Targa Energy LP - FORM 10-Q - November 9, 2010

Attached files

file	filename
EX-31.1 - SECTION 302 CEO CERTIFICATION - Targa Energy LP	dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Targa Energy LP	dex312.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - Targa Energy LP	dex321.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - Targa Energy LP	dex322.htm
EX-10.18 - LETTER AGREEMENT - Targa Energy LP	dex1018.htm

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 September 30, 2010

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

For the transition period from to

Commission file number: 1-32953

ATLAS PIPELINE HOLDINGS, L.P.

(Exact name of registrant as specified in its charter)


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

1550 Coraopolis Heights Road Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

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

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

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

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


Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	x (Do not check if a 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 common units of the registrant outstanding on November 3, 2010 was 27,703,704.

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q


		PAGE
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009 (Unaudited)		3

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009 (Unaudited)		4

	Consolidated Statement of Equity for the Nine Months Ended September 30, 2010 (Unaudited)		5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009 (Unaudited)		6

	Notes to Consolidated Financial Statements (Unaudited)		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		36

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56

Item 4.	Controls and Procedures		58

PART II.	OTHER INFORMATION

Item 1A.	Risk Factors		59

Item 6.	Exhibits		60

SIGNATURES

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands)


	September 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	215		$	1,103
Accounts receivable		59,421			80,019
Current portion of derivative asset		3,611			998
Prepaid expenses and other		14,883			13,360
Current assets of discontinued operations		—			22,746

Total current assets		78,130			118,226

Property, plant and equipment, net		1,339,730			1,327,704
Intangible assets, net		132,154			149,481
Investment in joint venture		135,765			132,990
Long-term portion of derivative asset		—			361
Other assets, net		23,564			30,326
Long-term assets of discontinued operations		—			379,030

Total assets	$	1,709,343		$	2,138,118


LIABILITIES AND EQUITY

Current liabilities:
Current portion of long-term debt	$	34,589		$	32,255
Accounts payable – affiliates		10,708			2,304
Accounts payable		9,919			19,556
Accrued liabilities		32,516			13,521
Accrued interest payable		12,340			9,652
Current portion of derivative liability		1,511			33,833
Accrued producer liabilities		58,143			57,430
Current liabilities of discontinued operations		—			13,181

Total current liabilities		159,726			181,732

Long-term portion of derivative liability		5,770			11,126
Long-term debt, less current portion		507,676			1,254,183
Other long-term liability		266			398

Commitments and contingencies

Equity:
Common limited partners’ interests		22,840			(7,756	)
Accumulated other comprehensive loss		(1,693	)		(6,551	)

Total partners’ capital		21,147			(14,307	)
Non-controlling interests		(31,712	)		(30,925	)
Non-controlling interest in Atlas Pipeline Partners, L.P.		1,046,470			735,911

Total equity		1,035,905			690,679

Total liabilities and equity	$	1,709,343		$	2,138,118

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenue:
Natural gas and liquids – third parties	$	220,478		$	161,365		$	641,978		$	434,780
Transportation, processing and other fees – third parties		9,810			11,518			29,472			32,025
Transportation, processing and other fees – affiliates		141			384			472			16,881
Other income (loss), net – third parties		(4,310	)		2,946			10,551			(13,380	)

Total revenue and other income (loss), net		226,119			176,213			682,473			470,306

Costs and expenses:
Natural gas and liquids – third parties		178,920			131,503			521,495			368,658
Plant operating		12,552			11,663			36,492			33,065
Transportation and compression		300			134			721			6,256
General and administrative		7,662			9,107			24,225			25,461
Compensation reimbursement – affiliates		375			375			1,125			1,125
Depreciation and amortization		18,566			17,916			55,647			55,567
Interest		28,448			29,300			80,588			77,924

Total costs and expenses		246,823			199,998			720,293			568,056

Equity income in joint venture		1,787			1,430			4,137			2,140
Gain (loss) on asset sale		—			(994	)		—			108,947

Income (loss) from continuing operations		(18,917	)		(23,349	)		(33,683	)		13,337

Discontinued operations:
Gain on sale of discontinued operations		311,492			—			311,492			51,078
Earnings from discontinued operations		(5,565	)		9,215			9,192			30,163

Income from discontinued operations		305,927			9,215			320,684			81,241

Net income (loss)		287,010			(14,134	)		287,001			94,578
Income attributable to non-controlling interests		(1,076	)		(954	)		(3,338	)		(2,075	)
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.		(251,488	)		11,487			(251,721	)		(82,201	)

Net income (loss) attributable to common limited partners	$	34,446		$	(3,601	)	$	31,942		$	10,302

Amounts attributable to common limited partners:
Continuing operations	$	(3,552	)	$	(4,843	)	$	(7,918	)	$	(1,188	)
Discontinued operations		37,998			1,242			39,860			11,490

Net income (loss) attributable to common limited partners	$	34,446		$	(3,601	)	$	31,942		$	10,302

Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations Basic	$	(0.13	)	$	(0.18	)	$	(0.29	)	$	(0.04	)
Discontinued operations		1.37			0.04			1.44			0.41

	$	1.24		$	(0.14	)	$	1.15		$	0.37

Diluted:
Continuing operations Basic	$	(0.13	)	$	(0.18	)	$	(0.29	)	$	(0.04	)
Discontinued operations		1.37			0.04			1.44			0.41

	$	1.24		$	(0.14	)	$	1.15		$	0.37

Weighted average common limited partner units outstanding:
Basic		27,704			27,659			27,704			27,659

Diluted		27,704			27,659			27,704			27,659

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010

(in thousands, except unit data)

(Unaudited)


	Common Limited Partners’ Capital					Accumulated Other Comprehensive Income (Loss)			Non- Controlling Interests			Non-Controlling Interest in Atlas Pipeline Partners L.P.			Total
	Units		$						Non- Controlling Interests						Total
Balance at January 1, 2010		27,703,579	$	(7,756	)	$	(6,551	)	$	(30,925	)	$	735,911		$	690,679
Issuance of common limited partner units		—		—			—			—			15,319			15,319
Issuance of subsidiary preferred units		—		—			—			—			8,000			8,000
Distributions to non-controlling interests		—		—			—			(4,125	)		—			(4,125	)
Distributions payable		—		—			—			—			(240	)		(240	)
Unissued common units under incentive plans		—		1,082			—			—			2,791			3,873
Issuance of units under incentive plans		125		—			—			—			19			19
Repurchase and retirement of common limited partner units		—		—			—			—			(246	)		(246	)
Net loss on purchase and sale of subsidiary equity		—		(2,428	)		—			—			2,428			—
Other comprehensive income		—		—			4,859			—			30,766			35,625
Net income (loss)		—		31,942			—			3,338			251,721			287,001

Balance at September 30, 2010		27,703,704	$	22,840		$	(1,692	)	$	(31,712	)	$	1,046,469		$	1,035,905

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	287,001		$	94,578
Less: Income from discontinued operations		320,684			81,241

Net income (loss) from continuing operations		(33,683	)		13,337
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by operating activities:
Depreciation and amortization		55,647			55,567
Equity income in joint venture		(4,137	)		(2,140	)
Distribution received from joint venture		8,276			1,657
Gain on asset sale		—			(108,947	)
Non-cash compensation expense		3,892			645
Amortization of deferred finance costs		9,161			6,542
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable, prepaid expenses and other		19,075			22,342
Accounts payable and accrued liabilities		13,431			7,018
Derivative accounts payable and accounts receivable		(4,304	)		24,253
Accounts payable and accounts receivable – affiliates		8,404			9,621

Net cash provided by continuing operations		75,762			29,895
Net cash provided by discontinued operations		24,490			19,420

Net cash provided by operations		100,252			49,315

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(31,194	)		(115,132	)
Capital contributions to joint venture		(6,914	)		—
Net proceeds from asset sale		—			87,797
Other		391			(2,012	)

Net cash used in continuing investing activities		(37,717	)		(29,347	)
Net cash provided by discontinued investing activities		667,605			288,109

