;

approximately 275 miles of low pressure gathering lines;

a 75% interest in T2 LaSalle Gathering Company L.L.C., which owns a 62 mile 24 inch gathering line;

a 50% interest in T2 Eagle Ford Gathering Company L.L.C., which owns a 45 mile 16 inch gathering pipeline and is currently building a 71 mile 24 inch gathering line; and

a 50% interest in T2 EF Cogeneration Holdings L.L.C., which is building a cogeneration facility.

Amendment to Credit Facility. On April 19, 2013, APL entered into an amendment to its revolving credit agreement, which among other changes,

allowed the TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement;

did not require the joint venture interests acquired in the TEAK Acquisition to be guarantors;

permitted the payment of cash distributions, if any, on the Class Dconvertible preferred units (“Class D Preferred ~~Units~~Units”) so long as we have a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million; and

modified the definition of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been ~~adjusted; and~~adjusted.

Common Unit Offering. On April 18, 2013, APL sold 11,845,000 common units of APL in a registered public offering at a price to the public of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from us, as general partner, of $8.3 million to maintain our 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see “Issuance of Units”).

Preferred Unit Offering. On May 7, 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction, at a negotiated price per unit of $29.75, for net proceeds of $397.7 million. APL also received a capital contribution from us, as general partner, of $8.2 million to maintain our 2% general partnership interest in APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see “Issuance of Units”).

Cryogenic Processing Plant.On April 12, 2013, APL placed in service a new 200 MMcfd cryogenic processing plant, known as the Driver Plant in its WestTX system in the Permian Basin of Texas, increasing the WestTX system capacity to 455 MMcfd.

Senior Notes Redemptions. On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% APL Senior Notes including a $6.3 million premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) (see “Senior Notes”). On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% APL Senior Notes, excluding unamortized premium, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% APL Senior Notes Indenture”) (see “Senior Notes”). In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture. APL also ~~issued a notice to redeem~~redeemed all the 8.75% APL Senior Notes not purchased in connection with the tender offer (see “Senior Notes”).

Senior Notes Issuance. On February 11, 2013, APL issued $650.0 million of 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million and utilized the proceeds to redeem its outstanding 8.75% senior unsecured notes due on June 15, 2018 (“8.75% APL Senior Notes”) and repay a portion of its outstanding indebtedness under its revolving credit facility (see “Senior Notes”).

Acquisition of Gas Gathering Systems and Related Assets.On January 7, 2013, APL paid $6.0 million for the first of two contingent payments related to the acquisition of a gas gathering system and related assets in February 2012. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes were achieved on the acquired gathering system within specified periods of time. Sufficient volumes were achieved in December 2012 to meet the required volumes for the first contingent payment.

Atlas ~~Resource~~Resources

EP Energy Acquisition.On July 31, 2013, ARP completed its acquisition of assets from EP Energy for approximately $705.9 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). The purchase price was funded through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due August 15, 2021 (“9.25% ARP Senior Notes”), the issuance of 14,950,000 ARP common limited partner units, and the issuance of its newly created Class C convertible preferred units. The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013.

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

Upon issuance of the Class C preferred units and 562,497 warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

Credit Facility Amendment.On July 31, 2013, in connection with the acquisition of assets from EP Energy, ARP entered into a second amended and restated credit agreement (“see “Credit Facility”).

Senior Notes. On July 30, 2013, ARP issued $250.0 million of the 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs of $5.5 million. The net proceeds were used to partially fund the EP Acquisition. The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of September 30, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date being February 15, 2014. At any time prior to August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.624%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at 109.250%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes (see “Senior Notes”).

Inconnection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time periods, the 9.25% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable.

Common Unit Offering.In June 2013, in connection with ~~entering into a purchase agreement to acquire certain producing wells and net acreage from~~the EP Energy ~~(see “Subsequent Events”),~~Acquisition, ARP sold an aggregate of 14,950,000 ~~(including a 1,950,000 over-allotment)~~ of its common limited partner units (including a 1,950,000 over-allotment) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see “Credit Facilities”).

Equity Distribution Program. In May 2013, ARP entered into an equity distribution program with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution program, ARP may sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act of 1933, as amended, including sales made directly on the New York Stock

Exchange, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the ~~three and six~~nine months ended ~~June~~September 30, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of ~~$7.1~~$7.0 million, net of ~~$0.3~~$0.4 million in commissions paid. No common limited partner units were issued under the equity distribution program during the three months ended September 30, 2013. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit ~~facility.~~facility (see “Issuance of Units”).

Senior Notes.On January 23, 2013, ARP issued $275.0 million of 7.75% senior unsecured notes due January 15, 2021 (“7.75% ARP Senior Notes”) in a private placement transaction at par. ARP used the net proceeds of approximately ~~$267.8~~$267.7 million, net of underwriting fees and other offering costs of ~~$7.2~~$7.3 million, to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility (see “Credit Facilities”). ~~Under the terms of ARP’s revolving credit facility, the borrowing base was reduced by 15% of the 7.75% ARP Senior Notes to $368.8 million.~~ In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs ~~in January~~during the nine months ended September 30, 2013. ~~The indenture governing~~Interest on the 7.75% ARP Senior Notes ~~contains covenants, including limitations~~is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of ~~ARP’s ability~~the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to ~~incur certain liens, incur~~repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional ~~indebtedness; declare~~interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or ~~pay distributions if an event~~in part, at a redemption price of ~~default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets.~~103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019.

lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 7.75% ARP Senior Notes. If ARP ~~does not meet~~fails to comply with its obligations to register the ~~aforementioned deadline,~~7.75% ARP Senior Notes within the specified time periods, the 7.75% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that ARP causes the exchange offer to be ~~consummated.~~consummated or the shelf registration id declared effective, as applicable. On July 1, 2013, ARP filed ~~its~~a registration statement with the SEC ~~in satisfaction~~relating to the exchange offer for the 7.75% ARP Senior Notes.

The indentures governing the 7.75% and 9.25% ARP Senior Notes contains covenants, including limitations of ARP’s ability to incur certain ~~requirements~~liens, incur additional indebtedness; declare or pay distributions if an event of ~~the registration rights agreement.~~default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

~~Atlas Resources~~

Natural Gas. We and ARP ~~markets~~market the majority of ~~its~~our natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian ~~Basin and~~Basin—Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line; Mississippi ~~Lime, primarily the New York Mercantile Exchange (“NYMEX”) spot market price;~~Lime—Southern Star; Barnett Shale and Marble ~~Falls,~~Falls- primarily ~~the~~ Waha ~~spot market price;~~but with smaller amounts sold into a variety of north Texas outlets; Raton – ANR, Panhandle, and NGPL; Black Warrior Basin – Southern Natural; Arkoma – Enable; New Albany Shale and Antrim ~~Shale,~~Shale- primarily the Texas Gas Zone SL and Chicago Hub spot ~~market prices;~~markets; and Niobrara ~~formation,~~ formation—primarily the Cheyenne Hub spot ~~market price.~~market. We and ARP attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

We and ARP ~~does~~do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of its other operating areas, ARP occasionally commits a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

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

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low Btu content) to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as mentioned above and ~~ARP’s NGLs are~~is generally priced using the Mont Belvieu (TX) regional processing hub. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We and ARP ~~does~~do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

Atlas Resources’ Investment Partnerships.

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

•

~~Well construction and completion.~~~~For each well that is drilled by a Drilling Partnership, ARP receives a 15% to 18% mark-up on those costs incurred to drill and complete the well;~~

Well construction and completion.For each well that is drilled by a Drilling Partnership, ARP receives a 15% to 18% mark-up on those costs incurred to drill and complete the well;

•

~~Administration and oversight.~~For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well;

Administration and oversight.For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well;

•

~~Well services~~. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the wells; and

•

~~Gathering~~. Each royalty owner, Drilling Partnership and certain other working interest owners pay ARP a gathering fee, which in general is equivalent to the fees ARP remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from in Drilling Partnerships by approximately 3%.

Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by its proportionate interest in the wells; and

Gathering. Each royalty owner, Drilling Partnership and certain other working interest owners pay ARP a gathering fee, which in general is equivalent to the fees ARP remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from in Drilling Partnerships by approximately 3%.

Atlas ~~Pipeline~~Pipeline’s Gathering and Processing

APL’s principal revenue is generated from the gathering and sale of natural gas, NGLs 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, processes and treats, and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent 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 and treating 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

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

~~Atlas Resource~~

Natural Gas and Oil Production

The areas in which we and ARP ~~operates~~operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic natural gas prices. While we and ARP ~~anticipates~~anticipate continued high levels of exploration and production activities over the long-term in the areas in which ~~it operates,~~we operate, fluctuations in energy prices can greatly affect production rates and investments ~~by third parties~~ in the development of new natural gas, oil and NGL reserves.

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

~~Atlas Pipeline~~

Gathering and Processing

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

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

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile.At ~~June~~September 30, 2013, our consolidated gas and oil production revenues and expenses ~~consist solely~~consists of our and ARP’s gas and oil production activities. Currently, our natural gas production entails the production generated by our assets acquired in the Arkoma Acquisition, while ARP has focused its natural gas, crude oil and NGL production operations in various shale plays throughout the United States. ARP has certain agreements which restrict its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which will expire on February 17, 2014. Through ~~June~~September 30, 2013, we and ARP ~~has~~have established production positions in the following operating areas:

ourcoal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, where we established a position following our acquisition of certain assets from EP Energy during the three months ended September 30, 2013 (see “Recent Developments”);

ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which ARP established a position following its acquisitions of assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”), Titan Operating, LLC (“Titan”) and DTE Energy Company (NYSE: DTE; “DTE”) during 2012;

ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming, where ARP established a position following its acquisition of certain assets from EP Energy during the three months ended September 30, 2013 (see “Recent Developments”);

ARP’s Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region;

~~the~~ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area; and

ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone; the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; the Antrim Shale in Michigan, where ARP produces out of the biogenic region of the shale similar to the New Albany Shale; and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

The following table presents the number of wells ARP drilled, both gross and for its interest, and the number of gross wells it turned in line during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Gross wells drilled:

Appalachia
   —         5       —         14
Barnett/Marble Falls
   17       —         31       —
Mississippi Lime/Hunton
   8       2       13       2
Niobrara
   —         —         —         51








Total
   25       7       44       67








Our share of gross wells drilled⁽¹⁾:

Appalachia
   —         2       —         4
Barnett/Marble Falls
   13       —         26       —
Mississippi Lime/Hunton
   2       1       6       1
Niobrara
   —         —         —         15








Total
   15       3       32       20








Gross wells turned in line:

Appalachia
   —         10       1       28
Barnett/Marble Falls
   10       —         37       —
Mississippi Lime/Hunton
   9       —         10       —
Chattanooga
   —         2       —         5
Niobrara
   —         23       —         72








Total
   19       35       48       105

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012

ARP gross wells drilled:		31		19		75		86
ARP’s share of gross wells drilled⁽¹⁾:		17		10		49		30
ARP gross wells turned in line:		35		44		83		149

(1)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.

Production Volumes. The following table presents ~~ARP’s~~ total net natural gas, crude oil, and NGL production volumes and production per day for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Production:⁽¹⁾⁽²⁾

Appalachia:⁽³⁾

Natural gas (MMcf)
   2,795       3,029       5,636       5,756
Oil (000’s Bbls)
   26       25       51       51
Natural gas liquids (000’s Bbls)
   —         1       —         4








Total (MMcfe)
   2,950       3,185       5,942       6,084








Barnett/Marble Falls:

Natural gas (MMcf)
   6,043       1,775       11,989       1,775
Oil (000’s Bbls)
   78       —         149       —
Natural gas liquids (000’s Bbls)
   250       3       480       3








Total (MMcfe)
   8,014       1,793       15,763       1,793








Mississippi Lime/Hunton:

Natural gas (MMcf)
   362       —         790       —
Oil (000’s Bbls)
   10       —         13       —
Natural gas liquids (000’s Bbls)
   22       —         44       —








Total (MMcfe)
   559       —         1,134       —








Other Operating Areas:⁽³⁾

Natural gas (MMcf)
   413       476       850       940
Oil (000’s Bbls)
   2       1       3       3
Natural gas liquids (000’s Bbls)
   36       38       71       74








Total (MMcfe)
   638       714       1,296       1,402








Total:

Natural gas (MMcf)
   9,613       5,280       19,266       8,470
Oil (000’s Bbls)
   117       26       216       54
Natural gas liquids (000’s Bbls)
   308       42       596       81








Total (MMcfe)
   12,161       5,691       24,135       9,278

Production per day:⁽¹⁾⁽²⁾

Appalachia:⁽³⁾

Natural gas (Mcfd)
   30,715       33,290       31,139       31,625
Oil (Bpd)
   283       274       280       281
Natural gas liquids (Bpd)
   2       10       2       20








Total (Mcfed)
   32,421       34,995       32,830       33,429








Barnett/Marble Falls:

Natural gas (Mcfd)
   66,407       19,506       66,239       9,753
Oil (Bpd)
   863       —         821       —
Natural gas liquids (Bpd)
   2,748       32       2,653       16








Total (Mcfed)
   88,070       19,699       87,086       9,849








Mississippi Lime/Hunton:

Natural gas (Mcfd)
   3,978       —         4,365       —
Oil (Bpd)
   115       —         72       —
Natural gas liquids (Bpd)
   245       —         244       —








Total (Mcfed)
   6,138       —         6,265       —








Other Operating Areas:⁽³⁾

Natural gas (Mcfd)
   4,538       5,226       4,699       5,163
Oil (Bpd)
   20       16       17       17
Natural gas liquids (Bpd)
   392       421       393       407








Total (Mcfed)
   7,012       7,847       7,161       7,703








Total:

Natural gas (Mcfd)
   105,638       58,022       106,442       46,541
Oil (Bpd)
   1,281       290       1,191       297
Natural gas liquids (Bpd)
   3,386       463       3,292       443








Total (Mcfed)
   133,641       62,541       133,341       50,981

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Production:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (MMcf)		759		—		759		—
Oil (000’s Bbls)		—		—		—		—
Natural gas liquids (000’s Bbls)		—		—		—		—
Total (MMcfe)		759		—		759		—
Atlas Resources:
Natural gas (MMcf)		17,574		8,115		36,840		16,586
Oil (000’s Bbls)		140		25		355		80
Natural gas liquids (000’s Bbls)		344		98		939		179
Total (MMcfe)		20,473		8,857		44,607		18,136
Total production:
Natural gas (MMcf)		18,333		8,115		37,599		16,586
Oil (000’s Bbls)		140		25		355		80
Natural gas liquids (000’s Bbls)		344		98		939		179
Total (MMcfe)		21,232		8,857		45,366		18,136

Production per day:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (Mcfd)		8,250		—		2,780		—
Oil (Bpd)		—		—		—		—
Natural gas liquids (Bpd)		—		—		—		—
Total (Mcfed)		8,250		—		2,780		—
Atlas Resources:
Natural gas (Mcfd)		191,020		88,208		134,945		60,531
Oil (Bpd)		1,517		277		1,301		291
Natural gas liquids (Bpd)		3,734		1,067		3,441		652
Total (Mcfed)		222,529		96,275		163,397		66,189
Total production per day:
Natural gas (Mcfd)		199,270		88,208		137,725		60,531
Oil (Bpd)		1,517		277		1,301		291
Natural gas liquids (Bpd)		3,734		1,067		3,441		652

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Total (Mcfed)		230,779		96,275		166,178		66,189

⁽¹⁾

Production quantities consist of the sum of (i) ~~ARP’s~~the proportionate share of production from wells in which ~~ARP’s has~~we and ARP have a direct interest, based on ~~its~~the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

⁽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. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

⁽³⁾	Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia. Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

Production Revenues, Prices and Costs. ~~ARP’s production~~Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 79% of ~~ARP’s~~ proved reserves on an energy equivalent basis at December 31, 2012. The following table presents ~~ARP’s~~ production revenues and average sales prices for ~~its~~our and ARP’s natural gas, oil, and natural gas liquids production for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, along with ~~ARP’s~~ average production costs, taxes, and transportation and compression costs in each of the reported periods:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Production revenues (in thousands):

Appalachia:⁽¹⁾

Natural gas revenue
   $ 8,039       $ 9,133       $ 16,313       $ 20,102
Oil revenue
   2,293       2,460       4,471       5,092
Natural gas liquids revenue
   6       64       13       216








Total revenues
   $ 10,338       $ 11,657       $ 20,797       $ 25,410








Barnett/Marble Falls:

Natural gas revenue
   $ 17,228       $ 3,940       $ 34,680       $ 3,940
Oil revenue
   7,178       2       13,457       2
Natural gas liquids revenue
   6,354       147       12,615       147








Total revenues
   $ 30,760       $ 4,089       $ 60,752       $ 4,089








Mississippi Lime/Hunton:

Natural gas revenue
   $ 1,357       $ —         $ 3,097       $ —
Oil revenue
   966       —         1,206       —
Natural gas liquids revenue
   816       —         1,695       —








Total revenues
   $ 3,139       $ —         $ 5,998       $ —








Other Operating Areas:⁽²⁾

Natural gas revenue
   $ 1,759       $ 2,072       $ 3,349       $ 3,802
Oil revenue
   158       131       267       286
Natural gas liquids revenue
   940       1,511       1,995       3,037








Total revenues
   $ 2,857       $ 3,714       $ 5,611       $ 7,125








Total:

Natural gas revenue
   $ 28,383       $ 15,145       $ 57,439       $ 27,844
Oil revenue
   10,595       2,593       19,401       5,380
Natural gas liquids revenue
   8,116       1,722       16,318       3,400








Total revenues
   $ 47,094       $ 19,460       $ 93,158       $ 36,624








Average sales price:

Natural gas (per Mcf):⁽³⁾

Total realized price, after hedge⁽⁴⁾
   $ 3.31       $ 3.49       $ 3.32       $ 3.81
Total realized price, before hedge⁽⁴⁾
   $ 3.47       $ 2.03       $ 3.18       $ 2.76
Oil (per Bbl):⁽³⁾

Total realized price, after hedge
   $ 90.90       $ 98.31       $ 89.97       $ 99.89
Total realized price, before hedge
   $ 92.33       $ 94.39       $ 91.63       $ 97.60
Natural gas liquids (per Bbl) total realized price:⁽³⁾
   $ 26.34       $ 40.85       $ 27.39       $ 42.22
Production costs (per Mcfe):⁽³⁾

Appalachia:⁽¹⁾

Lease operating expenses⁽⁵⁾
   $ 1.29       $ 0.89       $ 1.22       $ 1.01
Production taxes
   0.06       0.07       0.07       0.09
Transportation and compression
   0.53       0.31       0.49       0.32








   $ 1.88       $ 1.27       $ 1.78       $ 1.42








Barnett/Marble Falls:

Lease operating expenses
   $ 1.17       $ 0.41       $ 1.04       $ 0.41
Production taxes
   0.30       0.19       0.29       0.19
Transportation and compression
   0.15       0.30       0.10       0.30








   $ 1.62       $ 0.90       $ 1.43       $ 0.90








Mississippi Lime/Hunton:

Lease operating expenses
   $ 1.75       $ —         $ 1.52       $ —
Production taxes
   0.24       —         0.26       —
Transportation and compression
   —         —         —         —








   $ 1.99       $ —         $ 1.78       $ —








Other Operating Areas:⁽²⁾

Lease operating expenses
   $ 0.83       $ 0.63       $ 0.71       $ 0.67
Production taxes
   0.13       0.09       0.12       0.07
Transportation and compression
   0.18       0.16       0.18       0.16








   $ 1.14       $ 0.88       $ 1.01       $ 0.91








Total:

Lease operating expenses⁽⁵⁾
   $ 1.21       $ 0.71       $ 1.09       $ 0.84
Production taxes
   0.23       0.11       0.23       0.11
Transportation and compression
   0.24       0.29       0.20       0.29








   $ 1.68       $ 1.11       $ 1.51       $ 1.24

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Production revenues (in thousands):
Atlas Energy:
Natural gas revenue	$	2,700	$	—	$	2,700	$	—
Oil revenue		—		—		—		—
Natural gas liquids revenue		—		—		—		—
Total revenues	$	2,700	$	—	$	2,700	$	—
Atlas Resources:
Natural gas revenue	$	57,350	$	19,945	$	114,789	$	47,789
Oil revenue		12,993		2,239		32,394		7,619
Natural gas liquids revenue		9,989		2,515		26,307		5,915
Total revenues	$	80,332	$	24,699	$	173,490	$	61,323
Total production revenues:
Natural gas revenue	$	60,050	$	19,945	$	117,489	$	47,789
Oil revenue		12,993		2,239		32,394		7,619
Natural gas liquids revenue		9,989		2,515		26,307		5,915
Total revenues	$	83,032	$	24,699	$	176,190	$	61,323

Average sales price:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	3.46	$	3.01	$	3.39	$	3.42
Total realized price, before hedge⁽²⁾	$	3.21	$	2.46	$	3.20	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	93.07	$	87.86	$	91.19	$	95.70
Total realized price, before hedge	$	104.03	$	84.30	$	96.50	$	93.38

Natural gas liquids (per Bbl) total realized price:⁽¹⁾	$	29.08	$	25.61	$	28.01	$	33.09

Production costs (per Mcfe):⁽¹⁾
Atlas Energy:
Lease operating expenses	$	0.77	$	—	$	0.77	$	—
Production taxes		0.21		—		0.21		—
Transportation and compression		0.56		—		0.56		—
	$	1.54	$	—	$	1.54	$	—
Atlas Resources:
Lease operating expenses	$	1.15	$	0.75	$	1.12	$	0.80
Production taxes		0.11		0.13		0.17		0.12
Transportation and compression		0.24		0.25		0.22		0.27

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	$	1.50	$	1.13	$	1.51	$	1.19
Total production costs:
Lease operating expenses⁽³⁾	$	1.13	$	0.75	$	1.11	$	0.80
Production taxes		0.11		0.13		0.17		0.12
Transportation and compression		0.25		0.25		0.22		0.27
	$	1.50	$	1.13	$	1.51	$	1.19

⁽¹⁾	~~Appalachia includes ARP’s operations located in Pennsylvania, Ohio, New York and West Virginia.~~

⁽²⁾⁽¹⁾

~~Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.~~

⁽³⁾	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

⁽⁴⁾⁽²⁾

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was ~~$2.95~~$3.28 per Mcf ($~~3.10~~3.02 per Mcf before the effects of financial hedging) and ~~$2.87~~$2.46 per Mcf ($~~1.40~~1.91 per Mcf before the effects of financial hedging) for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$2.98~~$3.12 per Mcf ($~~2.85~~2.93 per Mcf before the effects of financial hedging) and ~~$3.29~~$2.88 per Mcf ($~~2.24~~2.07 per Mcf before the effects of financial hedging) for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively.

⁽⁵⁾⁽³⁾

Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.83 per Mcfe ($1.43 per Mcfe for total production costs) and $0.31 per Mcfe ($0.69 per Mcfe for total production costs) for the three months ended June 30, 2013 and 2012, respectively, and $0.84 per Mcfe ($1.40 per Mcfe for total production costs) and $0.58 per Mcfe ($1.00 per Mcfe for total production costs) for the six months ended June 30, 2013 and 2012, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were ~~$1.10~~$1.08 per Mcfe ($~~1.57~~1.44 per Mcfe for total production costs) and ~~$0.38~~$0.44 per Mcfe ($~~0.78~~0.82 per Mcfe for total production costs) for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and ~~$1.00~~$1.03 per Mcfe ($~~1.42~~1.43 per Mcfe for total production costs) and ~~$0.56~~$0.50 per Mcfe ($~~0.96~~0.90 per Mcfe for total production costs) for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, respectively.

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.Total natural gas revenues were ~~$28.4~~$60.1 million for the three months ended ~~June~~September 30, 2013, an increase of ~~$13.3~~$40.2 million from ~~$15.1~~$19.9 million for the three months ended ~~June~~September 30, 2012. This increase consisted primarily of a ~~$13.3~~$28.5 million increase attributable to natural gas revenue associated with our and ARP’s newly acquired coal-bed methane assets, an $8.5 million increase attributable to natural gas revenue associated with the ~~newly acquired~~ARP’s Barnett Shale/Marble Falls assets, ~~and~~ a ~~$1.4~~$2.0 million increase attributable to ~~the newly acquired~~ARP’s Mississippi Lime/Hunton assets, ~~partially offset by~~ a ~~$1.2~~$1.1 million decrease in ARP’s gas revenues subordinated to the investor partners within its Drilling Partnerships, and a $0.1 million increase attributable to ~~lower~~higher production volume on ARP’s legacy systems. Total oil revenues were ~~$10.6~~$13.0 million for the three months ended ~~June~~September 30, 2013, an increase of ~~$8.0~~$10.8 million from ~~$2.6~~$2.2 million for the comparable prior year period due principally to a ~~$7.2~~$7.4 million increase attributable to oil revenue associated with ~~the newly acquired~~ARP’s Barnett Shale/Marble Falls assets and a ~~$1.0~~$3.1 million increase attributable to oil revenue associated with ~~the newly acquired~~ARP’s Mississippi Lime/Hunton assets. Total natural gas liquids revenues were ~~$8.1~~$10.0 million for the three months ended ~~June~~September 30, 2013, an increase of ~~$6.4~~$7.5 million from ~~$1.7~~$2.5 million for the comparable prior year period. This increase was primarily attributable to ~~$6.2~~$5.7 million of NGL revenue associated with ~~the newly acquired~~ARP’s Barnett Shale/Marble Falls assets, and $1.6 million of NGL revenue attributable to ARP’s Mississippi Lime/Hunton assets.

~~Appalachia~~

Total production costs were ~~$4.2~~$30.6 million for the three months ended ~~June~~September 30, 2013, an increase of ~~$2.0~~$23.3 million from ~~$2.2~~$7.3 million for the three months ended ~~June~~September 30, 2012. This increase was due to ~~a $1.5~~an $11.9 million increase ~~in water hauling, transportation~~associated with our and ~~other costs and~~ARP’s current quarter acquisition of coal-bed methane assets, a ~~$0.5~~$9.3 million ~~decrease in ARP’s credit received against lease operating expenses pertaining to the subordination of ARP’s revenue within its Drilling Partnerships. Production costs~~increase associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, ~~were $14.1~~a $1.5 million ~~for~~decrease in ARP’s credit received against its lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships, and a $0.6 million increase in ARP’s Appalachia area transportation, labor and other production costs in comparison with the three months ended ~~June~~September 30, 2012.

Nine Months Ended September 30, 2013 ~~as compared to $1.6~~Compared with the Nine Months Ended September 30, 2012.Total natural gas revenues were $117.5 million for the ~~comparable prior year period. Production costs associated with ARP’s other operating areas were $0.7 million for the three~~nine months ended ~~June~~September 30, 2013, an increase of ~~$0.1~~$69.7 million from ~~$0.6~~$47.8 million for the ~~three~~nine months ended ~~June 30, 2012.~~

~~Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012.~~~~Total natural gas revenues were $57.4 million for the six months ended June 30, 2013, an increase of $29.6 million from $27.8 million for the six months ended June~~September 30, 2012. This increase consisted of a ~~$30.7~~$39.3 million increase attributable to natural gas revenue associated with ~~the newly acquired~~ARP’s Barnett Shale/Marble Falls assets, ~~and~~ a ~~$3.1~~$28.5 million increase attributable to ~~the~~natural gas revenue associated with our and ARP’s newly acquired coal-bed methane assets, and a $5.1 million increase attributable to ARP’s Mississippi Lime/Hunton assets, partially offset by ~~a $2.1 million increase in gas revenues subordinated to the investor partners within ARP’s Drilling Partnerships and~~ a $2.1 million decrease primarily attributable to lower realized natural gas prices for production volume on ARP’s legacy ~~systems.~~systems, and a $1.1 million increase in gas revenues subordinated to the investor partners within ARP’s Drilling Partnerships. Total oil revenues were ~~$19.4~~$32.4 million for the ~~six~~nine months ended ~~June~~September 30, 2013, an increase of ~~$14.0~~$24.8 million from ~~$5.4~~$7.6 million for the comparable prior year period due to a ~~$13.5~~$20.8 million increase attributable to oil revenue associated with ~~the newly acquired~~ARP’s Barnett Shale/Marble Falls assets and a ~~$1.2~~$4.3 million increase attributable to ~~the newly acquired~~ARP’s Mississippi Lime/Hunton assets, partially offset by a ~~$0.7~~$0.3 million decrease ~~primarily~~ attributable to lower realized prices on ARP’s legacy systems during the current year period. Total natural gas liquids revenues were ~~$16.3~~$26.3 million for the ~~six~~nine months ended ~~June~~September 30, 2013, an increase of ~~$12.9~~$20.4 million from ~~$3.4~~$5.9 million for the comparable prior year period. This increase was primarily attributable to ~~$12.5~~$18.1 million of NGL revenue associated with ~~the newly acquired~~ARP’s Barnett Shale/Marble Falls assets, and $3.3 million of NGL revenue attributable to the ARP’s Mississippi Lime/Hunton assets.

~~Appalachia~~

Total production costs were ~~$8.3~~$64.8 million for the ~~six~~nine months ended ~~June~~September 30, 2013, an increase of ~~$2.2~~$48.6 million from ~~$6.1~~$16.2 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This increase was due to a ~~$1.9~~$32.3 million increase in water hauling, transportation and other costs, and a $0.3 million decrease in ARP’s credit received against lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Production costs associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, ~~were $24.6~~an $11.9 million ~~for~~increase associated with our and ARP’s current quarter acquisition of coal-bed methane assets, a $2.5 million increase in ARP’s Appalachia area transportation, labor and other production costs, and a $1.8 million decrease in ARP’s credit received against its lease operating expenses pertaining to the ~~six~~subordination of its revenue within its Drilling Partnerships in comparison with the nine months ended June 30, 2013 as compared to $1.6 million for the comparable prior year period. Production costs associated with ARP’s other operating areas were $1.3 million for the six months ended June 30, 2013, comparable with the six months ended JuneSeptember 30, 2012.