Net cash provided by investing activities		629,888			258,762

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		273,000			483,000
Repayments under credit facilities		(595,000	)		(504,000	)
Repayment of Atlas Pipeline Partners, L.P. debt		(433,504	)		(273,675	)
Principal payments on Atlas Pipeline Partners, L.P. capital lease		(92	)		—
Net proceeds from subordinate loan with and advances from Atlas Energy, Inc.		8,000			19,000
Net proceeds from issuance of Atlas Pipeline Partners, L.P. common limited partner units		15,319			11,187
Net proceeds from issuance of Atlas Pipeline Partners, L.P. preferred units		8,000			4,955
Redemption of Atlas Pipeline Partners, L.P. Class A preferred units		—			(15,000	)
Distributions paid to common limited partners		—			(1,660	)
Distributions paid to non-controlling interests in Atlas Pipeline Partners, L.P.		—			(22,337	)
Net distributions (received from) to non-controlling interests		(4,125	)		7
Other		(2,626	)		(11,251	)

Net cash used in financing activities		(731,028	)		(309,774	)

Net change in cash and cash equivalents		(888	)		(1,697	)
Cash and cash equivalents, beginning of period		1,103			7,285

Cash and cash equivalents, end of period	$	215		$	5,588

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or the “Partnership”) is a publicly-traded Delaware limited partnership (NYSE: AHD). The Partnership’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or “General Partner”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”), which does not have an economic interest in the Partnership and is not entitled to receive any distributions from the Partnership, manages the operations and activities of the Partnership and owes a fiduciary duty to the Partnership’s common unitholders. At September 30, 2010, the Partnership had 27,703,704 common limited partnership units outstanding.

APL is a publicly-traded Delaware limited partnership and a midstream energy service provider engaged in the gathering and processing of natural gas. APL’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of APL. At September 30, 2010, the Partnership, through its general partner interests in APL and the Operating Partnership, owns a 1.9% general partner interest in the consolidated pipeline operations of APL, through which it manages and effectively controls both APL and the Operating Partnership. The remaining 98.1% ownership interest in the consolidated pipeline operations consists of limited partner interests in APL. The Partnership also owns 5,754,253 common units in APL and 15,000 $1,000 par value 12% cumulative Class B preferred limited partner units in APL. At September 30, 2010, APL had 53,303,635 common units outstanding, including the 5,754,253 common units held by the Partnership, plus 15,000 $1,000 par value 12% cumulative Class B preferred limited partner units held by the Partnership and 8,000 $1,000 par value 12% cumulative Class C preferred limited partner units held by Atlas Energy, Inc. (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS) (see Note 6).

On March 31, 2010, APL’s limited partnership agreement was amended to provide a temporary waiver of a capital contribution required for Atlas Pipeline GP to maintain its 2.0% general partner interest in APL, relative to the January 2010 issuance of APL common units for warrants exercised. Atlas Pipeline GP will not be required to make such capital contribution until it has received aggregate distributions from APL sufficient to fund the required capital contribution. During this waiver period Atlas Pipeline GP’s interest in APL and the Operating Partnership will be reduced by approximately 0.1% to 1.9% (see Note 5).

The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which as of September 30, 2010, together with the Partnership, owns:

•

a 1.9% general partner interest in APL, which entitles it to receive 1.9% of the cash distributed by APL;

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights;

•

5,754,253 common units of APL, representing approximately 10.8% of the 53,303,635 outstanding common units of APL, and

•

15,000 $1,000 par value 12% cumulative Class B preferred limited partner units of APL.

The Partnership, as general partner, manages the operations and activities of APL and owes a fiduciary duty to APL’s common unitholders. The Partnership is liable, as general partner, for all of APL’s debts (to the extent not paid from APL’s assets), except for indebtedness or other obligations that are made specifically non-recourse to the Partnership. The Partnership does not receive any management fee or other compensation for its management of APL. The Partnership and its affiliates are reimbursed for expenses incurred on APL’s behalf. These expenses include the costs of employee, officer, and managing board member compensation and benefits properly allocable to APL and all other expenses necessary or appropriate to conduct the business of, and allocable to, APL. The APL partnership agreement provides that the Partnership, as general partner, will determine the expenses that are allocable to APL in any reasonable manner in its sole discretion.

Atlas Energy owned 100% of Atlas Pipeline Holdings GP and a 64.3% ownership interest in the common units of the Partnership at September 30, 2010. In addition to its ownership interest in the Partnership, Atlas Energy also owned, at September 30, 2010, 1,112,000 of APL’s common limited partnership units, representing a 2.1% ownership interest in APL and 8,000 APL $1,000 par value 12% cumulative Class C preferred limited partner units (see Note 6).

The majority of the natural gas that APL and its affiliates, including Laurel Mountain Midstream LLC (“Laurel Mountain”), gather in Appalachia is derived from wells operated by Atlas Energy. Laurel Mountain, which was formed in May 2009, is a joint venture between APL and The Williams Companies, Inc. (NYSE: WMB) (“Williams”) in which APL has a 49% non-controlling ownership interest and Williams holds the remaining 51% ownership interest.

The Partnership has adjusted its consolidated financial statements and related footnote disclosures presented within this Form 10-Q from the amounts previously presented to reflect the following items:

•

On January 1, 2010, the Partnership reclassified a portion of its historical income, within its consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids”. This reclassification was made in order to provide clarity between the revenue that is commodity-based and the revenue that is fee-based; and

•

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems (see Note 4). The Partnership has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of Elk City as discontinued operations.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2009 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated 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, 2009. The results of operations for the three and nine month periods ended September 30, 2010 may not necessarily be indicative of the results of operations for the full year ending December 31, 2010. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2009.

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Partnership, the General Partner, APL, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. All material intercompany transactions have been eliminated.

The Partnership’s consolidated financial statements also include APL’s 95% interest in joint ventures which individually own a 100% interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% interest in the joint ventures as non-controlling interests on its statements of operations. The Partnership also reflects the 5% interest in the net assets of the joint ventures as non-controlling interests and as a component of equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% interest in the joint ventures, which is reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

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

Non-Controlling Interest in Atlas Pipeline Partners, L.P.

The non-controlling interest in APL on the Partnership’s consolidated financial statements reflects the outside ownership interests in APL, which was 87.6% and 86.8% at September 30, 2010 and December 31, 2009, respectively. The non-controlling interests in APL in the Partnership’s consolidated statements of operations is calculated quarterly by multiplying (i) the weighted average APL common limited partner units outstanding held by non-affiliated third parties by (ii) the consolidated net income (loss) per APL common limited partner unit for the respective quarter. The net income (loss) per APL common limited partner unit is calculated by dividing (i) the net income (loss) allocated to common limited partners, after the allocation of net income (loss) to the Partnership as general partner in accordance with the terms of the APL partnership agreement, by (ii) the total weighted average APL common limited partner units outstanding. The Partnership’s general partner interest in the net income (loss) of APL is based upon its 1.9% general partner ownership interest and incentive distributions, with a priority allocation of APL’s net income (loss) in an amount equal to the incentive distributions, in accordance with the APL partnership agreement, and the remaining APL net income (loss) allocated with respect to the general partner’s and APL’s limited partners’ ownership interests. The non-controlling interest in APL on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL’s consolidated net income (loss) to the non-controlling interest in APL and the contributed capital of non-controlling interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the non-controlling interest owners.

During the nine months ended September 30, 2010, APL’s warrant holders exercised their warrants to purchase 2,689,765 common units (see Note 5). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2.0% interest as general partner (see Note 1), was reduced. During the nine months ended September 30, 2010, the Partnership recorded a $2.4 million increase to non-controlling interest in APL with a corresponding decrease to its Partners’ capital, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheet.

Equity Method Investments

The Partnership’s consolidated financial statements include APL’s 49% non-controlling ownership interest in Laurel Mountain, a joint venture which owns and operates APL’s former Appalachia Basin natural gas gathering systems, excluding APL’s northeastern Tennessee operations. The Partnership accounts for APL’s investment in the joint venture under the equity method of accounting. Under this method, the Partnership records APL’s proportionate share of the joint venture’s net income (loss) as equity income on its consolidated statements of operations.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements 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 expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation and amortization, asset impairment, the fair value of the Partnership’s and APL’s derivative instruments, the probability of forecasted transactions, APL’s allocation of purchase price to the fair value of assets it acquired, and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented represent actual results in all material respects (see “-Revenue Recognition” accounting policy for further description).