Well Construction and Completion

Drilling Program Results. At ~~June~~September 30, 2013, our consolidated well construction and completion revenues and expenses consist solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its Drilling Partnerships during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012. There were no exploratory wells drilled during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Drilling partnership investor capital:

Raised
   $ 14,036       $ 3,000       $ 14,036       $ 3,000
Deployed
   $ 24,851       $ 12,241       $ 81,329       $ 55,960
Gross partnership wells drilled:

Appalachia
   —         5       —         14
Barnett/Marble Falls
   7       —         7       —
Mississippi Lime/Hunton
   8       2       9       2
Niobrara
   —         —         —         51








Total
   15       7       16       67








Net partnership wells drilled:

Appalachia
   —         5       —         14
Barnett/Marble Falls
   3       —         3       —
Mississippi Lime/Hunton
   8       1       9       1
Niobrara
   —         —         —         51








Total
   11       6       12       66

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Drilling partnership investor capital:
Raised	$	10,964	$	23,110	$	25,000	$	26,110
Deployed	$	10,964	$	36,317	$	92,293	$	92,277

Gross partnership wells drilled:
Appalachia		3		8		3		22
Barnett/Marble Falls		22		—		29		—
Mississippi Lime/Hunton		6		2		15		4
Niobrara		—		—		—		51
Total		31		10		47		77

Net partnership wells drilled:
Appalachia		3		8		3		22
Barnett/Marble Falls		11		—		14		—
Mississippi Lime/Hunton		6		2		15		3
Niobrara		—		—		—		51
Total		20		10		32		76

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Average construction and completion:

Revenue per well
   $ 2,681       $ 817       $ 4,595       $ 712
Cost per well
   2,331       708       3,996       615








Gross profit per well
   $ 350       $ 109       $ 599       $ 97








Gross profit margin
   $ 3,242       $ 1,635       $ 10,608       $ 7,659








Partnership net wells associated with revenue recognized⁽¹⁾:

Appalachia
   3       6       8       14
Barnett/Marble Falls
   2       —         2       —
Mississippi Lime/Hunton
   5       1       8       1
Chattanooga
   —         —         —         1
Niobrara
   —         8       —         63








Total
   10       15       18       79

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Average construction and completion:
Revenue per well	$	1,786	$	6,701	$	3,871	$	1,099
Cost per well		1,553		5,827		3,366		951
Gross profit per well	$	233	$	874	$	505	$	148

Gross profit margin	$	1,430	$	4,736	$	12,038	$	12,395

Partnership net wells associated with revenue recognized⁽¹⁾:
Appalachia		—		3		8		17
Barnett/Marble Falls		5		—		7		—

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Mississippi Lime/Hunton		1		2		9		3
Chattanooga		—		—		—		1
Niobrara		—		—		—		63
Total		6		5		24		84

(1)	Consists ~~of drilling partnership~~ofARP’s Drilling Partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012. Well construction and completion segment margin was ~~$3.2~~$1.4 million for the three months ended ~~June~~September 30, 2013, ~~an increase~~a decrease of ~~$1.6~~$3.3 million from ~~$1.6~~$4.7 million for three months ended ~~June~~September 30, 2012. This ~~increase~~decrease consisted of a ~~$2.2~~$3.5 million ~~increase~~decrease associated with ~~higher~~lower gross profit margin per well, partially offset by a ~~$0.6~~$0.2 million ~~decrease~~increase related to a ~~lower~~higher number of wells recognized for revenue within ARP’s Drilling Partnerships. Average revenue and cost per well ~~increased~~decreased between periods due primarily to higher capital deployed for Marble Falls and Mississippi Lime wells within ~~the~~ARP’s Drilling Partnerships during the three months ended ~~June~~September 30, 2013, compared with higher capital deployed for ~~Niobrara~~Marcellus Shale and Utica Shale wells, which typically have a much ~~lower~~higher cost per well as compared with ARP’s Marble Falls and Mississippi Lime wells, during the prior year period. Capital deployed during the three months ended September 30, 2013 decreased compared with the comparable prior year period due to the timing of funds raised during the period. As ARP’s drilling contracts with ~~the~~its Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in ARP’s average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012. Well construction and completion segment margin was ~~$10.6~~$12.0 million for the ~~six~~nine months ended ~~June~~September 30, 2013, ~~an increase~~a decrease of ~~$2.9~~$0.4 million from ~~$7.7~~$12.4 million for ~~six~~nine months ended ~~June~~September 30, 2012. This ~~increase~~decrease consisted of an ~~$8.8 million increase associated with higher gross profit margin per well, partially offset by a $5.9~~$8.9 million decrease related to a lower number of wells recognized for revenue within ARP’s Drilling ~~Partnerships.~~Partnerships, partially offset by an $8.5 million increase associated with higher gross profit margin per well. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Marcellus Shale, Utica Shale, and Mississippi Lime play wells within ~~the~~ARP’s Drilling Partnerships during the ~~six~~nine months ended ~~June~~September 30, 2013, compared with higher capital deployed for lower cost Niobrara Shale wells during the prior year period.

Administration and Oversight

At ~~June~~September 30, 2013, our consolidated administration and oversight revenues and expenses consist solely of ARP’s activities. Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP receives a lower administration and oversight fee related to shallow, vertical wells it drills within the Drilling Partnerships, such as those in the Marble Falls and Niobrara Shale, as compared to deep, horizontal wells, such as those drilled in the Marcellus and Utica Shales.

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012. Administration and oversight fee revenues were ~~$3.4~~$4.4 million for both of the three month periods ended September 30, 2013 and 2012.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012. Administration and oversight fee revenues were $8.9 million for the ~~three~~nine months ended ~~June~~September 30, 2013, an increase of ~~$2.1~~$0.3 million from ~~$1.3~~$8.6 million for the ~~three~~nine months ended ~~June~~September 30, 2012. This increase was due to ana current year period increase in the number of Mississippi Lime wells drilled, for which ARP received higher administration fees, and to wells drilled within the Marble Falls play during the current year ~~period in comparison to the prior year~~ period.

~~Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012~~. Administration and oversight fee revenues were $4.5 million for the three months ended June 30, 2013, an increase of $0.4 million from $4.1 million for the three months ended June 30, 2012. This increase was due to an increase in the number of Mississippi Lime wells drilled, for which ARP received higher administration fees, during the current year period in comparison to the prior year period.

Well Services

At ~~June~~September 30, 2013, our consolidated well services revenues and expenses consist solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012. Well services revenues were ~~$4.9~~$5.0 million for the three months ended ~~June 30, 2013, a decrease of $0.4 million from $5.3 million for the three months ended June 30, 2012. Well services expenses were $2.3 million for the three months ended June~~September 30, 2013, a decrease of $0.1 million from $5.1 million for the three months ended September 30, 2012. Well services expenses were $2.4 million for the three months ended ~~June~~September 30, 2013, an increase of $0.2 million from $2.2 million for the three months ended September 30, 2012. The decrease in well services revenue is primarily related to lower equipment rental revenue during the three months ended ~~June~~September 30, 2013 as compared with the comparable prior year period. The increase in well services expense is primarily related to higher well labor costs.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012. Well services revenues were ~~$9.7~~$14.7 million for the ~~six~~nine months ended ~~June~~September 30, 2013, a decrease of $0.6 million from ~~$10.3~~$15.3 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Well services expenses were ~~$4.6~~$7.0 million for the ~~six~~nine months ended ~~June~~September 30, 2013, a decrease of ~~$0.2~~$0.1 million from ~~$4.8~~$7.1 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease in well services revenue is primarily related to lower equipment rental revenue during the ~~six~~nine months ended ~~June~~September 30, 2013 as compared with the comparable prior year period. The decrease in well services expense is primarily related to lower well labor costs.

Gathering and Processing

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

   Three Months Ended
June 30, Six Months Ended
June 30,
Gathering and Processing:
   2013 2012 2013 2012
Atlas Resource:

Revenue
   $ 4,463    $ 2,863    $ 8,048    $ 6,177
Expense
   (4,882 ) (3,831 ) (9,224 ) (8,426 )


Gross Margin
   $ (419 ) $ (968 ) $ (1,176 ) $ (2,249 )


Atlas Pipeline:

Revenue
   $ 531,459    $ 253,557    $ 947,961    $ 555,384
Expense
   (448,986 ) (209,720 ) (796,385 ) (456,970 )


Gross Margin
   $ 82,473    $ 43,837    $ 151,576    $ 98,414


Total:

Revenue
   $ 535,922    $ 256,420    $ 956,009    $ 561,561
Expense
   (453,868 ) (213,551 ) (805,609 ) (465,396 )


Gross Margin
   $ 82,054    $ 42,869    $ 150,400    $ 96,165

	Three Months Ended September 30,						Nine Months Ended September 30,
Gathering and Processing:	2013			2012			2013			2012
Atlas Resources:
Revenue	$	3,591		$	4,134		$	11,639		$	10,311
Expense		(4,321	)		(4,402	)		(13,545	)		(12,828	)
Gross Margin	$	(730	)	$	(268	)	$	(1,906	)	$	(2,517	)

Atlas Pipeline:
Revenue	$	579,370		$	293,734		$	1,527,331		$	849,118
Expense		(488,370	)		(240,672	)		(1,284,755	)		(697,642	)
Gross Margin	$	91,000		$	53,062		$	242,576		$	151,476

Total:
Revenue	$	582,961		$	297,868		$	1,538,970		$	859,429
Expense		(492,691	)		(245,074	)		(1,298,300	)		(710,470	)
Gross Margin	$	90,270		$	52,794		$	240,670		$	148,959

The following table presents APL’s production volumes per day and average sales prices for its natural gas, oil, and natural gas liquids production for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Pricing:⁽¹⁾

Average sales price:

Natural gas sales ($/Mcf)
   $ 3.82       $ 2.01       $ 3.59       $ 2.26
NGL sales ($/gallon)
   $ 0.84       $ 0.80       $ 0.84       $ 0.92
Condensate sales ($/barrel)
   $ 89.15       $ 87.00       $ 88.09       $ 91.95
Volumes:⁽¹⁾

Gathered gas volume (Mcfd)
   1,432,818       772,661       1,371,537       737,816
Processed gas volume (Mcfd)
   1,253,158       681,036       1,203,953       656,875
Residue gas volume (Mcfd)
   1,090,703       562,242       1,052,202       537,270
NGL volume (Bpd)
   118,966       61,354       108,731       61,079
Condensate volume (Bpd)
   4,543       3,584       4,090       3,246

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Pricing:⁽¹⁾
Average sales price:
Natural gas sales ($/Mcf)	$	3.34	$	2.60	$	3.46	$	2.39
NGL sales ($/gallon)	$	0.92	$	0.87	$	0.87	$	0.90
Condensate sales ($/barrel)	$	101.48	$	86.65	$	92.82	$	90.07

Volumes:⁽¹⁾
Gathered gas volume (Mcfd)		1,484,071		860,026		1,412,616		780,426
Processed gas volume (Mcfd)		1,372,388		768,988		1,296,546		696,445
Residue gas volume (Mcfd)		1,160,608		658,846		1,091,665		579,771
NGL volume (Bpd)		120,126		56,363		113,292		59,557
Condensate volume (Bpd)		4,906		3,756		4,371		3,417

(1)	“Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.

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

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012. ARP’s net gathering and processing expense for the three months ended ~~June~~September 30, 2013 was ~~$0.5~~$0.7 million, ~~a decrease~~an increase of ~~$0.6~~$0.4 million compared with ~~$1.1~~$0.3 million for the three months ended ~~June~~September 30, 2012. This ~~favorable decrease~~unfavorable increase was principally due to lower gross margin recognized within ARP’s New Albany Shale-based processing plants and decreases in ARP’s ~~production volume and average realized natural gas price on production volume~~net revenues within the Appalachian Basin between the periods.

Gathering and processing margin for APL was ~~$82.4~~$91.0 million for the three months ended ~~June~~September 30, 2013 compared with ~~$43.8~~$53.1 million for the three months ended ~~June~~September 30, 2012. This increase was due principally to higher production volumes, including the new volumes from the Arkoma system due to the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”) and new volumes from the SouthTX system due to the TEAK ~~Acquisition, partially offset by lower commodity prices.~~Acquisition.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012. ARP’s net gathering and processing expense for the ~~six~~nine months ended ~~June~~September 30, 2013 was ~~$1.3~~$1.9 million, a decrease of ~~$1.1~~$0.6 million compared with ~~$2.4~~net expense of $2.5 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This favorable ~~decrease~~change was principally due to decreases in ARP’s production volume and average realized natural gas price on production volume within the Appalachian Basin between the ~~periods.~~periods, as well as lower gross margin recognized within our New Albany Shale-based processing plants.

Gathering and processing margin for APL was ~~$151.6~~$242.6 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared with ~~$98.4~~$151.5 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This increase was due principally to higher production volumes, including the new volumes from the Arkoma system due to the Cardinal Acquisition and new volumes from the SouthTX system due to the TEAK ~~Acquisition, partially offset by lower commodity prices.~~Acquisition.

Gain (Loss) on Mark-to-Market Derivatives

Gain (loss) on mark-to-market derivatives principally reflects the change in fair value of APL’s commodity derivatives that will settle in future periods, as APL does not apply hedge accounting to its derivatives. While APL utilizes either quoted market prices or observable market data to calculate the fair value of its natural gas and crude oil derivatives, valuations of APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of its NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for APL’s fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact our net income, though it would have no impact on our liquidity or capital resources. We recognized ~~gains~~losses of ~~$17.8~~$21.5 million and ~~$51.5~~$11.2 million for the three months ended ~~June~~September 30, 2013 and 2012, respectively, and a loss of $6.1 million and a gain of $33.2 million for the nine months ended September 30, 2013 and 2012, respectively for APL’s mark-to-market gain (loss) on derivatives valued upon unobservable inputs. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 3: Quantitative and Qualitative Disclosures About Market Risk”.

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.Gain (loss) on mark-to-market derivatives was ~~$27.1~~a loss of $24.5 million for the three months ended ~~June~~September 30, 2013 as compared with ~~$67.8~~a loss of $18.9 million for the three months ended ~~June~~September 30, 2012. This unfavorable movement was primarily due to a ~~$39.9~~$3.4 million unfavorable variance in derivative cash settlements and a $0.5 million unfavorable variance on the fair value revaluation of commodity derivative contracts in the current period compared to the prior year period.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012.Gain (loss) on mark-to-market derivatives was ~~$15.0~~a loss of $9.5 million for the ~~six~~nine months ended ~~June~~September 30, 2013 as compared with ~~$55.8~~a gain of $36.9 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This unfavorable movement was primarily due to a ~~$42.3~~$42.9 million unfavorable variance on the fair value revaluation of commodity derivative contracts in the current period compared to the prior year ~~period, due to the NGL forward curve prices falling more during the prior year~~ period.

Other, Net

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.Other, net for the three months ended ~~June~~September 30, 2013 was expense of $11.9 million compared with revenue of ~~$0.6~~$5.3 million ~~which~~for the three months ended September 31, 2012. This decrease was ~~comparable~~primarily due to the ~~prior~~$13.2 million of premium amortization associated with swaption derivative contracts for production volumes related to wells ARP acquired from EP Energy in the current year ~~period.~~period, a $3.3 million decrease in APL’s income from equity investments due to losses in the current period from the SouthTX equity method investments and $2.0 million of our swaption amortization related to production volumes on wells acquired from EP Energy in the current year period, partially offset by a $1.3 million increase in income from the equity investment in Lightfoot.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, ~~2012~~. 2012.Other, net for the ~~six~~nine months ended ~~June~~September 30, 2013 was ~~revenue~~expense of ~~$6.2~~$5.7 million as compared with ~~$3.3~~revenue of $8.6 million for the comparable prior year period. This ~~increase~~decrease was primarily due to the $14.5 million of premium amortization associated with swaption derivative contracts for production volumes related to wells ARP acquired from EP Energy in the current year period, $5.4 million increase in APL’s loss from equity investments due to a ~~$3.4~~loss in the current period from the SouthTX equity method investments and $2.3 million of our swaption amortization related to production volumes on wells acquired from EP Energy in the current year period, partially offset by a $5.0 million premium amortization associated with ARP’s swaption derivative contracts for production volumes related to wells acquired from Carrizo in the prior year period, a $1.1 million increase in income from the equity investment in Lightfoot and a $1.0 million settlement of APL’s business interruption ~~insurance, offset by a $1.2 million decrease in APL’s income from equity investments due to a loss in the current period from the SouthTX equity method investments.~~insurance.

OTHER COSTS AND EXPENSES

General and Administrative Expenses

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
General and Administrative expenses:

Atlas Energy
   $ 8,741       $ 6,624       $ 17,504       $ 22,185
Atlas Resource
   14,217       20,538       31,784       32,280
Atlas Pipeline
   30,916       10,445       45,244       20,390








Total
   $ 53,874       $ 37,607       $ 94,532       $ 74,855

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
General and Administrative expenses:
Atlas Energy	$	11,359	$	5,721	$	28,863	$	27,906
Atlas Resource		31,983		16,147		63,767		48,427
Atlas Pipeline		18,572		12,123		63,816		32,513
Total	$	61,914	$	33,991	$	156,446	$	108,846

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, ~~2012~~2012. Total general and administrative expenses increased to ~~$53.9~~$61.9 million for the three months ended ~~June~~September 30, 2013 compared with ~~$37.6~~$34.0 million for the three months ended ~~June~~September 30, 2012. Our ~~$8.7~~$11.4 million of general and administrative expenses for the three months ended ~~June~~September 30, 2013 represents a ~~$2.1~~$5.6 million increase from the comparable prior year period, which was primarily related to a ~~$1.2~~$4.5 million increase in non-recurring transaction costs and a ~~$1.0~~$2.0 million increase in non-cash compensation expense, partially offset by a ~~$0.1~~$0.9 million decrease in other corporate activities. ARP’s ~~$14.2~~$32.0 million of general and administrative expenses for the three months ended ~~June~~September 30, 2013 represents a ~~$6.3~~$15.8 million ~~decrease~~increase from the comparable period primarily due to a ~~$6.0~~$17.1 million ~~decrease~~increase in non-recurring transaction costs related to ARP’s acquisitions of assets in the current and prior year ~~period and~~periods, partially offset by a ~~$0.3 million~~ decrease in ~~salaries, wages and other corporate activities.~~non-cash compensation expense. APL’s ~~$30.9~~$18.6 million of general and administrative expense for the three months ended ~~June~~September 30, 2013 represents an increase of ~~$20.5~~$6.5 million from the comparable prior year period, which was principally due to ~~an $18.9~~a $4.2 million increase in costs related to APL’s acquisitions of Cardinal and TEAK and a ~~$0.5~~$2.3 million increase ofin non-cash compensation expense.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012.Total general and administrative expenses increased to ~~$94.5~~$156.4 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared with ~~$74.9~~$108.8 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Our ~~$17.5~~$28.9 million of general and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2013 represents a ~~$4.7~~$1.0 million ~~decrease~~increase from the comparable prior year period, which was primarily related to a ~~$5.2~~$4.1 million increase in non-cash compensation expense, partially offset by a $1.9 million decrease in non-recurring transaction costs and a ~~$1.6~~$1.2 million decrease in salaries, wages and other corporate ~~activities, partially offset by a $2.1 million increase in non-cash compensation expense.~~activities. ARP’s ~~$31.8~~$63.8 million of general and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2013 represents a ~~$0.5~~$15.3 million ~~decrease~~

increase from the comparable period primarily due to a ~~$4.7~~$12.4 million ~~decrease~~increase in non-recurring transaction costs related to ARP’s acquisitions, ~~of assets in the prior year period and~~ a ~~$0.4 million decrease in salaries, wages and other corporate activities, partially offset by a $4.2~~$2.3 million increase in non-cash compensation expense, ~~and~~ a $0.4 million ~~unfavorable movement related to a~~ decrease in net reimbursements received under ARP’s transition services agreement with Chevron Corporation, which expired during the first quarter of ~~2012.~~2012, and a $0.3 million decrease in salaries, wages and other corporate activities. APL’s ~~$45.2~~$63.8 million of general and administrative expense for the ~~six~~nine months ended ~~June~~September 30, 2013 represents an increase of ~~$24.9~~$31.3 million from the comparable prior year period, which was principally due to ~~an $18.9~~a $21.7 million increase in costs related to APL’s acquisitions of Cardinal and TEAK, a $6.3 million increase in non-cash compensation expense and a ~~$3.9~~$3.3 million increase in salaries and wages partially due to the increase in the number of ~~non-cash compensation expense.~~employees as a result of the Cardinal and TEAK Acquisitions.

Chevron Transaction Expense

During the three months ended September 30, 2012, we recognized a $7.7 million charge regarding ARP’s reconciliation process with Chevron related to certain amounts included within the contractual cash transaction adjustment, which was settled in October 2012 (see “Item 1: Financial Statements”).

Depreciation, Depletion and Amortization

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Depreciation, depletion and amortization:

Atlas Resource
   $ 22,197       $ 10,822       $ 43,405       $ 19,930
Atlas Pipeline
   46,383       21,712       76,841       42,554








Total
   $ 68,580       $ 32,534       $ 120,246       $ 62,484

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Depreciation, depletion and amortization:
Atlas Energy	$	1,331	$	—	$	1,331	$	—
Atlas Resource		41,656		13,918		85,061		33,848
Atlas Pipeline		51,080		23,161		127,921		65,715
Total	$	94,067	$	37,079	$	214,313	$	99,563

Total depreciation, depletion and amortization increased to ~~$68.6~~$94.1 million for the three months ended ~~June~~September 30, 2013 compared with ~~$32.5~~$37.1 million for the comparable prior year period, which was due to a ~~$11.1~~$28.6 million increase in our and ARP’s depletion expense resulting from the acquisitions itwe and ARP consummated during 2013 and 2012 and a ~~$25.0~~$27.9 million increase in depreciation expenses, primarily due to $13.0 million in additional expense related assets acquired in the TEAK Acquisition, $10.6 million in additional expense related to assets acquired in the Cardinal Acquisition and APL’s expansion capital expenditures incurred subsequent to ~~June~~September 30, 2012.

Total depreciation, depletion and amortization increased to ~~$120.2~~$214.3 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared with ~~$62.5~~$99.6 million for the comparable prior year period, which was due to a ~~$23.2~~$51.8 million increase in our and ARP’s depletion expense resulting from the acquisitions it consummated during 2013 and 2012 and a ~~$34.5~~$62.2 million increase in depreciation expenses, primarily due to $32.0 million in additional expense related to assets acquired in the Cardinal Acquisition, $17.4 million in additional expense related assets acquired in the TEAK Acquisition and APL’s expansion capital expenditures incurred subsequent to ~~June~~September 30, 2012.

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

   Three Months Ended
June 30, Six Months Ended
June 30,
   2013 2012 2013 2012
Depletion expense:

Total
   $ 20,580    $ 9,520    $ 40,276    $ 17,087
Depletion expense as a percentage of gas and oil production revenue
   44 % 49 % 43 % 47 %
Depletion per Mcfe
   $ 1.69    $ 1.67    $ 1.67    $ 1.84

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Depletion expense:
Total	$	41,224		$	12,576		$	81,500		$	29,663
Depletion expense as a percentage of gas and oil production revenue		50	%		51	%		46	%		48	%

Depletion per Mcfe	$	1.94		$	1.42		$	1.80		$	1.64

Depletion expense varies from period to period and is directly affected by changes in ~~ARP’s~~ gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of ~~ARP’s~~ gas and oil properties. For the three months

ended ~~June~~September 30, 2013, depletion expense was ~~$20.6~~$41.2 million, an increase of ~~$11.1~~$28.6 million compared with ~~$9.5~~$12.6 million for the three months ended ~~June~~September 30, 2012. ~~ARP’s depletion~~Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to ~~44%~~50% for the three months ended ~~June~~September 30, 2013, compared with ~~49%~~51% for the three months ended ~~June~~September 30, 2012, which was primarily due to an increase in ~~our~~ARP’s oil and natural gas liquids volumes as a result of ARP’s acquisitions in 2012. Depletion expense per Mcfe was $1.94 for the three months ended September 30, 2013, an increase of $0.52 per Mcfe from $1.42 for the three months ended September 30, 2012, which was primarily related to the increase in ARP’s oil and natural gas liquids production between the periods. Depletion expense increased between periods principally due to an overall increase in production volume.

Depletion expense was $81.5 million for the nine months ended September 30, 2013, an increase of $51.8 million compared with $29.7 million for the nine months ended September 30, 2012. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 46% for the nine months ended September 30, 2013, compared with 48% for the nine months ended September 30, 2012, which was primarily due to an increase in ARP’s oil and natural gas liquids volumes as a result of ARP’s acquisitions in 2012, partially offset by a decrease in realized natural gas prices between the periods. Depletion expense per Mcfe was ~~$1.69~~$1.80 for the ~~three~~nine months ended ~~June~~September 30, 2013, an increase of $0.16 per Mcfe from $1.64 per Mcfe for the nine months ended September 30, 2012, which was ~~consistent with~~primarily related to the ~~comparable prior year period.~~increase in ARP’s oil and natural gas liquids production between the periods. Depletion expense increased between periods principally due to an overall increase in production volume.

Depletion expense was $40.3 million for the six months ended June 30, 2013, an increase of $23.2 million compared with $17.1 million for the six months ended June 30, 2012. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 43% for the six months ended June 30, 2013, compared with 47% for the six months ended June 30, 2012, which was primarily due to an increase in our oil and natural gas liquids volumes as a result of ARP’s acquisitions in 2012, partially offset by a decrease in realized natural gas prices between the periods. Depletion expense per Mcfe was $1.67 for the six months ended June 30, 2013, a decrease of $0.17 per Mcfe from $1.84 per Mcfe for the six months ended June 30, 2012, which was primarily related to lower depletion expense per Mcfe for the assets acquired during 2012. Depletion expense increased between periods principally due to an overall increase in production volume.

~~Loss~~Gain (Loss) on Asset Sales and Disposals

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012. During the three months ended ~~June~~September 30, 2013 and 2012, ~~losses~~gain (loss) on asset sales and disposals were ~~$2.2~~losses of $0.7 million and gains of approximately ~~$16,000,~~$2,000, respectively. ARP recognized losses of $0.7 million loss on asset disposal for the three months ended ~~June~~September 30, 2013 pertained to management’s decision not to drill wells on leasehold property that expired in the New Albany and Chattanooga Shales during the period. ~~APL’s $1.5 million loss on asset sales and disposal primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired.~~

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012. During the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012, ~~losses~~gain (loss) on asset sales and disposals were ~~$2.9~~losses of $3.6 million and ~~approximately~~ $7.0 million, respectively. ARP recognized losses on asset sales and disposals of ~~$1.4~~$2.0 million and $7.0 million, respectively. The ~~$1.4~~$2.0 million loss on asset disposal for the ~~six~~nine months ended ~~June~~September 30, 2013 pertained to management’s decision not to drill wells on leasehold property that expired in the New Albany and Chattanooga Shales during the period. During the ~~six~~nine months ended ~~June~~September 30, 2012, ARP recognized a $7.0 million loss on asset sales and disposal related to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling milestones which needed to be met in order for ARP to maintain ownership of the South Knox processing plant. During 2012, ARP management decided not to continue progressing towards these milestones due to the current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book value of the assets during the ~~six~~nine months ended ~~June~~September 30, 2012. APL’s $1.5 million loss on asset sales and disposal primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired.

Interest Expense

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Interest Expense:

Atlas Energy
   $ 442       $ 69       $ 677       $ 302
Atlas Resource
   4,508       956       11,397       1,106
Atlas Pipeline
   22,581       9,269       41,267       17,977








Total
   $ 27,531       $ 10,294       $ 53,341       $ 19,385

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Interest Expense:
Atlas Energy	$	3,418	$	130	$	4,095	$	432
Atlas Resource		10,748		1,423		22,145		2,529
Atlas Pipeline		24,347		9,692		65,614		27,669
Total	$	38,513	$	11,245	$	91,854	$	30,630

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.Total interest expense increased to ~~$27.5~~$38.5 million for the three months ended ~~June~~September 30, 2013 as compared with ~~$10.3~~$11.2 million for the three months ended ~~June~~September 30, 2012. This ~~$17.2~~$27.3 million increase was due to ~~a $13.3~~our $3.3 million increase, ~~related to APL,~~ a ~~$3.5~~$9.3 million

increase related to ARP and a $14.7 million increase related to APL. The $3.3 million increase in our ~~$0.4~~interest expense consisted of $2.7 million ~~increase.~~associated with our term loan facility, a $0.5 million increase in the amortization of deferred financing costs primarily associated with our term loan facility, and a $0.1 million increase associated with our credit facility. The ~~$3.5~~$9.3 million increase in ARP’s interest expense consisted of a $5.3 million increase associated with ARP’s issuance of $275.0 million of 7.75% ARP Senior Notes in January 2013, $3.9 million associated with the issuance of $250.0 million of the 9.25% ARP Senior Notes, a ~~$0.7~~$2.3 million increase in the amortization of deferred financing costs, and a $0.4 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility, partially offset by interest that was capitalized on ARP’s ongoing capital projects. The increase in amortization associated with ARP’s deferred financing costs includes ~~$0.4~~$1.9 million associated with ARP’s amended credit facility, $0.2 million associated with ARP’s issuance of its 7.75% ARP Senior Notes, and $0.2 million associated with ARP’s issuance of its 9.25% ARP Senior Notes. The ~~$13.3~~$14.7 million increase in interest expense for APL was primarily due to $9.5 million in additional interest related to the 5.875% APL Senior Notes, ~~$8.1~~$7.9 million increase in interest expense associated with APL’s 6.625% senior unsecured notes due 2020 (“6.625% APL Senior Notes”), and ~~$2.6~~$4.8 million additional interest related to the 4.75% APL Senior Notes, partially offset by $7.8 million reduced interest on the APL 8.75% Senior Notes. The increase in the interest on ~~the 6.625% APL Senior Notes,~~ the 5.875% APL Senior Notes and the 4.75% APL Senior Notes is due to their issuance after ~~June~~September 30, 2012. The increase in the interest on the 6.625% APL Senior Notes is due to an additional issuance of $175.0 million after September 30, 2012. The decrease in the interest for the 8.75% APL Senior Notes is due to their redemption prior to the three months ended ~~June~~September 30, 2013 (see “APL Senior Notes”).

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012.Total interest expense increased to ~~$53.3~~$91.9 million for the ~~six~~nine months ended ~~June~~September 30, 2013 as compared with ~~$19.4~~$30.6 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This ~~$34.0~~$61.3 million increase was due to ~~a $23.3~~our $3.7 million increase, ~~related to APL,~~ a ~~$10.3~~$19.6 million increase related to ARP and a $38.0 million increase related to APL, and. The $3.7 million increase in our interest expense consisted of $2.7 million associated with our term loan facility, a $0.5 million increase in the amortization of deferred financing costs primarily associated with our term loan facility, and a $0.4 million ~~increase.~~increase associated with our credit facility. The ~~$10.3~~$19.6 million increase in ARP’s interest expense consisted of a ~~$9.4~~$14.7 million increase associated with ARP’s issuance of the 7.75% ARP Senior Notes in January 2013, a ~~$5.3~~$7.6 million increase in the amortization of deferred financing costs, $3.9 million associated with the issuance of the 9.25% ARP Senior Notes, and a ~~$1.8~~$2.2 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility and term loan credit facility, partially offset by interest capitalized on ARP’s ongoing capital projects. The increase in amortization associated with deferred financing costs includes $3.2 million of accelerated amortization related to the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base subsequent to ARP’s issuance of the 7.75% ARP Senior Notes, $3.2 million associated with ARP’s amended credit facility, $0.7 million associated with ARP’s issuance of the 7.75% ARP Senior Notes, and $0.2 million associated with ARP’s issuance of the 9.25% ARP Senior Notes. The ~~$23.3~~$38.0 million increase in interest expense for APL was primarily due to $24.4 million in additional interest related to the 5.875% APL Senior Notes; a ~~$16.3~~$24.2 million increase in interest expense associated with the 6.625% APL Senior ~~Notes; $14.9 million additional interest related to the 5.875% APL Senior~~ Notes, and ~~$2.6~~$7.4 million in additional interest related to the 4.75% APL Senior Notes, partially offset by ~~$11.4~~$19.2 million in reduced interest on the 8.75% APL Senior Notes. The increase in the interest on ~~the 6.625% APL Senior Notes,~~ the 5.875% APL Senior Notes and the 4.75% APL Senior Notes is due to their issuance after ~~June~~September 30, 2012. The increase in the interest on the 6.625% APL Senior Notes is due to an additional issuance of $175.0 million after September 30, 2012. The decrease in the interest for the 8.75% APL Senior Notes is due to their redemption during the ~~six~~nine months ended ~~June~~September 30, 2013 (see “APL Senior Notes”).

Loss on Early Extinguishment of Debt

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.Loss on early extinguishment of debt for the three months ended ~~June~~September 30, 2013 was approximately $19,000. There was no loss on early extinguishment of debt for the three months ended ~~June~~September 30, 2012.