Receivables

The amounts included within accounts receivable on the Partnership’s consolidated balance sheet at September 30, 2010 and December 31, 2009 are associated entirely with APL’s operating activities. In evaluating the realizability of its accounts receivable, 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 APL’s review of its customers’ credit information. APL extends credit on an unsecured basis to many of its customers. At September 30, 2010 and December 31, 2009, APL recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Capitalized Interest

APL capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by APL was 7.7% and 7.4% for the three months ended September 30, 2010 and 2009, respectively, and 7.5% and 6.0% for the nine months ended September 30, 2010 and 2009, respectively. The amount of interest capitalized was $0.2 million and $0.6 million for the three months ended September 30, 2010 and 2009, respectively, and $0.6 million and $2.4 million for the nine months ended September 30, 2010 and 2009, respectively.

Intangible Assets

APL has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at September 30, 2010 and December 31, 2009 (dollars in thousands):


	September 30, 2010			December 31, 2009⁽¹⁾			Estimated Useful Lives In Years
Customer Relationships:
Gross carrying amount		205,313			205,313			7–20
Accumulated amortization		(73,159	)		(55,832	)

Net carrying amount		132,154			149,481

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

APL amortizes intangible assets with finite useful lives 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 management’s estimate of whether these individual relationships will continue in excess or less than the average length. Amortization expense on intangible assets was $5.8 million for both the three month periods ended September 30, 2010 and 2009, and $17.3 million for both the nine month periods ended September 30, 2010 and 2009. Amortization expense related to intangible assets is estimated to be as follows for each of the next five calendar years: 2010 to 2013 - $23.1 million per year; and 2014 - $19.5 million.

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 plan and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income (loss) utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Continuing operations:
Net income (loss)	$	(18,917	)	$	(23,349	)	$	(33,683	)	$	13,337
Income attributable to non-controlling interests		(1,076	)		(954	)		(3,338	)		(2,075	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		16,441			19,460			29,103			(12,450	)

Net income (loss) attributable to common limited partners		(3,552	)		(4,843	)		(7,918	)		(1,188	)
Less: Net income attributable to participating securities – phantom units⁽²⁾		—			—			—			—

Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit	$	(3,552	)	$	(4,843	)	$	(7,918	)	$	(1,188	)


Discontinued operations:
Net income	$	305,927		$	9,215		$	320,684		$	81,241
Income attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		(267,929	)		(7,973	)		(280,824	)		(69,751	)

Net income utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit	$	37,998		$	1,242		$	39,860		$	11,490

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

(2)

Net income attributable to common limited partners’ ownership interest is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended September 30, 2010 and 2009, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 144,000 and 182,000 phantom units, respectively, and for the nine months ended September 30, 2010 and 2009, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 141,000 and 191,000 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 by the sum of the weighted average number of common limited partner units outstanding, including participating securities, plus 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 plan (see Note 14).

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Weighted average number of common limited partner units – basic		27,704		27,659		27,704		27,659
Add effect of participating securities – phantom units⁽¹⁾		—		—		—		—
Add effect of dilutive option incentive awards⁽²⁾		—		—		—		—

Weighted average number of common limited partner units – diluted		27,704		27,659		27,704		27,659

(1)

For the three months ended September 30, 2010 and 2009, approximately 144,000 and 182,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit and for the nine months ended September 30, 2010 and 2009, approximately 141,000 and 191,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such phantom units would have been anti-dilutive.

(2)	For the three and nine months ended September 30, 2010 and 2009, approximately 1.0 million unit options were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive.

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. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” or “OCI” and for the Partnership only include changes in the fair value of unsettled derivative contracts which were accounted for as cash flow hedges (see Note 10). The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Net income (loss)	$	287,010		$	(14,134	)	$	287,001		$	94,578
Income attributable to non-controlling interests		(1,076	)		(954	)		(3,338	)		(2,075	)
(Income) loss attributable to non-controlling interests - Atlas Pipeline Partners, L.P.		(251,488	)		11,487			(251,721	)		(82,201	)

Net income (loss) attributable to common limited partners		34,446			(3,601	)		31,942			10,302

Other comprehensive income:
Change in fair value of derivative instruments accounted for as cash flow hedges		—			(165	)		—			(2,411	)
Changes in non-controlling interest related to items in other comprehensive income (loss)		(12,302	)		(11,286	)		(30,766	)		(36,982	)
Add: adjustment for realized losses reclassified to net income		14,122			13,713			35,625			46,757

Total other comprehensive income		1,820			2,262			4,859			7,364

Comprehensive income (loss)	$	36,266		$	(1,339	)	$	36,801		$	17,666

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

Revenue Recognition

APL’s revenue primarily consists of the fees earned from its gathering and processing operations. 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, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas. APL is also paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through APL’s 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 natural gas and NGLs APL 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. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to NGLs extracted when processed through a plant. APL must make up or “keep the producer whole” for this loss in volume. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the volume of residue gas available for redelivery to the producer may be less than APL received from the producer; or (ii) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that APL 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 Keep-Whole agreements is often 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 of margin risk.

APL accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from APL’s records and management estimates of the related gathering and compression fees which are, in turn, based upon applicable product prices (see “-Use of Estimates” accounting policy for further description). APL had unbilled revenues at September 30, 2010 and December 31, 2009 of $37.7 million and $61.2 million, respectively, which are included in accounts receivable within the Partnership’s consolidated balance sheets.

Recently Adopted Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements,” which provides enhanced disclosure requirements for activity in Levels 1, 2 and 3 fair value measurements. The update requires significant transfers in and out of Levels 1 and 2 fair value measurements to be reported separately and the reasons for such transfers to be disclosed. The update also requires information regarding purchases, sales, issuances, and settlements to be disclosed separately on a gross basis in the reconciliation of fair value measurements using unobservable inputs for all activity in Level 3 fair value measurements. Additionally, the update clarifies that fair value measurement for each class of assets and liabilities must be disclosed as well as disclosures pertaining to the inputs and valuation techniques for both recurring and nonrecurring fair value measurements in Levels 2 and 3. These requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those requirements will be effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Partnership adopted these requirements on January 1, 2010 and it did not have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates APL’s previously owned Appalachia natural gas gathering system, excluding APL’s northeastern Tennessee operations. Williams contributed cash and a note receivable of $25.5 million to the joint venture and owns 51% interest in Laurel Mountain. APL contributed the Appalachia natural gas gathering system and owns a 49% interest in Laurel Mountain. APL is required to make capital contributions to Laurel Mountain equal to 49% of any capital calls, in order to maintain its current ownership interest in the joint venture. APL is also entitled to preferred distribution rights relating to all payments on the note receivable, up to $7.5 million per annual period. Williams performs the day to day operations of the joint venture.

APL recognizes its 49% ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheet. APL accounts for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain as equity income on its consolidated statements of operations. During the three and nine months ended September 30, 2010, APL utilized $8.5 million and $15.3 million of the $25.5 million note receivable, respectively, and made cash payments of $1.3 million and $6.9 million, respectively, to make capital contributions to Laurel Mountain. As of September 30, 2010, APL has utilized $17.0 million of the $25.5 million note receivable

The following table provides the joint venture’s summarized statement of operations for the three and nine months ended September 30, 2010 and 2009 and balance sheet data as of September 30, 2010 and December 31, 2009 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009⁽¹⁾
Statement of Operations data:
Total revenue	$	11,533	$	9,622	$	33,046	$	12,690
Net income		2,349		2,386		6,441		3,664

(1)	Represents the period from May 31, 2009, the date of initial formation, through September 30, 2009.


	September 30, 2010		December 31, 2009
Balance Sheet data:
Current assets	$	14,815	$	12,193
Long-term assets		286,639		248,730
Current liabilities		16,656		19,724
Long-term liabilities		1,310		9,555
Net equity		283,488		231,644

NOTE 4 – DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”). APL accounted for the earnings of the NOARK system assets as discontinued operations within the Partnership’s consolidated financial statements and recorded a gain of $51.1 million on the sale of the NOARK assets within income from discontinued operations on the Partnership’s consolidated statements of operations during the nine months ended September 30, 2009.

for $682.0 million in cash, excluding any working capital adjustment or transactions costs. APL accounted for the earnings of Elk City as discontinued operations within the Partnership’s consolidated financial statements and recorded a gain of $311.5 million on the sale of Elk City within income from discontinued operations on the Partnership’s consolidated statements of operations during the three and nine months ended September 30, 2010.