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012.Loss on early extinguishment of debt for the ~~six~~nine months ended ~~June~~September 30, 2013 represented $17.5 million premiums paid, an $8.0 million consent payment made with respect to the extinguishment, and a $5.3 million write off of deferred financing costs, partially offset by a $4.2 million recognition of unamortized premium related to the redemption of the APL 8.75% APL Senior Notes (see “APL Senior Notes”). There was no loss on early extinguishment of debt for the nine months ended September 30, 2012.

Loss (Income) ~~Loss~~ Attributable to Non-Controlling Interests

Three Months Ended ~~June~~September 30, 2013 Compared with the Three Months Ended ~~June~~September 30, 2012.~~Income~~Loss attributable to non-controlling interests was ~~$3.1~~$52.0 million for the three months ended ~~June~~September 30, 2013 as compared with ~~$59.2~~

loss of $10.0 million for the comparable prior year period. ~~(Income) loss~~Loss (income) attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income (loss) to non-controlling interest holders. The increase between the three months ended September 30, 2013 and the prior year comparable period was primarily due to the increase in APL’s and ARP’s net losses between periods.

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012.Loss attributable to non-controlling interests was $78.1 million for the nine months ended September 30, 2013 as compared with income of $52.6 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income (loss) to non-controlling interest holders. The decrease between the ~~three~~nine months ended ~~June~~September 30, 2013 and the prior year comparable period was primarily due to the decrease in APL’s net earnings between periods ~~partially offset by a decrease~~and an increase in ARP’s net loss between periods.

~~Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012.~~Loss attributable to non-controlling interests was $26.0 million for the six months ended June 30, 2013 as compared with income of $62.6 million for the comparable prior year period. (Income) loss attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income to non-controlling interest holders. The decrease between the six months ended June 30, 2013 and the prior year comparable period was primarily due to the decrease in APL’s net earnings between periods, partially offset by a decrease in ARP’s net loss between periods.

LIQUIDITY AND CAPITAL RESOURCES

General

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

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

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

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

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

expansion capital expenditures and working capital deficits through the retention of cash and additional capital raising; and

debt principal payments through operating cash flows and refinancings as they become due, or by the issuance of additional limited partner units or asset sales.

ARP and APL rely on cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. ARP and APL cannot be certain that additional capital will

be available to the extent required and on acceptable terms. We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our, ARP’s and APL’s credit facilities and other borrowings, the issuance of additional common units, the sale of assets and other transactions.

Cash Flows – ~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with the ~~Six~~Nine Months Ended ~~June~~September 30, 2012

Net cash used in operating activities of ~~$84.2~~$59.4 million for the ~~six~~nine months ended ~~June~~September 30, 2013 represented an unfavorable movement of ~~$59.5~~$87.3 million from net cash ~~used in~~provided by operating activities of ~~$24.7~~$27.9 million for the comparable prior year period. The ~~$59.5~~$87.3 million unfavorable movement was derived principally from ~~a $50.5~~an $88.6 million unfavorable movement in distributions paid to non-controlling interests and a ~~$54.6~~$73.1 million unfavorable movement in working capital, partially offset by a ~~$45.6~~$74.4 million favorable movement in net income (loss) excluding non-cash items. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP and APL. The movement in working capital was due to a ~~$78.3~~$101.9 million unfavorable movement in accounts receivable, prepaid expenses and other, ~~current assets,~~ partially offset by a ~~$23.7~~$28.8 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s and APL’s respective capital programs. The non-cash charges which primarily impacted net income included a ~~$72.0~~$137.8 million increase in non-cash expenses, including depreciation, depletion and amortization, amortization of deferred financing costs and compensation expense, a ~~$30.3~~$52.5 million favorable movement in non-cash ~~gain~~(gain) loss on derivatives and a $26.6 million favorable movement in loss on early extinguishment of debt, partially offset by a ~~$83.3~~$141.5 million unfavorable movement in net income (loss).

Net cash used in investing activities of ~~$1,351.7~~$2,327.5 million for the ~~six~~nine months ended ~~June~~September 30, 2013 represented an unfavorable movement of ~~$918.8~~$1,711.0 million from net cash used in investing activities of ~~$432.9~~$616.5 million for the comparable prior year period. This unfavorable movement was principally due to a ~~$758.9~~$1,476.6 million increase in cash paid for acquisitions, a ~~$153.7~~$217.9 million unfavorable movement in capital expenditures, a $9.8 million increase in APL’s contributions to the T2 Joint Ventures (see “Recent Developments”) and a ~~$6.2~~$6.7 million unfavorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements”.

Net cash provided by financing activities of ~~$1,469.6~~$2,379.6 million for the ~~six~~nine months ended ~~June~~September 30, 2013 represented a favorable movement of ~~$1,056.7~~$1,835.1 million from net cash provided by financing activities of ~~$412.9~~$544.5 million for the comparable prior year period. This movement was principally due to a ~~$1,296.3~~$1,219.8 million favorable movement in net proceeds from the issuance of ARP’s and APL’s long-term debt, a ~~$1,026.1~~$1,089.6 million favorable movement in ARP’s and APL’s issuance of common and preferred limited partner units, a ~~$490.5~~$1,055.5 million favorable movement in our and ARP’s and APL’s borrowings under ~~their~~the respective revolving credit facilities and ~~a $4.7~~an $8.2 million favorable movement in contributions from non-controlling interests, partially offset by a ~~$1,362.4~~$1,103.9 million unfavorable movement in repayments of our and our subsidiaries’ credit facilities, a $365.8 million unfavorable movement in repayments of APL’s long-term debt, a $26.7 million unfavorable movement in deferred financing costs and other, a $25.6 million unfavorable movement in payments of premium on the retirement of APL’s long-term debt and a ~~$6.2~~$16.0 million unfavorable movement in distributions paid to our common limited ~~partners and a $0.9 million~~partners. The unfavorable movement in deferred financing costs and ~~other.~~other is primarily due to the increase in deferred financing costs associated with our and ARP’s revolving and term loan credit facilities. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the consolidated statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us, ARP and APL, which is generally common practice for our and their industries.

Capital Requirements

At ~~June~~September 30, 2013, our ~~principal assets consist~~and our subsidiaries’ capital requirements are as follows:

Natural gas and oil production.The capital requirements of our ~~ownership interests in ARP~~ and APL, through which our operating activities occur (see “Subsequent Events”). As such, at June 30, 2013, we do not currently have any separate capital requirements apart from those entities. A more detailed discussion of ARP’s natural gas and ~~APL’s capital requirements is provided below.~~

~~Atlas Resource Partners.~~~~ARP’s capital requirements~~oil production consist primarily of:

~~maintenance capital expenditures – capital expenditures ARP makes on an ongoing basis to maintain its current levels of production margin over the long term; and~~
•
maintenance capital expenditures— capital expenditures we and ARP make on an ongoing basis to maintain the current levels of production margin over the long term. We and ARP calculate the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. We and ARP do not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a subset of wells expected to be drilled in future periods based on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors,

including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions; and

expansion capital ~~expenditures –~~expenditures— capital expenditures we and ARP ~~makes~~make to increase ~~its~~the current levels of production margin for longer than the short-term, ~~and include~~which includes the acquisition of new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions, direct well drilling and investments by ARP in its Drilling Partnerships.

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

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

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

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

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2013    2012    2013    2012
Atlas Resource

Maintenance capital expenditures
   $ 7,000       $ 1,750       $ 11,000       $ 3,500
Expansion capital expenditures
   64,565       24,944       119,052       42,152








Total
   $ 71,565       $ 26,694       $ 130,052       $ 45,652








Atlas Pipeline

Maintenance capital expenditures
   $ 3,848       $ 4,000       $ 7,703       $ 8,510
Expansion capital expenditures
   103,345       61,221       208,006       137,878








Total
   $ 107,193       $ 65,221       $ 215,709       $ 146,388








Consolidated

Maintenance capital expenditures
   $ 10,848       $ 5,750       $ 18,703       $ 12,010
Expansion capital expenditures
   167,910       86,165       327,058       180,030








Total
   $ 178,758       $ 91,915       $ 345,761       $ 192,040

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Atlas Energy
Maintenance capital expenditures	$	300	$	—	$	300	$	—
Expansion capital expenditures		1,531		—		1,531		—
Total	$	1,831	$	—	$	1,831	$	—

Atlas Resources
Maintenance capital expenditures	$	10,000	$	3,350	$	21,000	$	6,850
Expansion capital expenditures		63,944		24,377		182,996		66,529
Total	$	73,944	$	27,727	$	203,996	$	73,379

Atlas Pipeline
Maintenance capital expenditures	$	6,416	$	4,732	$	14,119	$	13,242
Expansion capital expenditures		105,736		91,292		313,742		229,170
Total	$	112,152	$	96,024	$	327,861	$	242,412

Consolidated
Maintenance capital expenditures	$	16,716	$	8,082	$	35,419	$	20,092
Expansion capital expenditures		171,211		115,669		498,269		295,699
Total	$	187,927	$	123,751	$	533,688	$	315,791

Atlas Energy.During the three and nine months ended September 30, 2013, our total capital expenditures consisted primarily of $1.8 million related to the acquisition of additional leasehold acreage.

Atlas Resource Partners. During the three months ended ~~June~~September 30, 2013, ARP’s ~~$71.6~~$73.9 million of total capital expenditures consisted primarily of ~~$29.1~~$28.6 million for wells drilled exclusively for its own account compared with ~~$0.2~~$7.6 million for the comparable prior year period, ~~$25.6~~$27.7 million of investments in its Drilling Partnerships compared with ~~$4.2~~$13.1 million for the prior year comparable period, ~~$9.1~~$4.2 million of leasehold acquisition costs compared with ~~$19.7~~$5.6 million for the prior year comparable period and ~~$7.8~~$13.4 million of corporate and other costs compared with ~~$2.6~~$1.4 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense. Capital expenditures related to ARP’s investments in its Drilling Partnerships are generally incurred in periods subsequent to the period in which the funds were raised.

During the ~~six~~nine months ended ~~June~~September 30, 2013, ARP’s ~~$130.1~~$204.0 million of total capital expenditures consisted primarily of ~~$65.5~~$94.1 million for wells drilled exclusively for its own account compared with ~~$0.2~~$7.8 million for the comparable prior year period, ~~$37.2~~$64.9 million of investments in its Drilling Partnerships compared with ~~$17.4~~$30.5 million for the prior year comparable period, ~~$13.4~~$17.6 million of leasehold acquisition costs compared with ~~$23.7~~$29.3 million for the prior year comparable period and ~~$14.0~~$27.4 million of corporate and other costs compared with ~~$4.4~~$5.8 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense.

ARP continuously evaluates acquisitions of gas and oil assets. In order to make any acquisitions in the future, ARP believes it 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 ARP will be successful in its efforts to obtain outside capital.

Atlas Pipeline Partners. APL’s capital expenditures increased to ~~$107.2~~$112.2 million for the three months ended ~~June~~September 30, 2013 compared with ~~$65.2~~$96.0 million for the comparable prior year period. The increase was primarily due to construction costs for the Stonewall Plant within Arkoma, the Silver Oak II Plant in SouthTX and the Edward Plant within WestTX.

APL’s capital expenditures increased to $327.9 million for the nine months ended September 30, 2013 compared with $242.4 million for the comparable prior year period. The increase was primarily due to the completion of the Driver Plant within WestTX in April 2013 and construction costs for the Stonewall Plant within Arkoma, ~~and~~ the Silver Oak II Plant ~~in SouthTX.~~

~~APL’s capital expenditures increased to $215.7 million for~~within SouthTX and the ~~six months ended June 30, 2013 compared with $146.4 million for the comparable prior year period. The increase was primarily due to the completion of the Driver~~Edward Plant within ~~WestTX in April 2013 and construction costs for the Stonewall Plant within Arkoma and the Silver Oak II Plant in SouthTX.~~WestTX.

As of ~~June~~September 30, 2013, ~~ARP~~we and ~~APL~~our subsidiaries are committed to expending approximately ~~$219.7~~$263.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of ~~June~~September 30, 2013, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of ~~$0.6~~$2.1 million, APL’s letters of credit outstanding of $0.4 million and ~~ARP’s and APL’s~~ commitments to spend ~~$219.7~~$263.5 million related to ~~ARP’s drilling and completion expenditures, and ARP’s and APL’s other~~ capital expenditures.

CASH DISTRIBUTIONS

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

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.

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

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

Atlas Pipeline Partners’ Cash Distribution Policy.APL’s partnership agreement requires that it distribute 100% of available cash to its common unitholders (subject to the rights of any other class or series of APL security with the right to share in APL’s cash distributions) and to the 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 2.0% of the aggregate amount of cash being distributed. We, as general partner, agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after we receive the initial $7.0 million per quarter of incentive distribution rights.

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

CREDIT FACILITIES

~~In May 2012,~~

Term Loan Facility

On July 31, 2013, in connection with the Arkoma Acquisition, we ~~entered into~~received net proceeds of $230.2 million under a ~~credit facility with a syndicate of banks that matures in May 2016 (see “Subsequent Events”). On March 1, 2013, we amended our credit facility to increase our maximum lender commitments to $100.0~~$240.0 million ~~of which $5.0 million may be in the form of standby letters of credit.~~Term Facility. At ~~June~~September 30, 2013, ~~$34.0~~$240.0 million was outstanding under the ~~credit facility. Our obligations~~Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the credit facility are secured by substantially all of our assets, including our ownership interests in APL and ARP. Additionally, our obligations under the credit facility may be guaranteed by future subsidiaries. AtTerm Facility bear interest, at our election ~~interest on borrowings under the credit facility is determined by~~at either LIBOR plus an applicable margin of ~~between 3.50% and 4.50%~~5.50% per annum or the alternate base rate (“ABR”) plus an applicable margin of ~~between 2.50% and 3.50%~~4.50% per annum. ~~The applicable margin will fluctuate based on~~Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the ~~utilization of the facility.~~interest periods selected by us. We are required to ~~pay a fee between 0.5% and 0.625%~~repay principal at the rate of $0.6 million per ~~annum on~~quarter until the ~~unused portion of~~maturity date when the ~~borrowing base, which~~balance is ~~included within interest expense on our consolidated statement of operations.~~due. At ~~June~~September 30, 2013, the weighted average interest rate on our outstanding ~~credit facility~~Term Facility borrowings was ~~4.2%~~6.5%.

The ~~credit agreement~~Term Facility contains customary covenants, similar to those in our credit facility, that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a ~~commitment deficiency exists or a~~ default ~~under the credit agreement~~ exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The Term Facility also contains a covenant that requires us to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility) the same as those in our credit facility. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

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

Revolving Credit Facility

On July 31, 2013, in connection with the Arkoma Acquisition, we entered into an amended and restated credit agreement with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At September 30, 2013, no amounts were outstanding under the credit facility. Our obligations under the amended credit facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under the credit facility are guaranteed by our material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. At our election, interest on borrowings under the credit agreement is determined by reference to either LIBOR plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by us for LIBOR loans. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that (i) require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than ~~3.25~~4.5 to 1.0 as of the last day of ~~any fiscal~~the quarter ~~and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75~~ending September 30, 2013; 4.0 to 1.0 as of the last day of ~~any fiscal quarter.~~each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) require us to enter into swaps agreements with respect to the assets being acquired in the Arkoma Acquisition.

The credit agreement is subject to an intercreditor agreement as described above.

At ~~June~~September 30, 2013, we have not guaranteed any of ARP’s or APL’s debt obligations.

Atlas ~~Resource~~Resources

~~At June 30,~~

On July 31, 2013, in connection with the acquisition of assets from EP Energy (see “Recent Developments”), ARP ~~had~~entered into a second amended and restated credit agreement (“ARP Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amended and restated ARP’s existing revolving credit facility. The Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of ~~$430.0~~$835.0 million and a maximum facility amount of $1.5 billion, which is scheduled to mature in ~~March 2016 (see “Subsequent Events”). In January~~July 2018. At September 30, 2013, ~~ARP repaid in full its $75.4~~$425.0 million ~~term loan~~was outstanding under the credit ~~facility, which was scheduled to mature in May 2014, with proceeds from its issuance of 7.75% ARP Senior Notes.~~facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which ~~$0.6~~$2.1 million was outstanding at ~~June~~September 30, 2013. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by ~~substantially all~~certain of ARP’s ~~subsidiaries.~~material subsidiaries, and any subsidiaries of ARP, other than subsidiary guarantors, are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either LIBOR plus an applicable margin between 1.75% and ~~3.00%~~2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal ~~funds~~Funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and ~~2.00%~~1.75% per annum. ARP is also required to pay a fee ~~of 0.5% per annum~~ on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on ~~the~~ our consolidated statements of operations.

At September 30, 2013, the weighted average interest rate on outstanding borrowings under the credit facility was 2.2%.

The ~~revolving credit agreement~~ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP ~~was in compliance with these covenants as of June 30, 2013. The credit agreement~~Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt ~~(as~~

(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 4.50 to 1.0 as of the last day of the quarter ended September 30, 2013, 4.25 to 1.0 as of the last day of ~~any fiscal quarter ending on or before~~the quarters ended December 31, 2013 and March 31, 2014 and 4.0 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

~~On July 30, 2013, in connection with the EP Energy Acquisition, ARP entered into an amendment of its revolving credit facility (see “Subsequent Events”).~~

Atlas Pipeline

At ~~June~~September 30, 2013, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which ~~$80.0~~$100.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus ~~1.00%~~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 ~~June~~September 30, 2013 was 3.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.4 million was outstanding at ~~June~~September 30, 2013. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet at ~~June~~September 30, 2013. At ~~June~~September 30, 2013, APL had ~~$519.6~~$499.6 million of remaining committed capacity under its credit facility, subject to covenant limitations. ~~We have not guaranteed any of the obligations under APL’s senior secured revolving credit facility.~~

Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK and West TX entities in which APL has 95% interests, and Centrahoma, ~~Processing, LLC (“Centrahoma”),~~ in which APL has a 60% interest; and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies.

The events which constitute an event of default under the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. On April 19, 2013, APL entered into an amendment to the credit agreement which, among other changes, adjusted certain covenant ratio limits and adjusted the method of calculation in connection with the TEAK ~~acquisition (see “Recent Developments”).~~acquisition.

ATLAS RESOURCE SECURED HEDGE FACILITY

At ~~June~~September 30, 2013, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantee their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

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

SENIOR NOTES

Atlas Resource Senior Notes

On September 30, 2013, ARP had $275.0 million principal outstanding of 7.75% ARP Senior Notes and $248.3 million principal outstanding of 9.25% ARP Senior Notes. On July 30, 2013, ARP issued $250.0 million of 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs, of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see “Recent Developments”). The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of September 30, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date being February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes ~~due 2021~~ in a private placement transaction at par. ARP used the net proceeds of approximately ~~$267.8~~$267.7 million, net of underwriting fees and other offering costs of ~~$7.2~~$7.3 million, to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit ~~facility (see “Credit Facilities”). Under~~facility. In connection with the ~~terms~~retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility ~~the~~ borrowing base, ~~was reduced by 15%~~ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the ~~7.75% ARP Senior Notes to $368.8 million.~~nine months ended September 30, 2013. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. The indenture governing the 7.75% ARP Senior Notes contains covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets.

In connection with the issuance of the 7.75% ARP Senior Notes, ARP entered into registration rights agreements, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by January 23, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 7.75% ARP Senior Notes. If ARP ~~does not meet~~fails to comply with its obligations to register the ~~aforementioned deadline,~~7.75% ARP Senior Notes within the specified time period, the 7.75% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that ~~ARP causes~~ the exchange offer ~~to be consummated.~~is consummated or the shelf registration statement is declared effective, as applicable. On July 1, 2013, ARP filed ~~its~~a registration statement ~~with~~relating to the ~~SEC in satisfaction of certain requirements of~~exchange offer for the ~~registration rights agreement.~~7.75% ARP Senior Notes.

~~On July 30, 2013, in connection with~~

The indentures governing the ~~EP Energy Acquisition,~~7.75% and 9.25% ARP ~~issued $250.0 million of our 9.25%~~ Senior Notes ~~in a private placement transaction (see “Subsequent Events”).~~contains covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets.

Atlas Pipeline Senior Notes Issuances

At ~~June~~September 30, 2013, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes due 2020, $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior ~~Notes~~Notes”) and $400.0 million of 4.75% Senior Notes due 2021 (with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.5 million after underwriting commissions and other transactions costs and utilized the proceeds to repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see “Recent Developments”). Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In connection with the issuance of the 4.75% APL Senior Notes, APL entered into a registration rights ~~agreements,~~agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by May 5, 2014. If APL does not meet the aforementioned deadline, the 4.75% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated. On October 4, 2013, APL filed a registration statement with the SEC for an exchange offer for the 4.75% Senior Notes.

outstanding indebtedness under its revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In connection with the issuance of the 5.875% APL Senior Notes, APL entered into a registration rights ~~agreements,~~agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued 5.875% APL Senior Notes for registered notes, and (b) cause the exchange offer to be consummated by February 6, 2014. If APL does not meet the aforementioned deadline, the 5.875% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated. On October 4, 2013, APL filed a registration statement with the SEC for an exchange offer for the 5.875% Senior Notes.

On September 28, 2012 and December 20, 2012, APL issued an aggregate of $500.0 million of its 6.625% ~~senior notes~~APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were presented combined with a net ~~$4.9~~$4.7 million unamortized premium as of ~~June~~September 30, 2013. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. ~~On July 22, 2013,~~The registration statement APL filed ~~an amendment to its registration statement~~ with the SEC ~~in satisfaction of~~for the ~~registration requirements~~exchange offer for the 6.625% APL Senior Notes became effective on September 17, 2013. APL commenced an exchange offering for the 6.625% APL Senior Notes on September 18, 2013 and the exchange offer was completed on October 16, 2013. Pursuant to the terms of the registration rights ~~agreement.~~agreement, because the exchange offer was not consummated within the required timeframe, APL incurred a 0.25% interest penalty from September 23, 2013 through consummation of the exchange offer on October 16, 2013.

Atlas Pipeline Senior Notes Redemptions

of the net proceeds from the issuance of the 5.875% APL Senior Notes due 2023. During the ~~six~~nine months ended ~~June~~September 30, 2013, APL recognized a loss of $26.6 million within loss on early extinguishment of debt on our consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid, $8.0 million consent payment and a $5.3 million write-off of deferred financing costs, partially offset by $4.2 million of unamortized premium recognized.

On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% APL Senior Notes, excluding unamortized premium, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture. APL also ~~issued a notice to redeem~~redeemed all the 8.75% APL Senior Notes not purchased in connection with the tender offer.

ISSUANCE OF UNITS

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

Atlas Energy

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

Atlas Resource Partners

Equity Offerings

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

~~Equity Offerings~~

In June 2013, in connection with ~~entering into a purchase agreement to acquire certain producing wells and net acreage from~~the EP ~~Energy (see “Subsequent Events”),~~Acquisition, ARP sold an aggregate of 14,950,000 ~~(including a 1,950,000 over-allotment)~~

of its common limited partner units (including a 1,950,000 over-allotment) in a public offering at a price of $21.75 per unit, yielding net proceeds of

approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit ~~facility (see “Credit Facilities”).~~facility.

In May 2013, ARP entered into an equity distribution program with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution program, ARP may sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act of 1933, as amended, including sales made directly on the New York Stock Exchange, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the ~~three and six~~nine months ended ~~June~~September 30, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of ~~$7.1~~$7.0 million, net of ~~$0.3~~$0.4 million in commissions paid. No common limited partner units were issued under the equity distribution program during the three months ended September 30, 2013. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million of ARP’s common units and 3.8 million newly-created ARP convertible Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo. To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain of our executives. The common units issued by ARP were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of the registration requirements of the registration rights agreement and on August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s common and preferred units, we recorded a $25.2 million ~~and $48.4 million gain~~ within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated statements of partners’ capital during the ~~six~~nine months ended ~~June~~September 30, ~~2013 and 2012, respectively.~~2013.

ARP Common Unit Distribution

In February 2012, the board of directors of our general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner

units for each of our common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see “Business Overview”).

Atlas Pipeline Partners

APL Equity Offerings

In April 2013, APL sold 11,845,000 of its common units ~~of APL~~ at a price to the public of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from us, as general partner, of $8.3 million to maintain our 2%2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see “Recent Developments”).

In May 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction, at a negotiated price per unit of $29.75, ~~for~~resulting in net proceeds of $397.7 ~~million. The~~million pursuant to the Class D ~~Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL also received a capital contribution from us,~~preferred unit purchase agreement dated April 16, 2013 (the “Commitment Date”). We, as general partner, ofcontributed $8.2 million to maintain our 2.0% general ~~partner~~partnership interest in ~~APL.~~APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK ~~Acquisition (see “Recent Developments”).~~Acquisition.

The fair value of APL’s common units ~~upon issuing~~on the Commitment Date of the Class D Preferred Units was $36.52 per unit, resulting in an embedded beneficial conversion discount on the Class D Preferred Units of $91.0 million. ~~The Partnership~~We recognized the ~~intrinsic~~fair value of the Class D Preferred Units with the offsetting intrinsic discount within non-controlling interests on ~~the Partnership’s~~our consolidated balance sheet as of ~~June~~September 30, 2013. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and ~~the Partnership,~~us, as general partner. For the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL recorded ~~$6.7~~$11.4 million and $18.1 million, respectively, within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on our consolidated statements of operations to recognize the accretion of the beneficial conversion discount. APL’s Class D Preferred Units are presented combined with a net ~~$84.3~~$72.9 million unaccreted beneficial conversion discount within non-controlling interests on our consolidated balance sheet at ~~June~~September 30, 2013.

The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of ~~the Partnership,~~us, as general partner. Cash distributions will be paid to the Class D Preferred Unit holders prior to any other distributions of available cash. Distributions will be determined based upon the cash distribution declared each quarter on APL’s common limited partner units plus a preferred yield premium. Class D Preferred Unit distributions, whether in kind units or in cash, will be accounted for as a reduction to APL’s net income attributable to the common limited partners and ~~the Partnership,~~us, as general partner. For the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL recorded costs related to preferred unit distributions of ~~$5.3~~$9.1 million and $14.4 million, respectively, within income (loss) attributable to non-controlling interests on our consolidated statements of operations. During the three and nine months ended September 30, 2013, APL distributed 138,598 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution for the quarter ended June 30, 2013.

will pay Citigroup a commission, which in each case shall not be more than 2.0% of the gross sales price of common limited partner units sold. During the three and ~~six~~nine months ended ~~June~~September 30, 2013, APL issued ~~642,495~~1,722,800 and ~~1,090,280~~2,863,080 common units, respectively, under the equity distribution program for net proceeds of ~~$24.5~~$63.7 million and ~~$38.9~~$102.7 million, net of ~~$0.5~~$1.3 million and ~~$0.8~~$2.1 million, respectively, in commission incurred from Citigroup. APL also received capital contributions from us of ~~$0.5~~$1.3 million and ~~$0.8~~$2.1 million during the three and ~~six~~nine months ended ~~June 3,~~September 30, 2013, respectively, to maintain our 2.0% general partner interest in APL. APL utilized the net proceeds from the ~~sale to repay borrowings outstanding under its revolving credit facility.~~common unit offering for general partnership purposes.

In December 2012, APL completed the sale of 10,507,033 APL common units in a public offering at an offering price of $31.00 per unit and received net proceeds of $319.3 million, including $6.7 million contributed by us to maintain our 2.0% general partner interest in APL. APL used the net proceeds from this offering to fund a portion of the Cardinal Acquisition. In November 2012, APL entered into an agreement to issue $200.0 million of newly created Class D convertible preferred units in a private placement in order to finance a portion of the Cardinal Acquisition. Under the terms of the agreement, the private placement of the Class D convertible preferred units was nullified upon APL’s issuance of common units in excess of $150.0 million prior to the closing date of the Cardinal Acquisition. As a result of APL’s December 2012 issuance of $319.3 million common units, the private placement agreement terminated without the issuance of the Class D preferred units, and APL paid a commitment fee equal to 2.0%, or $4.0 million.

In connection with the issuance of APL’s common units during the ~~six~~nine months ended ~~June~~September 30, 2013, we recorded ~~a $9.9~~an $11.5 million gain within partner’s capital and a corresponding decrease in non-controlling interests on our consolidated statement of partners’ capital during the ~~six~~nine months ended ~~June~~September 30, 2013. ~~No gain was recorded during the six months ended June 30, 2012.~~

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 the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements was included in our Annual Report on Form ~~10-K~~10-K/A for the year ended December 31, 2012, and we summarize our significant accounting policies within our consolidated financial statements included in Note 2 under “Item 1: Financial Statements” included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

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

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

have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

There were no impairments of proved or unproved gas and oil properties recorded ~~by ARP~~ for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012. During the year ended December 31, 2012, ARP recognized $9.5 million of asset

impairments related to gas and oil properties within property, plant and equipment on our consolidated balance sheet for shallow natural gas wells in the Antrim and Niobrara Shales. These impairments related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

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

There were no goodwill impairments recognized by us during the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012.

Fair Value of Financial Instruments

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3– Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

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

Of the ~~$90.9~~$61.8 million and $51.3 million of net derivative assets at ~~June~~September 30, 2013 and December 31, 2012, respectively, APL had net derivative assets of ~~$28.6~~$2.7 million and $23.1 million at ~~June~~September 30, 2013 and December 31, 2012, respectively, that were classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the price APL utilized in calculating the fair value of derivatives at ~~June~~September 30, 2013 would have resulted in a ~~$0.7~~$0.9 million non-cash change, excluding the effect of non-controlling interests, to net income for the ~~six~~nine months ended ~~June~~September 30, 2013.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows

using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

During the three months ended ~~June~~September 2013, we completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the nine months ended September 30, 2013, APL completed the TEAK ~~acquisition.~~Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, ~~and~~certain proved reserves and associated

assets from Titan and the DTE ~~and~~Acquisition, while APL completed the Cardinal ~~acquisition.~~Acquisition. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of our and its gas and oil wells (see “Item 1: Financial ~~Statements –~~ Statements—Note 7”). These inputs require significant judgments and estimates by our, ARP’s and APL’s management at the time of the valuation and are subject to change.

Reserve Estimates

~~Our estimates~~

Estimates of ~~ARP’s~~ proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. As discussed in “Item 2: Properties” of our Annual Report on Form 10-K for the year ended December 31, 2012, ARP engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of its proved reserves.

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

Asset Retirement Obligations

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

~~Atlas Resource~~

We and ARP ~~recognizes~~recognize an estimated liability for the plugging and abandonment of ~~its~~ gas and oil wells and related facilities. We and ARP also ~~recognizes~~recognize a liability for ~~its~~ future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. We and ARP also ~~considers~~consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on ~~ARP’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. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we and ARP ~~attempts~~attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. Neither we nor ARP ~~has no~~have any assets legally restricted for purposes of settling asset retirement

obligations. Except for ~~ARP’s~~ gas and oil properties, ~~ARP believes that~~ there are no other material retirement obligations associated with our and ARP’s tangible long lived assets.

Atlas Pipeline

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations owned by APL and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of ~~June~~September 30, 2013 and December 31, 2012 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

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

General

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on ~~June~~September 30, 2013. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

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

Interest Rate Risk.At ~~June~~September 30, 2013, we had ~~$34.0~~$240.0 million of outstanding borrowings under our ~~credit~~term loan facility, ARP had no$425.0 million of outstanding borrowings under its revolving credit facility and APL had ~~$80.0~~$100.0 million of outstanding borrowings under its senior secured revolving credit facility. At September 30, 2013, we had no borrowings outstanding under our revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending ~~June~~September 30, 2014 by ~~$1.1~~$7.7 million, excluding the effect of non-controlling interests.