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


	Three Months Ended						Nine Months Ended
	September 30, 2010			September 30, 2009			September 30, 2010			September 30, 2009
NOARK
Total revenue and other loss, net	$	—		$	—		$	—		$	21,274
Total costs and expenses		—			—			—			(9,857	)
Gain on asset sale		—			—			—			51,078

Income from NOARK discontinued operations		—			—			—			62,495


Elk City
Total revenue and other loss, net		29,912			43,764			129,928			127,466
Total costs and expenses		(35,477	)		(37,042	)		(120,736	)		(111,213	)
Gain on asset sale		311,492			2,493			311,492			2,493

Income from Elk City discontinued operations		305,927			9,215			320,684			18,746

Total income from discontinued operations	$	305,927		$	9,215		$	320,684		$	81,241

The following table summarizes the components included within total assets and liabilities of discontinued operations within the Partnership’s consolidated balance sheet at December 31, 2009, related to Elk City.


	December 31, 2009
	December 31, 2009
Cash and cash equivalents	$	—
Accounts receivable		20,702
Prepaid expenses and other		2,044

Total current assets of discontinued operations		22,746

Property, plant and equipment, net		356,680
Intangible assets, net		18,610
Other assets, net		3,740

Total assets of discontinued operations	$	401,776


Accounts payable	$	3,372
Accrued liabilities		1,028
Accrued producer liabilities		8,781

Total current liabilities of discontinued operations	$	13,181

NOTE 5 – APL COMMON UNIT EQUITY OFFERING

On January 7, 2010, APL executed amendments to the warrants originally issued in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 per unit from $6.35 per unit. In connection with the amendments, the holders of the

warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million to APL. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 12) and to fund the early termination of certain APL derivative agreements (see Note 10).

The common units and warrants sold by APL in the August 2009 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required APL to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.

On March 31, 2010, APL and the Operating Partnership amended their respective partnership agreements to temporarily waive the requirement that Atlas Pipeline GP make aggregate cash contributions of approximately $0.3 million, which was required in connection with APL’s issuance of 2,689,765 of its common units upon the exercise of warrants in January 2010. The waiver will remain in effect until Atlas Pipeline GP has received aggregate distributions from APL sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to Atlas Pipeline GP’s general partner interest in APL and the Operating Partnership is reduced to 1.9%. Both amendments were approved by APL’s conflicts committee and managing board, and are effective as of January 11, 2010.

NOTE 6 – APL PREFERRED UNIT EQUITY OFFERINGS

On June 30, 2010, APL sold 8,000 newly-created 12% Cumulative Class C Preferred Units of limited partner interest (the “APL Class C Preferred Units”) to Atlas Energy for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). APL used the proceeds from the sale of the APL Class C Preferred Units for general partnership purposes. The APL Class C Preferred Units are entitled to receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The APL Class C Preferred Units are not convertible into APL common units. APL has the right at any time to redeem some or all of the outstanding APL Class C Preferred Units (but not less than 2,500 APL Class C Preferred Units) for cash at an amount equal to the APL Class C Preferred Face Value being redeemed plus accrued but unpaid dividends.

The sale of the APL Class C Preferred Units to Atlas Energy was exempt from the registration requirements of the Securities Act of 1933. The APL Class C Preferred Units are reflected on the Partnership’s consolidated balance sheet as Non-controlling interest in Atlas Pipeline Partners, L.P. within Equity.

NOTE 7 – CASH DISTRIBUTIONS

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, 2009 through September 30, 2010 were as follows:


Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners



				(in thousands)
February 19, 2009	December 31, 2008	$	0.06	$	1,660

There were no cash distributions declared by the Partnership for the quarters ended March 31, 2009 through June 30, 2010. On October 18, 2010, the Partnership declared a cash distribution of $0.05 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The $1.4 million distribution will be paid on November 16, 2010 to unitholders of record as of the close of business on November 8, 2010.

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 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by APL for the period from January 1, 2009 through September 30, 2010 were as follows:


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 the General Partner




				(in thousands)		(in thousands)
February 13, 2009	December 31, 2008	$	0.38	$	17,463	$	358
May 15, 2009	March 31, 2009		0.15		7,149		147

APL did not declare cash distributions for the quarters ended June 30, 2009 through June 30, 2010. On October 18, 2010, APL declared a cash distribution of $0.35 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The $19.0 million distribution, including $0.4 million to the Partnership for its general partner interest, will be paid on November 12, 2010 to unitholders of record as of the close of business on November 8, 2010.

NOTE 8 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (dollars in thousands):


	September 30, 2010			December 31, 2009⁽¹⁾			Estimated Useful Lives in Years


Pipelines, processing and compression facilities	$	1,327,455		$	1,281,366		2 – 40
Rights of way		156,239			152,908		20 – 40
Buildings		8,047			8,047		40
Furniture and equipment		9,166			8,848		3 – 7
Other		12,491			11,633		3 – 10

		1,513,398			1,462,802
Less – accumulated depreciation		(173,668	)		(135,098	)

	$	1,339,730		$	1,327,704

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see Note 4).

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 are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. The Partnership follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation. 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.

During the nine months ended September 30, 2010, APL entered into capital lease arrangements having obligations of $0.9 million at inception. Leased property and equipment meeting capital lease criteria are capitalized at the original cost of the equipment 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. APL did not enter into any capital lease arrangements during the nine months ended September 30, 2009, and had no capital lease obligations as of December 31, 2009.

NOTE 9 – OTHER ASSETS

The following is a summary of other assets (in thousands):


	September 30, 2010		December 31, 2009⁽¹⁾
Deferred finance costs, net of accumulated amortization of $34,911 and $25,752 at September 30, 2010 and December 31, 2009, respectively	$	21,035	$	27,404
Security deposits		2,529		2,922

	$	23,564	$	30,326

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see Note 4).

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12). In May 2009, APL recorded $2.3 million of accelerated amortization of deferred financing costs associated with the retirement of a portion of APL’s term loan with the proceeds from the sale of APL’s NOARK system (see Note 4). In September 2010, APL recorded $4.3 million of accelerated amortization of deferred financing costs associated with the retirement of APL’s term loan with the proceeds from the sale of APL’s Elk City assets (see Note 4). Total amortization expense of deferred finance costs for the Partnership and APL was $5.9 million and $1.8 million for the three months ended September 30, 2010 and 2009, respectively, and $9.2 million and $6.5 million for the nine months ended September 30, 2010 and 2009, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations. Amortization expense related to deferred finance costs is estimated to be as follows for each of the next five calendar years: 2010 – $10.6 million; 2011 to 2012 – $5.9 million per year; 2013 – $3.9 million; 2014 – $1.2 million.

NOTE 10 – DERIVATIVE INSTRUMENTS

The Partnership and APL use a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The Partnership and APL also previously entered into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to

exchange obligations of money as the underlying natural gas, NGLs and condensate are sold or interest payments on the underlying debt instrument are due. Under its swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

On July 1, 2008, APL discontinued hedge accounting for certain existing qualified crude oil derivatives, utilized to hedge forecasted NGL production, due to significant ineffectiveness. APL also discontinued hedge accounting for all of its other qualified commodity derivatives for consistency in reporting of all commodity-based derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in non-controlling interests and accumulated other comprehensive loss within Partners’ capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

The portion of any gain or loss in other comprehensive income related to originally forecasted transactions that are no longer expected to occur are removed from other comprehensive income and recognized within the statements of operations. In September 2010, APL sold its Elk City assets (see Note 4), thus the Partnership recognized a loss of $10.6 million within discontinued operations in the Partnership’s statements of operations with a corresponding decrease in non-controlling interests and accumulated other comprehensive loss within Partners’ capital on the Partnership’s consolidated balance sheet, since the related originally forecasted transactions related to the Elk City operations are no longer expected to occur. The $10.6 million loss reclassed from other comprehensive income includes $1.4 million related to derivatives which were settled early and $9.2 million related to derivatives which will settle in future periods.