Commodity Price Risk. Our ~~ARP’s~~ and ~~APL’s~~our subsidiaries’ market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our and our subsidiaries’ financial results. To limit ~~their~~the exposure to changing commodity prices, we ~~ARP~~ and ~~APL~~our subsidiaries use financial derivative instruments, including financial swap and option instruments, to hedge portions of ~~their~~ future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap

agreements, we ~~ARP~~ and ~~APL~~our subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending ~~June~~September 30, 2014 of approximately ~~$6.1~~$6.4 million, net of non-controlling interests.

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

At ~~June~~September 30, 2013, we had the following commodity derivatives:

Natural Gas Fixed Price ~~Swaptions~~Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price
   (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾
2014
   2,760,000       $ 4.156
2015
   2,280,000       $ 4.295
2016
   1,440,000       $ 4.423
2017
   1,200,000       $ 4.590
2018
   420,000       $ 4.797

~~Natural Gas Put Options~~

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2014		750,000	$	4.058
2014		2,760,000	$	4.177
2015		2,280,000	$	4.302
2016		1,440,000	$	4.433
2017		1,200,000	$	4.590
2018		420,000	$	4.797

Production Period Ending December 31,

Option Type
   Volumes    Average
Fixed Price
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾
2013
   Puts purchased    1,500,000       $ 3.958

⁽¹⁾	“MMBtu” represents million British Thermal Units.

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

At ~~June~~September 30, 2013, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price
   (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾
2013
   14,694,800       $ 3.821
2014
   31,353,000       $ 4.139
2015
   27,234,500       $ 4.237
2016
   33,746,300       $ 4.359
2017
   24,120,000       $ 4.538
2018
   3,960,000       $ 4.716

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2013		15,597,400	$	3.909
2014		60,153,000	$	4.152
2015		50,274,500	$	4.240
2016		43,946,300	$	4.318
2017		24,840,000	$	4.532
2018		3,960,000	$	4.716

Natural Gas Costless Collars

Production Period Ending December 31,

Option Type
   Volumes    Average
Floor and Cap
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾
2013
   Puts purchased    2,760,000       $ 4.395
2013
   Calls sold    2,760,000       $ 5.443
2014
   Puts purchased    3,840,000       $ 4.221
2014
   Calls sold    3,840,000       $ 5.120
2015
   Puts purchased    3,480,000       $ 4.234
2015
   Calls sold    3,480,000       $ 5.129

~~Natural Gas Put Options~~


Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Option Type	Volumes		Average Floor and Cap
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾			(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2013	Puts purchased		14,280,000	$	3.957	Puts purchased		1,380,000	$	4.395
2013						Calls sold		1,380,000	$	5.443
2014						Puts purchased		3,840,000	$	4.221
2014						Calls sold		3,840,000	$	5.120
2015						Puts purchased		3,480,000	$	4.234
2015						Calls sold		3,480,000	$	5.129

Natural Gas Put Options – Drilling ~~Partnership~~Partnerships

Production Period Ending December 31,

Option Type
   Volumes    Average
Fixed Price
      (MMBtu)⁽¹⁾    (per MMBtu)⁽¹⁾
2013
   Puts purchased    1,080,000       $ 3.450
2014
   Puts purchased    1,800,000       $ 3.800
2015
   Puts purchased    1,440,000       $ 4.000
2016
   Puts purchased    1,440,000       $ 4.150

~~Natural Gas Fixed Price Swaptions~~


Production Period Ending December 31,	Volumes		Average Fixed Price		Option Type	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾			(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2013					Puts purchased		540,000	$	3.450
2014		26,880,000	$	4.159	Puts purchased		1,800,000	$	3.800
2015		17,760,000	$	4.297	Puts purchased		1,440,000	$	4.000
2016					Puts purchased		1,440,000	$	4.150

Natural Gas Liquids Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price
   (Bbl)⁽¹⁾    (per Bbl)⁽¹⁾
2013
   63,000       $ 93.656
2014
   105,000       $ 91.571
2015
   96,000       $ 88.550
2016
   84,000       $ 85.651
2017
   60,000       $ 83.780

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2013		36,000	$	93.656
2014		105,000	$	91.571
2015		96,000	$	88.550
2016		84,000	$	85.651
2017		60,000	$	83.780

Natural Gas Liquids Ethane Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price
   (Gal)⁽¹⁾    (per Gal)⁽¹⁾
2014
   2,520,000       $ 0.303

Production

Period Ending

December 31,

Volumes

Average
Fixed Price

(Gal)⁽¹⁾

(per Gal)⁽¹⁾

2014

2,520,000

0.303

Natural Gas Liquids Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾
2013		3,864,000	$	1.084
2014		11,592,000	$	0.996

Crude Oil Fixed Price Swaps

Production Period Ending December 31,
   Volumes    Average
Fixed Price
   (Bbl)⁽¹⁾    (per Bbl)⁽¹⁾
2013
   262,850       $ 92.307
2014
   414,000       $ 91.727
2015
   411,000       $ 88.030
2016
   165,000       $ 85.931
2017
   72,000       $ 84.175

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2013		170,200	$	93.738
2014		552,000	$	92.668
2015		567,000	$	88.144
2016		225,000	$	85.523
2017		132,000	$	83.305

Crude Oil Costless Collars

Production Period Ending December 31,

Option Type
   Volumes    Average
Floor and Cap
      (Bbl)⁽¹⁾    (per Bbl)⁽¹⁾
2013
   Puts purchased    35,000       $ 90.000
2013
   Calls sold    35,000       $ 116.396
2014
   Puts purchased    41,160       $ 84.169
2014
   Calls sold    41,160       $ 113.308
2015
   Puts purchased    29,250       $ 83.846
2015
   Calls sold    29,250       $ 110.654

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2013	Puts purchased		20,000	$	90.000
2013	Calls sold		20,000	$	116.396
2014	Puts purchased		41,160	$	84.169
2014	Calls sold		41,160	$	113.308
2015	Puts purchased		29,250	$	83.846
2015	Calls sold		29,250	$	110.654

⁽¹⁾	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

100

As of ~~June~~September 30, 2013, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period

Purchased/
Sold

Commodity
   Volumes⁽¹⁾    Average
Fixed
Price
Natural Gas

2013
   Sold    Natural Gas    3,100,000       $ 3.689
2014
   Sold    Natural Gas    12,600,000       $ 3.983
2015
   Sold    Natural Gas    15,160,000       $ 4.235
2016
   Sold    Natural Gas    3,750,000       $ 4.399
Natural Gas Liquids

2013
   Sold    Natural Gas Liquids    27,468,000       $ 1.247
2014
   Sold    Natural Gas Liquids    55,566,000       $ 1.248
2015
   Sold    Natural Gas Liquids    23,688,000       $ 1.110
Crude Oil

2013
   Sold    Crude Oil    153,000       $ 96.873
2014
   Sold    Crude Oil    312,000       $ 92.368
2015
   Sold    Crude Oil    60,000       $ 85.130


Options Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾		Average Strike Price

Production Period								Purchased/ Sold	Commodity	Volumes⁽¹⁾		Average Fixed Price
Natural Gas
2013								Sold	Natural Gas		1,570,000	$	3.752
2014	Purchased	Put	Natural Gas		600,000	$	4.125	Sold	Natural Gas		12,600,000	$	3.983
2015								Sold	Natural Gas		15,160,000	$	4.235
2016								Sold	Natural Gas		3,750,000	$	4.399

Natural Gas Liquids
2013	Purchased	Put	Natural Gas Liquids		23,184,000	$	1.897	Sold	Natural Gas Liquids		18,774,000	$	1.200
2014	Purchased	Put	Natural Gas Liquids		3,150,000	$	1.030	Sold	Natural Gas Liquids		75,978,000	$	1.185
2015	Purchased	Put	Natural Gas Liquids		1,260,000	$	0.883	Sold	Natural Gas Liquids		27,216,000	$	1.097

Crude Oil
2013	Purchased	Put	Crude Oil		147,000	$	100.100	Sold	Crude Oil		75,000	$	96.660
2014	Purchased	Put	Crude Oil		448,500	$	94.685	Sold	Crude Oil		312,000	$	92.368
2015	Purchased	Put	Crude Oil		270,000	$	89.175	Sold	Crude Oil		60,000	$	85.130

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾		Average Strike Price
Natural Gas
2014	Purchased	Put	Natural Gas		600,000	$	4.125

Natural Gas Liquids
2013	Purchased	Put	Natural Gas Liquids		11,844,000	$	1.900
2014	Purchased	Put	Natural Gas Liquids		4,410,000	$	1.001
2015	Purchased	Put	Natural Gas Liquids		1,890,000	$	0.901

Crude Oil
2013	Purchased	Put	Crude Oil		75,000	$	100.100
2014	Purchased	Put	Crude Oil		448,500	$	94.685
2015	Purchased	Put	Crude Oil		270,000	$	89.175

⁽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.

~~Volumes for crude oil are stated in barrels.~~

101

ITEM 4:

CONTROLS AND PROCEDURES

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

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of ~~June~~September 30, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

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.

~~On May 7,~~

During the nine months ended September 30, 2013, ARP completed the acquisition of certain assets from EP Energy and APL acquired 100% the outstanding ownership interests in TEAK (see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Recent Developments”). We are continuing to integrate ~~this system’s~~these systems’ historical internal controls over financial reporting with our existing internal controls over financial reporting. This integration may lead to changes in our or the acquired ~~system’s~~systems’ historical internal controls over financial reporting in future fiscal reporting periods.

~~PART II~~

102

PART II

ITEM 1:

LEGAL PROCEEDINGS

On August 3, 2011, CNX Gas Company LLC (“CNX”), filed a lawsuit in the United States District Court for the Eastern District of Tennessee at Knoxville styledCNX Gas Company LLC vs. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC, and Scott Boruff, No. 3:11-cv-00362. On April 16, 2012, Atlas Energy Tennessee, LLC, one of our subsidiaries, was brought into the lawsuit by way of Amended Complaint. On April 23, 2012, the Court dismissed Chevron Appalachia, LLC as a party on the grounds of lack of subject matter jurisdiction over that entity.

The lawsuit ~~alleges~~alleged that CNX entered into a Letter of Intent with Miller Energy Resources, Inc. (“Miller Energy”), for the purchase by CNX of certain leasehold interests containing oil and natural gas rights, representing around 30,000 acres in East Tennessee. The lawsuit also ~~alleges~~alleged that Miller Energy breached the Letter of Intent by refusing to close by the date provided and by allegedly entertaining offers from third parties for the same leasehold interests. Allegations of inducement of breach of contract and related claims ~~are~~were made by CNX against the remaining defendants, on the theory that these parties knew of the terms of the Letter of Intent and induced Miller Energy to breach the Letter of Intent. CNX iswas seeking $15.5 million in damages. We ~~assert~~asserted that we acted in good faith and ~~believe~~believed that the outcome of the litigation ~~will~~would be resolved in our favor.

In early September 2013, Atlas Energy Tennessee, LLC, was dismissed as a party on jurisdictional grounds.

We and our subsidiaries are also parties to various routine legal proceedings arising out of 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.

103

ITEM 6:

EXHIBITS

Exhibit No.		Description
~~Exhibit~~ ~~No.~~2.1		~~Description~~

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

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

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

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

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

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

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

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

4.1		Specimen Certificate Representing Common Units⁽¹⁾

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

~~10.2~~ 10.2(a)		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽¹⁾

~~10.3(a)~~ 10.2(b)		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽⁵⁴⁾

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

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

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

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

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

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

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

~~Exhibit~~
~~No.~~
~~Description~~
10.3(h)
~~10.3(h)~~
Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁹⁾
10.3(i)
Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁴⁾
10.3(j)
Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽³⁹⁾
10.4
Atlas Pipeline Partners, L.P.’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Convertible Preferred Units, dated as of May 7, 2013⁽³⁹⁾

104

Exhibit No.		Description
~~10.5~~ 10.5(a)		Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC⁽³³⁾

~~10.6(a)~~ 10.5(b)		Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC⁽⁵³⁾

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

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

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

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

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

10.9(a)		Long-Term Incentive Plan⁽⁶⁾

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

10.10		Form of Phantom Grant under 2006 Long-Term Incentive Plan⁽⁵³⁾

10.11		2010 Long-Term Incentive Plan⁽¹⁶⁾

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

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

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

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

~~Exhibit~~
~~No.~~
~~Description~~
10.16
Intercreditor Agreement, dated July 31, 2013 among Atlas Energy, L.P., the grantors party ~~thereto,~~thereo, Wells Fargo
Bank, NA as revolving facility administrative agent and Deutsche Bank AG, New York Branch, as term facility
administrative agent⁽⁴⁵⁾
10.17(a)
Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto⁽²³⁾
10.17(b)
Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011⁽²⁵⁾
10.17(c)
Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011⁽²⁶⁾
10.17(d)
Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012⁽¹⁸⁾
10.17(e)
Amendment No. 3 to the Amended and Restated Credit Agreement⁽³⁴⁾
10.17(f)
Amendment No. 4 to the Amended and Restated Credit Agreement⁽¹¹⁾
10.18
Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

105

Exhibit No.		Description
10.19(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~~becauseconfidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

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

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

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

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

~~Exhibit~~
~~No.~~
~~Description~~
10.22
~~10.22~~
Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾
10.23
Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011⁽¹²⁾
10.24
Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011⁽¹²⁾
10.25
Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011⁽²¹⁾
10.26
Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011⁽³²⁾
10.27
Employment Agreement between Atlas Energy, L.P. and Daniel Herz dated as of November 4, 2011
10.28
Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012⁽³⁵⁾
10.29
Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010⁽²¹⁾
10.30
Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010⁽²²⁾
10.31
Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010⁽²²⁾
10.32
Second Amended and Restated Credit Agreement dated July 31, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽⁴⁴⁾
10.33(a)
Credit Agreement, dated as of March 5, 2012, among Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders⁽³⁰⁾

106

Exhibit No.		Description
10.33(b)		First Amendment to Credit Agreement, dated as of April 30, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders⁽³¹⁾

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

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

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

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

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

~~Exhibit~~
~~No.~~
~~Description~~
10.35
~~10.35~~
Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan⁽²⁸⁾
10.36
Atlas Pipeline Partners, L.P. Long-Term Incentive Plan⁽²⁷⁾
10.37
Atlas Pipeline Partners, L.P. Amended and Restated 2010 Long-Term Incentive Plan⁽²⁰⁾
10.38
Registration Rights Agreement, dated as of April 30, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein⁽³¹⁾
10.39
Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein⁽¹⁷⁾
10.40
Registration Rights Agreement, dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation and the initial purchasers named therein⁽¹⁰⁾
10.41
Registration Rights Agreement, dated May 16, 2012, between Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein⁽³⁵⁾
10.42
Registration Rights Agreement, dated September 28, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽⁴¹⁾
~~10.43~~ Registration Rights Agreement, dated December 20, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽⁴²⁾
~~10.44~~
Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.⁽⁴³⁾
~~10.45~~
10.43
Purchase and Sale Agreement, dated as of April 16, 2013, among TEAK Midstream Holdings, LLC, TEAK Midstream, L.L.C. and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Registration S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request⁽²⁹⁾
~~10.46~~
10.44
Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽³⁸⁾
~~10.47~~
10.45
Class D Preferred Unit Purchase Agreement, dated as of April 16, 2013, among Atlas Pipeline Partners, L.P. and the various purchasers party thereto⁽²⁹⁾
~~10.48~~
10.46
Registration Rights Agreement, dated May 7, 2013, by and among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽³⁹⁾
~~10.49~~
10.47
Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.⁽⁴⁷⁾
~~10.50~~
10.48
Warrant to Purchase Common Units⁽⁴⁴⁾

~~Exhibit~~
~~No.~~
~~Description~~
10.49
~~10.51~~
Distribution Agreement dated as of May 10, 2013, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents⁽⁴⁸⁾
~~10.52~~
10.50
Class C Preferred Unit Purchase Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P.⁽⁵⁰⁾

107

Exhibit No.		Description

~~10.53~~	10.51		Indenture dated as of July 30, 2013, by and between Atlas Resource Escrow Corporation and Wells Fargo Bank, National Association⁽⁴⁹⁾

~~10.54~~	10.52		Supplemental Indenture dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association⁽⁴⁹⁾

~~10.55~~	10.53		Registration Rights Agreement dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Deutsche Bank Securities, Inc., for itself and on behalf of the Initial Purchasers⁽⁴⁹⁾

~~10.56~~	10.54		Registration Rights Agreement dated as of July 31, 2013 by and among Atlas Energy, L.P. and Atlas Resource Partners, L.P.⁽⁴⁴⁾

~~10.57~~	10.55		Registration Rights Agreement dated May 7, 2013, among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽⁵²⁾

~~10.58~~	10.56		Indenture dated as of May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein and U.S. Bank National Association⁽⁴⁶⁾

~~10.59~~	10.57		Registration Rights Agreement, dated May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the guarantors named therein and Citigroup Global Markets, Inc. for itself and on behalf of the initial purchasers⁽⁴⁶⁾

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

101.INS		XBRL Instance Document⁽⁵⁴⁾⁽⁵⁵⁾

101.SCH		XBRL Schema Document^(54)(55⁾

101.CAL		XBRL Calculation Linkbase Document⁽⁵⁴⁾⁽⁵⁵⁾

101.LAB		XBRL Label Linkbase Document^(54)(55⁾

101.PRE		XBRL Presentation Linkbase Document⁽⁵⁴⁾⁽⁵⁵⁾

101.DEF		XBRL Definition Linkbase Document^(54)(55⁾

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

(2)	Previously filed as an exhibit to current report on Form 8-K filed May 21, 2012.