The Partnership’s and APL’s derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. Premium costs for purchased options are recorded on the Partnership’s consolidated balance sheet as the initial value of the options. Changes in the fair value of the options are recognized within other income (loss), net as unrealized gain (loss) on the Partnership’s consolidated statements of operations. Premium costs are reclassified to realized gain (loss) within other income (loss), net at the time the option expires or is exercised. The Partnership reflected net derivative liabilities on its consolidated balance sheets of $3.7 million and $43.6 million at September 30, 2010 and December 31, 2009, respectively. The Partnership will reclassify $0.9 million of the $1.7 million net loss in accumulated other comprehensive loss within Partners’ capital on the Partnership’s consolidated balance sheet at September 30, 2010, to natural gas and liquids revenue on the Partnership’s consolidated statements of operations over the next twelve month period. Aggregate losses of $0.8 million will be reclassified to natural gas and liquids revenue on the Partnership’s consolidated statements of operations in later periods. At September 30, 2010, no derivative instruments are designated as hedges for hedge accounting purposes.

The fair value of the Partnership’s and APL’s derivative instruments was included in the Partnership’s consolidated balance sheets as follows (in thousands):


	September 30, 2010			December 31, 2009
Current portion of derivative asset	$	3,611		$	998
Long-term derivative asset		—			361
Current portion of derivative liability		(1,511	)		(33,833	)
Long-term derivative liability		(5,770	)		(11,126	)

	$	(3,670	)	$	(43,600	)

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


Contract Type	Balance Sheet Location	September 30, 2010			December 31, 2009

Asset Derivatives
Commodity contracts	Current portion of derivative asset	$	5,460		$	1,591
Commodity contracts	Long-term derivative asset		—			361
Commodity contracts	Current portion of derivative liability		1,303			6,562
Commodity contracts	Long-term derivative liability		1,403			3,435

			8,166			11,949

Liability Derivatives
Interest rate contracts	Current portion of derivative liability		—			(2,533	)
Interest rate contracts	Current portion of derivative asset		—			(593	)
Commodity contracts	Current portion of derivative asset		(1,849	)		—
Commodity contracts	Long-term derivative asset		—			—
Commodity contracts	Current portion of derivative liability		(2,814	)		(37,862	)
Commodity contracts	Long-term derivative liability		(7,173	)		(14,561	)

			(11,836	)		(55,549	)

Total Derivatives		$	(3,670	)	$	(43,600	)

As of September 30, 2010, the Partnership and APL had no interest rate derivative contracts. The following table summarizes APL’s commodity derivatives as of September 30, 2010, none of which are designated for hedge accounting (dollars and volumes in thousands):

Fixed Price Swaps


Production Period	Purchased/ Sold	Commodity	Volumes⁽²⁾		Average Fixed Price			Fair Value⁽¹⁾ Asset/ (Liability)
Natural Gas
2010	Sold	Natural Gas Basis		1,140	$	(0.700	)	$	(508	)
2010	Purchased	Natural Gas Basis		1,140		(0.705	)		514
2011	Sold	Natural Gas Basis		1,920		(0.728	)		(828	)
2011	Purchased	Natural Gas Basis		1,920		(0.758	)		886
2012	Sold	Natural Gas Basis		720		(0.685	)		(276	)
2012	Purchased	Natural Gas Basis		720		(0.685	)		276

Natural Gas Liquids
2010	Sold	Propane		8,820		1.115			(823	)
2010	Sold	Normal Butane		1,890		1.550			95
2010	Sold	Natural Gasoline		1,512		1.925			114
2011	Sold	Propane		2,016		1.150			(73	)

Crude Oil
2011	Sold	Crude Oil		78		92.870			710

Total Fixed Price Swaps								$	87

Options


Production Period	Purchased/ Sold	Type		Commodity	Volumes⁽²⁾		Average Strike Price		Fair Value⁽¹⁾ Asset/ (Liability)
Natural Gas
2010	Purchased⁽³⁾		Call	Natural Gas		2,100	$	6.500	$	(674	)

Crude Oil
2010	Purchased		Put	Crude Oil		150		74.40		224
2010	Sold		Call	Crude Oil		273		100.05		(38	)
2010	Purchased⁽⁴⁾		Call	Crude Oil		87		120.00		1
2011	Purchased		Put	Crude Oil		420		89.00		4,316
2011	Sold		Call	Crude Oil		678		94.68		(3,666	)
2011	Purchased⁽⁴⁾		Call	Crude Oil		252		120.00		311
2012	Sold		Call	Crude Oil		498		95.83		(4,950	)
2012	Purchased⁽⁴⁾		Call	Crude Oil		180		120.00		719

Total Options									$	(3,757	)

Total Fair Value									$	(3,670	)

(1)	See Note 11 for discussion on fair value methodology.

(2)	Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for Crude Oil are stated in barrels.

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

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

The following tables summarize the gross effect of the Partnership’s and APL’s derivative instruments, including the transactions referenced above, on the Partnership’s consolidated statements of operations for the periods indicated (in thousands):


		For the Three Months ended September 30,						For the Nine Months ended September 30,
		2010			2009⁽¹⁾			2010			2009⁽¹⁾
Gain (Loss) Recognized in Accumulated OCI
Contract Type
Interest rate contracts⁽²⁾		$	—		$	30		$	—		$	(2,411	)

		$	—		$	30		$	—		$	(2,411	)


Gain (Loss) Reclassified from Accumulated OCI into Income

Contract Type	Location
Interest rate contracts⁽²⁾	Interest expense	$	—		$	(3,419	)	$	(2,242	)	$	(9,599	)
Commodity contracts⁽²⁾	Natural gas and liquids revenue		(2,411	)		(7,409	)		(13,159	)		(23,987	)
Commodity contracts⁽²⁾	Discontinued operations		(11,711	)		(2,885	)		(20,154	)		(13,171	)

		$	(14,122	)	$	(13,713	)	$	(35,555	)	$	(46,757	)


Gain (Loss) Recognized in Income (Derivatives not designated as hedges)

Contract Type	Location
Interest rate contracts⁽²⁾	Other income (loss), net	$	—		$	(951	)	$	(6	)	$	(1,147	)
Commodity contracts	Other income (loss), net		(6,802	)		1,314			3,139			(23,110	)
Commodity contracts	Discontinued operations		(1,555	)		1,051			665			6,686

		$	(8,357	)	$	1,414		$	3,798		$	(17,571	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems (see Note 4).

(2)	Hedges previously designated as cash flow hedges.

NOTE 11 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Instruments

The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

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

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

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

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 10). At September 30, 2010, all of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity derivatives include natural gas and crude oil swaps and options which are calculated based upon observable market data related to the change in price of the underlying commodity. These swaps and options are calculated by utilizing the New York Mercantile Exchange (“NYMEX”) quoted price for futures and option contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3.

The following table represents the Partnership’s and APL’s assets and liabilities recorded at fair value as of September 30, 2010 (in thousands):


	Level 1		Level 2			Level 3			Total
Assets
Commodity swaps	$	—	$	2,386		$	209		$	2,595
Commodity options		—		5,571			—			5,571

Total assets		—		7,957			209			8,166

Liabilities
Commodity swaps		—		(1,611	)		(896	)		(2,507	)
Commodity options		—		(9,329	)		—			(9,329	)

Total liabilities		—		(10,940	)		(896	)		(11,836	)


Total derivatives	$	—	$	(2,983	)	$	(687	)	$	(3,670	)

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the nine months ended September 30, 2010 (in thousands):


	NGL Fixed Price Swaps						NGL Put Options						Total
	Volume⁽¹⁾			Amount			Volume⁽¹⁾			Amount			Amount
Balance – December 31, 2009		—		$	—			43,470		$	1,268		$	1,268
New contracts		23,058			—			8,820			—			—
Cash settlements⁽²⁾⁽³⁾		(8,820	)		(272	)		(52,290	)		7,246			6,974
Net change in unrealized loss⁽²⁾		—			(415	)		—			(2,005	)		(2,420	)
Option premium recognition⁽³⁾		—			—			—			(6,509	)		(6,509	)

Balance – September 30, 2010		14,238		$	(687	)		—		$	—		$	(687	)

(1)	Volumes for NGLs are stated in gallons.

(2)	Included within other income (loss), net 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.

Other Financial Instruments

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

The Partnership’s current assets and liabilities on its consolidated balance sheets, other than the derivatives discussed above, are considered to be financial instruments for which the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s total debt at September 30, 2010 and December 31, 2009, which consists principally of APL’s term loan (repaid in September 2010), APL’s Senior Notes, borrowings under APL’s revolving credit facility and the Partnership’s borrowings from Atlas Energy, was $507.8 million and $1,226.5 million, respectively, compared with the carrying amounts of $542.3 million and $1,286.4 million, respectively. The APL term loan and APL Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under APL’s revolving credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

NOTE 12 – DEBT

Total debt consists of the following (in thousands):


	September 30, 2010			December 31, 2009
Revolving credit facility	$	—		$	8,000
Atlas Energy, Inc.		34,383			24,255
APL revolving credit facility		12,000			326,000
APL term loan		—			433,505
APL 8.125% Senior notes – due 2015		272,039			271,628
APL 8.75% Senior notes – due 2018		223,050			223,050
APL capital lease obligations		793			—

Total debt		542,265			1,286,438
Less current maturities		(34,589	)		(32,255	)

Total long term debt	$	507,676		$	1,254,183

Cash payments for interest related to debt were $12.5 million and $13.3 million for the three months ended September 30, 2010 and 2009, respectively and were $68.0 million and $55.1 million for the nine months ended September 30, 2010 and 2009, respectively.

Atlas Pipeline Holdings Credit Facility

On April 13, 2010, the Partnership’s credit facility with a syndicate of banks was paid in full. The Partnership repaid $4.0 million of its outstanding balance on January 13, 2010 and the remaining balance on April 13, 2010. Payments were made by funding from Atlas Energy under its guaranty of the Partnership’s obligations.

Atlas Pipeline Holdings Demand Note with Atlas Energy

On June 1, 2009, in connection with its amendment of the credit facility, the Partnership borrowed $15.0 million from Atlas Energy under a 12% per annum subordinate loan. The Partnership incurred interest expense of $1.0 million and $0.2 million on the subordinate loan during the nine months ended September 30, 2010 and 2009, respectively, which was included in interest expense on the Partnership’s statements of operations. The interest was added to the principal of the subordinate loan.

Also, on June 1, 2009, in consideration of Atlas Energy’s guaranty of the indebtedness under the Partnership’s credit facility, the Partnership entered into a guaranty note with Atlas Energy. Atlas Energy funded $8.0 million in both the nine months ended September 30, 2010 and twelve months ended December 31, 2009, under its guaranty of the Partnership’s obligations. The Partnership incurred $0.1 million and $0.2 million in fees and interest under the guaranty note during the nine months ended September 30, 2010 and 2009, respectively, which was included in interest expense on the Partnership’s statements of operations. The interest and fees were added to the principal of the guaranty note.

The subordinate loan and guaranty note matured on April 14, 2010, the day following the date that the Partnership repaid all outstanding borrowings under its credit facility. On July 19, 2010, the Partnership entered into an amended and consolidated demand note (the “Note”) with Atlas Energy to consolidate in one instrument the debt owed to Atlas Energy under the $15.0 million subordinate loan, the $0.3 million guaranty note and the $16.0 million advance under Atlas Energy’s guaranty of the Partnership’s credit facility, plus accrued interest. The initial principal of the Note was $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by Atlas Energy for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable on demand. During the three and nine months ended September 30, 2010, the Partnership accrued $1.0 million in interest expense, which was added to the principal amount of the Note. As of September 30, 2010, the Partnership reflected $34.4 million in the current portion of long term debt on the Partnership’s consolidated balance sheet related to its obligations to Atlas Energy.

APL Term Loan and Credit Facility

At September 30, 2010, APL had a senior secured credit facility with a syndicate of banks, which consisted of a $380.0 million revolving credit facility that matures in July 2013. A $425.8 million term loan, which was scheduled to mature in July 2014, was paid in full in September 2010 with proceeds APL received from its Elk City asset sale (see Note 4). Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR, subject to a floor of 2.0% per annum, plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at September 30, 2010 was 7.8%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $5.1 million was outstanding at September 30, 2010. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. At September 30, 2010, APL had $362.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and Laurel Mountain; and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its

unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of September 30, 2010 and expects to be in compliance in future periods.

The events which constitute an event of default for APL’s 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 September 1, 2010, APL entered into an amendment to its credit facility agreement, which:

•

increased the annual capital contributions APL is permitted to invest in Laurel Mountain from $10.0 million to $60.0 million, provided if less than $60.0 million is paid in any given year that the shortfall may be carried over to the following year;

•

revised the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to premiums associated with hedging agreements, not to exceed 15% of Consolidated EBITDA and to exclude the net gains or losses attributable to a disposition of assets other than in the ordinary course of business; and

•

effective upon the closing of APL’s sale of the Elk City system (see Note 4), adjusted the maximum ratio of funded debt (as defined in the credit facility) to Consolidated EBITDA to 4.75 to 1.0 from 7.0 to 1.0; the maximum ratio of senior secured funded debt (as defined in the credit facility) to Consolidated EBITDA to 2.75 to 1.0 from 4.25 to 1.0; and the minimum ratio of Consolidated EBITDA to consolidated interest expense to 2.50 to 1.0 from 1.9 to 1.0.

As of September 30, 2010, APL’s leverage ratio was 3.16 to 1.0, its senior secured leverage ratio was 0.11 to 1.0, and its interest coverage ratio was 3.21 to 1.0.

APL Senior Notes

At September 30, 2010, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $3.4 million of unamortized discount as of September 30, 2010. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 31, 2010, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of September 30, 2010.

NOTE 13 – COMMITMENTS AND CONTINGENCIES

APL is a party to various routine legal proceedings arising in the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

On February 26, 2010, APL received notice from Williams, its joint venture partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by APL to Laurel Mountain. Under the Formation and Exchange Agreement with Williams (“Formation Agreement”): (i) Williams had nine months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL had 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects. On March 26, 2010, APL delivered notice, disputing Williams’ alleged title defects as well as the amounts claimed. By agreement dated August 24, 2010, Williams agreed to extend the cure period until December 31, 2010. Consequently, APL is continuing its review of the alleged title defects, although it appears that some of the alleged deficiencies may be resolved by appropriate assignments from Atlas Energy, Inc. or its affiliates. At the end of the cure period, with respect to any remaining title defects, APL may elect, at its option, to pay Williams for the cost of such defects, up to a total of $3.5 million, or indemnify Williams with respect to such title defects. Williams also claims, in a letter dated August 26, 2010, that the alleged title defects violate APL’s representation with respect to sufficiency of the assets contributed to Laurel Mountain. If valid, this would make Williams’ title defect claims subject to a higher deductible (which is noted below). APL believes its representations with respect to title are Williams’ sole and exclusive remedy with respect to title matters.

Additionally, in August 2010, Williams asserted additional indemnity claims under the Formation Agreement totaling approximately $19.8 million. Williams’ claims are generally based on APL’s alleged failure to construct and maintain the assets contributed to Laurel Mountain in accordance with “standard industry practice” or applicable law. As a preliminary matter, APL believes Williams has overstated its claim by forty-nine percent (49%), because, under Section 10.1 of the Formation Agreement, these claims are reduced on a pro-rata basis to equal Williams’ percentage ownership interest in Laurel Mountain. APL is currently evaluating Williams’ claims and, in this regard, has requested additional information from Williams. Under the Formation Agreement, Williams’ indemnity claims are capped, in the aggregate, at $27.5 million. In addition, APL is entitled to indemnification from Atlas Energy with respect to some of Williams’ claims. Although an adverse outcome is reasonably possible, it is not currently possible to evaluate the amount that APL may be required to pay with respect to Williams’ indemnity claims.

NOTE 14 – BENEFIT PLANS

Generally, all share-based payments to employees, including grants of unit options and phantom units, which are not cash settled, are recognized in the financial statements based on their fair values on the date of the grant.

A phantom unit entitles a grantee to receive a common limited partner unit upon vesting of the phantom unit. In tandem with phantom unit grants, participants may be granted a distribution equivalent right (“DER”), which is 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 the phantom unit is outstanding. Except for phantom units awarded to non-employee managing board members of the General Partner, a committee (the “LTIP Committee”) appointed by the General Partner’s managing board determines the vesting period for phantom units.

A unit option entitles a grantee to purchase a common limited partner unit 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 common unit on the date of grant of the option. The LTIP Committee shall determine how the exercise price may be paid by the grantee. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant.

Partnership’s Long-Term Incentive Plan.

In November 2006, the Board of Directors approved and adopted the Partnership’s Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees, board members, employees of its affiliates, consultants, and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The LTIP is administered by the LTIP Committee. Under the LTIP, phantom units and/or unit options may be granted, at the discretion of the LTIP Committee, to all or designated Participants, at the discretion of the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At September 30, 2010, the Partnership had 1,099,750 phantom units and unit options outstanding under the Partnership’s LTIP, with 954,650 phantom units and unit options available for grant.