(3)	Previously filed as an exhibit to current report on Form 8-K filed on March 4, 2013.

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

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

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

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

(10)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 25, 2013.

(11)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 23, 2013.

(12)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(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 December 13, 2011.

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

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

(17)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012.

108

(18)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 31, 2012.

(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 Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q filed on March 31, 2011.

(21)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(22)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(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 Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(26)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011.

(27)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2009.

(28)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 14, 2012.

(29)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 17, 2013.

(30)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012.

(31)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 1, 2012.

(32)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2011.

(33)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2012.

(34)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2012.

(35)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended ~~June~~September 30, 2012.

(36)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on December 26, 2012.

(37)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 11, 2013.

(38)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on February 12, 2013.

(39)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 8, 2013.

(40)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended ~~June~~September 30, 2012.

(41)	~~Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 28, 2012.~~ Intentionally omitted.

(42)	~~Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 26, 2012.~~ Intentionally omitted.

(43)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on November 6, 2012.

(44)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 6, 2013.

(45)	Previously filed as an exhibit to current report on Form 8-K filed on August 6, 2013.

(46)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 13, 2013.

(47)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 10, 2013.

(48)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 10, 2013.

(49)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 2, 2013.

(50)	Previously filed as an exhibit to current report on Form 8-K filed on June 13, 2013.

(51)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 31, 2013.

(52)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 8, 2013.

(53)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended ~~March 31,~~September 30, 2013.

(54)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P. quarterly report on Form 10-Q for the quarter ended September 30, 2013.

(55)

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

109

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: ~~August 9,~~November 8, 2013	~~By:~~	By:	/s/S/ EDWARD E. COHEN
		Edward E. Cohen
		Chief Executive Officer and President of the General Partner

Date: ~~August 9,~~November 8, 2013	~~By:~~	By:	/s/S/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Financial Officer of the General Partner

Date: ~~August 9,~~November 8, 2013	~~By:~~	By:	/s/S/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback
		Chief Accounting Officer of the General Partner

~~108~~

110


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues:
Gas and oil production	$	47,094		$	19,460		$	93,158		$	36,624
Well construction and completion		24,851			12,241			81,329			55,960
Gathering and processing		535,922			256,420			956,009			561,561
Administration and oversight		3,391			1,315			4,476			4,146
Well services		4,864			5,252			9,680			10,258
Gain on mark-to-market derivatives		27,107			67,847			15,024			55,812
Other, net		566			504			6,221			3,305

Total revenues		643,795			363,039			1,165,897			727,666


Costs and expenses:
Gas and oil production		19,035			4,447			34,251			8,952
Well construction and completion		21,609			10,606			70,721			48,301
Gathering and processing		453,868			213,551			805,609			465,396
Well services		2,305			2,414			4,623			4,844
General and administrative		53,874			37,607			94,532			74,855
Depreciation, depletion and amortization		68,580			32,534			120,246			62,484

Total costs and expenses		619,271			301,159			1,129,982			664,832


Operating income		24,524			61,880			35,915			62,834

Loss on asset sales and disposal		(2,191	)		(16	)		(2,893	)		(7,021	)
Interest expense		(27,531	)		(10,294	)		(53,341	)		(19,385	)
Loss on early extinguishment of debt		(19	)		—			(26,601	)		—


Net income (loss) before tax		(5,217	)		51,570			(46,920	)		36,428
Income tax benefit		28			—			37			—

Net income (loss)		(5,189	)		51,570			(46,883	)		36,428
Loss (income) attributable to non-controlling interests		(3,058	)		(59,191	)		26,040			(62,556	)

Net loss attributable to common limited partners	$	(8,247	)	$	(7,621	)	$	(20,843	)	$	(26,128	)


Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.16	)	$	(0.15	)	$	(0.41	)	$	(0.51	)


Weighted average common limited partner units outstanding:
Basic and Diluted		51,380			51,318			51,375			51,306


	Common Limited Partners’ Capital					Accumulated Other Comprehensive Income		Non-Controlling Interest			Total Partners’ Capital
	Units		Amount			Accumulated Other Comprehensive Income		Non-Controlling Interest			Total Partners’ Capital
Balance at January 1, 2013		51,365,582	$	456,171		$	9,699	$	2,013,978		$	2,479,848
Distributions to non-controlling interests		—		—			—		(102,673	)		(102,673	)
Contributions from non-controlling interests		—		—			—		4,676			4,676
Unissued common units under incentive plan		—		11,085			—		14,843			25,928
Issuance of units under incentive plans		19,234		—			—		84			84
Distributions paid to common limited partners		—		(31,338	)		—		—			(31,338	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(1,387	)		—		(2,196	)		(3,583	)
Atlas Pipeline Partners, L.P. purchase price allocation		—		—			—		(30,607	)		(30,607	)
Gain on issuance of Atlas Resource Partners, L.P.’s common units		—		25,221			—		(25,221	)		—
Gain on issuance of Atlas Pipeline Partners, L.P.’s common units		—		9,899			—		(9,899	)		—
Non-controlling interests’ capital contribution		—		—			—		1,145,456			1,145,456
Other comprehensive income		—		—			4,228		11,930			16,158
Net loss		—		(20,843	)		—		(26,040	)		(46,883	)

Balance at June 30, 2013		51,384,816	$	448,808		$	13,927	$	2,994,331		$	3,457,066

Liabilities:
Asset retirement obligation		14,142
Net assets acquired	$	705,976

Accounts receivable		5,253
Prepaid expenses and other		131
Total current assets		5,756

Property, plant and equipment		208,491
Other assets, net		2,344
Total assets acquired	$	216,591

Liabilities:
Accounts payable	$	676
Revenue distribution payable		3,091
Accrued liabilities		1,816
Total current liabilities		5,583

Asset retirement obligation and other		2,418
Total liabilities assumed		8,001
Net assets acquired	$	208,590


Assets:
Natural gas and oil properties	$	190,946

Liabilities:
Asset retirement obligation		3,903


Net assets acquired	$	187,043


	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets

As of June 30, 2013
Current portion of derivative assets	$	3,592	$	—	$	3,592
Long-term portion of derivative assets		—		—		—
Current portion of derivative liabilities		—		—		—
Long-term portion of derivative liabilities		—		—		—


Total derivative assets	$	3,592	$	—	$	3,592


As of December 31, 2012
Current portion of derivative assets	$	—	$	—	$	—
Long-term portion of derivative assets		—		—		—
Current portion of derivative liabilities		—		—		—
Long-term portion of derivative liabilities		—		—		—


Total derivative assets	$	—	$	—	$	—


	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets

As of June 30, 2013
Current portion of derivative assets	$	25,877		$	(642	)	$	25,235
Long-term portion of derivative assets		15,630			(1,039	)		14,591
Current portion of derivative liabilities		5			(5	)		—


Total derivative assets	$	41,512		$	(1,686	)	$	39,826


As of December 31, 2012
Current portion of derivative assets	$	23,534		$	(457	)	$	23,077
Long-term portion of derivative assets		9,637			(1,695	)		7,942


Total derivative assets	$	33,171		$	(2,152	)	$	31,019


	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities

As of June 30, 2013
Current portion of derivative assets	$	(642	)	$	642		$	—
Long-term portion of derivative assets		(1,039	)		1,039			—
Current portion of derivative liabilities		(100	)		5			(95	)

Total derivative liabilities	$	(1,781	)	$	1,686		$	(95	)


As of December 31, 2012
Current portion of derivative liabilities	$	(457	)	$	457		$	—
Long-term portion of derivative liabilities		(1,695	)		1,695			—


Total derivative liabilities	$	(2,152	)	$	2,152		$	—


Production Period	Purchased/ Sold	Type Commodity		Volumes⁽²⁾		Average Strike Price		Fair Value⁽¹⁾ Asset (in thousands)

Natural Gas
2014	Purchased	Put	Natural Gas		600,000	$	4.125	$	319

Natural Gas Liquids
2013	Purchased	Put	Natural Gas Liquids		23,184,000	$	1.897		6,646
2014	Purchased	Put	Natural Gas Liquids		3,150,000	$	1.030		377
2015	Purchased	Put	Natural Gas Liquids		1,260,000	$	0.883		183

Crude Oil
2013	Purchased	Put	Crude Oil		147,000	$	100.100		989
2014	Purchased	Put	Crude Oil		448,500	$	94.685		4,313
2015	Purchased	Put	Crude Oil		270,000	$	89.175		2,953


Total Options								$	15,780


Total APL net assets								$	39,731


	Gallons		Third Party Quotes⁽¹⁾			Adjustments⁽²⁾			Total Amount
As of June 30, 2013
Propane swaps		81,900	$	16,565		$	(180	)	$	16,385
Isobutane swaps		5,040		(1,072	)		752			(320	)
Normal butane swaps		3,780		952			169			1,121
Natural gasoline swaps		16,002		6,460			(2,274	)		4,186

Total NGL swaps – June 30, 2013		106,722	$	22,905		$	(1,533	)	$	21,372


As of December 31, 2012
Propane swaps		69,678	$	16,302		$	(552	)	$	15,750
Isobutane swaps		1,134		(219	)		187			(32	)
Normal butane swaps		6,174		(909	)		242			(667	)
Natural gasoline swaps		10,080		3,247			(1,484	)		1,763

Total NGL swaps – December 31, 2012		87,066	$	18,421		$	(1,607	)	$	16,814


				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of June 30, 2013
Propane swaps	$	(180	)		0.8951		0.9050		0.9001
Isobutane swaps		752			1.1225		1.1319		1.1272
Normal butane swaps		169			1.0361		1.0405		1.0383
Natural gasoline swaps		(2,274	)		0.9116		0.9321		0.9219


Total NGL swaps – June 30, 2013	$	(1,533	)


As of December 31, 2012
Propane swaps	$	(552	)		0.9019		0.9122		0.9071
Isobutane swaps		187			1.1285		1.1376		1.1331
Normal butane swaps		242			1.0370		1.0416		1.0393
Natural gasoline swaps		(1,484	)		0.8988		0.9169		0.9078


Total NGL swaps – December 31, 2012	$	(1,607	)


	Three Months Ended June 30,
	2013				2012
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	599	$	599	$	3,911	$	3,911

Total	$	599	$	599	$	3,911	$	3,911


	Six Months Ended June 30,
	2013				2012
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	1,244	$	1,244	$	4,092	$	4,092

Total	$	1,244	$	1,244	$	4,092	$	4,092


	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013

Deferred benefit:
Federal	$	(25	)	$	(33	)
State		(3	)		(4	)

Total income tax benefit	$	(28	)	$	(37	)


Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partners

May 18, 2012	March 31, 2012	$	0.25	$	12,830
August 17, 2012	June 30, 2012	$	0.25	$	12,831
November 19, 2012	September 30, 2012	$	0.27	$	13,866
February 19, 2013	December 31, 2012	$	0.30	$	15,410

May 20, 2013	March 31, 2013	$	0.31	$	15,928



Production per day:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	30,715	33,290	31,139	31,625
Oil (Bpd)	283	274	280	281
Natural gas liquids (Bpd)	2	10	2	20

Total (Mcfed)	32,421	34,995	32,830	33,429

Barnett/Marble Falls:
Natural gas (Mcfd)	66,407	19,506	66,239	9,753
Oil (Bpd)	863	—	821	—
Natural gas liquids (Bpd)	2,748	32	2,653	16

Total (Mcfed)	88,070	19,699	87,086	9,849

Mississippi Lime/Hunton:
Natural gas (Mcfd)	3,978	—	4,365	—
Oil (Bpd)	115	—	72	—
Natural gas liquids (Bpd)	245	—	244	—

Total (Mcfed)	6,138	—	6,265	—

Other Operating Areas:⁽³⁾
Natural gas (Mcfd)	4,538	5,226	4,699	5,163
Oil (Bpd)	20	16	17	17
Natural gas liquids (Bpd)	392	421	393	407

Total (Mcfed)	7,012	7,847	7,161	7,703

Total:
Natural gas (Mcfd)	105,638	58,022	106,442	46,541
Oil (Bpd)	1,281	290	1,191	297
Natural gas liquids (Bpd)	3,386	463	3,292	443

Total (Mcfed)	133,641	62,541	133,341	50,981


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

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

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

10.4		Atlas Pipeline Partners, L.P.’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Convertible Preferred Units, dated as of May 7, 2013⁽³⁹⁾


~~Exhibit~~ ~~No.~~	~~Description~~

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

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

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

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

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

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

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

10.18	Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾


~~Exhibit~~ ~~No.~~		~~Description~~
10.22
~~10.22~~		Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.⁽¹²⁾

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

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

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

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

10.27		Employment Agreement between Atlas Energy, L.P. and Daniel Herz dated as of November 4, 2011

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

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

10.30		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010⁽²²⁾

10.31		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010⁽²²⁾

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

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


~~Exhibit~~ ~~No.~~		~~Description~~
10.35
~~10.35~~		Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan⁽²⁸⁾

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

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

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

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

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

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

10.42		Registration Rights Agreement, dated September 28, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽⁴¹⁾

~~10.43~~		Registration Rights Agreement, dated December 20, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽⁴²⁾

~~10.44~~		Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.⁽⁴³⁾

~~10.45~~ 10.43		Purchase and Sale Agreement, dated as of April 16, 2013, among TEAK Midstream Holdings, LLC, TEAK Midstream, L.L.C. and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Registration S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request⁽²⁹⁾

~~10.46~~ 10.44		Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein⁽³⁸⁾

~~10.47~~ 10.45		Class D Preferred Unit Purchase Agreement, dated as of April 16, 2013, among Atlas Pipeline Partners, L.P. and the various purchasers party thereto⁽²⁹⁾

~~10.48~~ 10.46		Registration Rights Agreement, dated May 7, 2013, by and among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽³⁹⁾

~~10.49~~ 10.47		Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.⁽⁴⁷⁾

~~10.50~~ 10.48		Warrant to Purchase Common Units⁽⁴⁴⁾


~~Exhibit~~ ~~No.~~		~~Description~~
10.49
~~10.51~~		Distribution Agreement dated as of May 10, 2013, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents⁽⁴⁸⁾

~~10.52~~ 10.50		Class C Preferred Unit Purchase Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P.⁽⁵⁰⁾