Through September 30, 2010, phantom units granted to employees under the LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. Phantom units outstanding under the Partnership’s LTIP at September 30, 2010, include 132,838 units which will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at September 30, 2010 include DERs granted to the Participants by the LTIP Committee. The amount paid with respect to the Partnership’s DERs was $14,000 for the nine months ended September 30, 2009. This amount was recorded as a reduction of Partners’ capital on the Partnership’s consolidated balance sheet. No DERs were paid during the three months ended September 30, 2010 and 2009 and no DERs were paid during the nine months ended September 30, 2010.

The following table sets forth the Partnership’s phantom unit activity for the periods indicated:


	Three Months Ended September 30,									Nine Months Ended September 30,
	2010					2009				2010					2009
	Number of Units			Fair Value⁽¹⁾		Number of Units		Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾
Outstanding, beginning of period		144,375		$	21.48		181,300	$	22.77		138,875		$	22.18		226,300		$	22.73
Granted		500			8.94		500		3.40		6,500			6.43		500			3.40
Matured⁽²⁾		(125	)		3.40		—		—		(125	)		3.40		—			—
Forfeited		—			—		—		—		(500	)		32.28		(45,000	)		22.56

Outstanding, end of period⁽²⁾		144,750		$	21.45		181,800	$	22.72		144,750		$	21.45		181,800		$	22.72

Non-cash compensation expense recognized (in thousands)				$	218			$	295				$	617				$	277

(1)	Fair value based upon weighted average grant date price.

(2)	The intrinsic values for phantom unit awards exercised during the three and nine months ended September 30, 2010 were $1.1 thousand. No phantom unit awards were exercised during the nine months ended September 30, 2009.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2010 is $1.3 million.

At September 30, 2010, the Partnership had approximately $0.2 million of unrecognized compensation expense related to unvested phantom units outstanding under its LTIP based upon the fair value of the awards.

Through September 30, 2010, unit options granted under the Partnership’s LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. There are 641,250 unit options outstanding under the Partnership’s LTIP at September 30, 2010 that will vest within the following twelve months. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP.

The following table sets forth the Partnership’s unit option activity for the periods indicated:


	Three Months Ended September 30,								Nine Months Ended September 30,
	2010				2009				2010				2009
	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 period		955,000	$	20.54		955,000	$	20.54		955,000	$	20.54		1,215,000		$	22.56
Granted		—		—		—		—		—		—		100,000			3.24
Forfeited		—		—		—		—		—		—		(360,000	)		22.56

Outstanding, end of period⁽¹⁾⁽²⁾		955,000	$	20.54		955,000	$	20.54		955,000	$	20.54		955,000			20.54

Options exercisable, end of period⁽³⁾		213,750	$	22.56		—		—		213,750	$	22.56		—			—

Fair value of unit options granted during the period		—	$	—		—	$	—		—	$	—		100,000		$	0.61

Non-cash compensation expense recognized (in thousands)			$	155			$	222			$	464				$	(129	)

(1)	The weighted average remaining contractual lives for outstanding options at September 30, 2010 and 2009 were 6.3 years and 7.3 years, respectively.

(2)	The aggregate intrinsic value of options outstanding at September 30, 2010 and 2009 was approximately $565,000 and $56,000, respectively.

(3)	There were no options exercised during the nine months ended September 30, 2010 and 2009.

At September 30, 2010, the Partnership had approximately $0.1 million of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.

The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:


	Nine Months Ended September 30, 2009
Expected dividend yield		7.0	%
Expected stock price volatility		40.0	%
Risk-free interest rate		2.3	%
Expected term (in years)		6.9

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“2004 LTIP”) and a 2010 Long-Term Incentive Plan (“2010 LTIP” and collectively with the 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by the Partnership’s managing board. On June 15, 2010, APL unitholders approved the terms of the APL 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and DERs. Under the APL 2010 LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in APL’s 2004 LTIP. At September 30, 2010, APL had 593,149 phantom units and unit options outstanding under the APL LTIPs, with 2,508,459 phantom units and unit options available for grant.

Through September 30, 2010, phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. Except for phantom units awarded to non-employee managing board members of the

General Partner, the LTIP Committee determines the vesting period for phantom units. In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”), under APL’s subsidiary’s plan discussed below, agreed to exchange their APL Bonus Units for an equivalent number of APL phantom units, effective as of June 1, 2010. These APL phantom units will vest over a two year period, with the first tranche vesting on June 1, 2010. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIPs. At September 30, 2010, there were 187,311 units outstanding under APL’s LTIPs that will vest within the following twelve months. All phantom units outstanding under the APL LTIPs at September 30, 2010 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million for the nine months ended September 30, 2009. These amounts were recorded as a reduction of non-controlling interest in APL on the Partnership’s consolidated balance sheet. No APL DERs were paid for the nine months ended September 30, 2010.

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


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010					2009					2010					2009
	Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾
Outstanding, beginning of period		603,774		$	12.24		76,721		$	40.88		52,233		$	39.72		126,565		$	44.22
Granted		500			13.90		—			—		564,000			10.34		2,000			4.75
Matured⁽²⁾		(103,625	)		11.15		(11,038	)		41.71		(114,209	)		14.10		(46,132	)		45.91
Forfeited		(4,500	)		14.83		(75	)		44.55		(5,875	)		21.65		(16,825	)		48.48

Outstanding, end of period⁽³⁾		496,149		$	12.43		65,608		$	40.73		496,149		$	12.43		65,608		$	40.73

Non-cash compensation expense recognized (in thousands)⁽⁴⁾				$	763				$	235				$	2,788				$	491

(1)	Fair value based upon weighted average grant date price.

(2)	The intrinsic values for phantom unit awards exercised during the three months ended September 30, 2010 and 2009 were $1.2 million and $0.1 million, respectively, and $1.3 million and $0.2 million during the nine months ended September 30, 2010 and 2009, respectively.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2010 and 2009 was $8.7 million and $0.5 million, respectively.

(4)	Non-cash compensation expense includes $0.2 million and $2.0 million related to Bonus Units converted to phantom units during the three and nine months ended September 30, 2010, respectively.

At September 30, 2010, APL had approximately $2.8 million of unrecognized compensation expense related to unvested phantom units outstanding under APL’s LTIPs based upon the fair value of the awards.

Through September 30, 2010, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in APL’s LTIPs. There are 25,000 unit options outstanding under APL’s LTIPs at September 30, 2010 that will vest within the following twelve months.

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


	Three Months Ended September 30,									Nine Months Ended September 30,
	2010					2009				2010					2009
	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 period		100,000		$	6.24		100,000	$	6.24		100,000		$	6.24		—	$	—
Granted		—			—		—		—		—			—		100,000		6.24
Exercised⁽¹⁾		(3,000	)		6.24		—		—		(3,000	)		6.24		—		—

Outstanding, end of period⁽²⁾⁽³⁾		97,000		$	6.24		100,000	$	6.24		97,000		$	6.24		100,000	$	6.24

Options exercisable, end of period		22,000		$	6.24		—		—		22,000		$	6.24

Fair value of options granted during the period		—		$	—		—	$	—		—		$	—		100,000	$	0.14

Non-cash compensation expense recognized (in thousands)				$	1			$	2				$	3			$	5

(1)	The intrinsic values for option unit awards exercised during the three and nine months ended September 30, 2010 were $0.1 million.

(2)	The weighted average remaining contractual life for outstanding and exercisable options at September 30, 2010 and 2009 was 8.3 years and 9.3 years, respectively.

(3)	The aggregate intrinsic value of options outstanding at September 30, 2010 and 2009 was $1.1 million and $0.1 million, respectively.

At September 30, 2010, APL had approximately $4,000 of unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.

APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:


	Nine Months Ended September 30, 2009
Expected dividend yield		11.0	%
Expected stock price volatility		20.0	%
Risk-free interest rate		2.2	%
Expected term (in years)		6.3

Employee Incentive Compensation Plan and Agreement

A wholly-owned subsidiary of APL has an incentive plan (the “APL Cash Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The APL Cash Plan is administered by a committee appointed by the president and chief executive officer of the General Partner. Under the APL Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee, which granted 325,000 bonus units during 2009. In addition, the APL subsidiary granted an award of 50,000 bonus units to an APL executive officer on substantially the same terms as the bonus units available under the APL Cash Plan (the bonus units issued under the APL Cash Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing

document. Vesting will terminate upon termination of employment with cause. In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 of the then outstanding 375,000 APL Bonus Units outstanding at June 16, 2010 agreed to exchange their APL Bonus Units for APL phantom units, effective as of June 1, 2010.

A total of 24,750 of the remaining 75,000 APL Bonus Units vested on June 1, 2010 and an additional 24,750 APL Bonus Units will vest within the following twelve months. The Partnership recognized compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. The Partnership recognized compensation expense related to the re-measurement of the outstanding APL Bonus Units of $0.3 million and $0.4 million during the three months ended September 30, 2010 and 2009, respectively, and a credit of $0.5 million during the nine months ended September 30, 2010 and expense of $0.5 million during the nine months ended September 30, 2009, which was recorded within general and administrative expense on its consolidated statements of operations. The Partnership had $0.5 million and $1.2 million, at September 30, 2010 and December 31, 2009, respectively, included within accrued liabilities on its consolidated balance sheet with regard to these awards, which represents their fair value as of those dates.

NOTE 15 – RELATED PARTY TRANSACTIONS

Neither the Partnership nor APL directly employs any persons to manage or operate their businesses. These functions are provided by employees of Atlas Energy. Atlas Pipeline Holdings GP, the Partnership’s general partner, does not receive a management fee in connection with its management of APL, nor does Atlas Pipeline GP, the general partner of APL, receive a management fee in connection with its management of APL apart from its interest as general partner and its right to receive incentive distributions. APL reimburses the Partnership and its affiliates for compensation and benefits related to their employees who perform services for it based upon an estimate of the time spent by such persons on activities for APL. Other indirect costs, such as rent for offices, are allocated to APL by Atlas Energy based on the number of its employees who devote their time to activities on APL’s behalf.

APL’s partnership agreement provides that the Partnership will determine the costs and expenses that are allocable to APL in any reasonable manner determined by the Partnership at its sole discretion. APL reimbursed the Partnership and its affiliates $0.4 million for both the three months ended September 30, 2010 and 2009, and $1.1 million for both the nine months ended September 30, 2010 and 2009, for compensation and benefits related to their employees. There were no reimbursements by APL for direct expenses incurred by the Partnership and its affiliates for the nine months ended September 30, 2010 and 2009.

On July 19, 2010, the Partnership entered into a Note with Atlas Energy to consolidate in one instrument the debt owed to Atlas Energy under a $15.0 million subordinate loan, a $0.3 million guaranty note and a $16.0 million advance under Atlas Energy’s guaranty of the Partnership’s credit facility, plus accrued interest. The initial principal of the Note was $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by Atlas Energy for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable on demand (see Note 12 “-Atlas Pipeline Holdings Demand Note with Atlas Energy”).

NOTE 16 – SEGMENT INFORMATION

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments, which reflect the way APL manages its operations.

APL’s Mid-Continent segment consists of APL’s Chaney Dell, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins. APL’s Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs at the tailgate of its processing plants and the gathering of natural gas.

APL’s Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin area of the northeastern United States and services drilling activity in the Marcellus Shale area in southwestern Pennsylvania. Effective May 31, 2009, APL’s Appalachia operations were principally conducted through its Tennessee operations and APL’s 49% ownership interest in Laurel Mountain, a joint venture to which APL contributed its natural gas transportation, gathering and processing assets located in northeastern Appalachia. APL recognizes its ownership interest in Laurel Mountain under the equity method of accounting. APL’s Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates.

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):


	Appalachia			Mid-Continent		Corporate and Other			Consolidated
Three Months Ended September 30, 2010:
Revenue:
Revenues – third party⁽¹⁾	$	143		$	235,047	$	(9,212	)	$	225,978
Revenues – affiliates		141			—		—			141

Total revenue and other income (loss), net		284			235,047		(9,212	)		226,119

Costs and Expenses:
Operating costs and expenses – third party		300			191,472		—			191,772
General and administrative⁽²⁾ `		—			—		8,037			8,037
Depreciation and amortization		150			18,416		—			18,566
Interest expense⁽²⁾		—			—		28,448			28,448

Total costs and expenses		450			209,888		36,485			246,823

Equity income		1,787			—		—			1,787

Net income (loss) from continuing operations		1,621			25,159		(45,697	)		(18,917	)
Income from discontinued operations		—			—		305,927			305,927

Net income (loss)	$	1,621		$	25,159	$	260,230		$	287,010


Three Months Ended September 30, 2009⁽³⁾:
Revenue:
Revenues – third party⁽¹⁾	$	1,146		$	181,634	$	(6,951	)	$	175,829
Revenues – affiliates		384			—		—			384

Total revenue and other income (loss), net		1,530			181,634		(6,951	)		176,213

Costs and expenses:
Operating costs and expenses – third party		123			143,177		—			143,300
General and administrative⁽²⁾		—			—		9,482			9,482
Depreciation and amortization		153			17,763		—			17,916
Interest expense⁽²⁾		—			—		29,300			29,300

Total costs and expenses		276			160,940		38,782			199,998

Equity income		1,430			—		—			1,430
Loss on sale of assets		(994	)		—		—			(994	)

Net income (loss) from continuing operations		1,690			20,694		(45,733	)		(23,349	)
Income from discontinued operations		—			—		9,215			9,215

Net income (loss)	$	1,690		$	20,694	$	(36,518	)	$	(14,134	)


	Appalachia		Mid- Continent		Corporate and Other			Consolidated
Nine Months Ended September 30, 2010:
Revenue:
Revenues – third party⁽¹⁾	$	254	$	691,798	$	(10,051	)	$	682,001
Revenues – affiliates		472		—		—			472

Total revenue and other income (loss), net		726		691,798		(10,051	)		682,473

Costs and Expenses:
Operating costs and expenses – third party		721		557,987		—			558,708
General and administrative⁽²⁾ `		—		—		25,350			25,350
Depreciation and amortization		451		55,196		—			55,647
Interest expense⁽²⁾		—		—		80,588			80,588

Total costs and expenses		1,172		613,183		105,938			720,293

Equity income		4,137		—		—			4,137

Net income (loss) from continuing operations		3,691		78,615		(115,989	)		(33,683	)
Income from discontinued operations		—		—		320,684			320,684

Net income (loss)	$	3,691	$	78,615	$	204,695		$	287,001


Nine Months Ended September 30, 2009⁽³⁾:
Revenue:
Revenues – third party⁽¹⁾	$	2,743	$	498,986	$	(48,304	)	$	453,425
Revenues – affiliates		16,881		—		—			16,881

Total revenue and other income (loss), net		19,624		498,986		(48,304	)		470,306

Costs and expenses:
Operating costs and expenses – third party		6,515		401,464		—			407,979
General and administrative⁽²⁾		—				26,586			26,586
Depreciation and amortization		3,452		52,115		—			55,567
Interest expense⁽²⁾		—		—		77,924			77,924

Total costs and expenses		9,967		453,579		104,510			568,056

Equity income		2,140		—		—			2,140
Gain on sale of assets		108,947		—		—			108,947

Net income (loss) from continuing operation		120,744		45,407		(152,814	)		13,337
Income from discontinued operations		—		—		81,241			81,241

Net income (loss)	$	120,744	$	45,407	$	(71,573	)	$	94,578

(1)	Derivative contracts are held at the corporate level and are reported accordingly.

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

(3)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see Note 4).


	Three Months Ended September 30,				Nine Months Ended September 30,
Capital Expenditures:	2010		2009⁽¹⁾		2010		2009⁽¹⁾
Mid-Continent	$	11,340	$	5,453	$	32,078	$	87,745
Appalachia		—		34		—		9,737

	$	11,340	$	5,487	$	32,078	$	97,482


	September 30, 2010		December 31, 2009⁽¹⁾
	September 30, 2010		December 31, 2009⁽¹⁾
Balance Sheet
Total assets:
Mid-Continent	$	1,538,549	$	1,563,082
Appalachia		146,068		143,601
Discontinued operations		—		401,776
Corporate other		24,726		29,659

	$	1,709,343	$	2,138,118

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see Note 4).

The following table summarizes the Partnership’s natural gas and liquids revenues by product or service for the periods indicated (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009⁽¹⁾⁽²⁾		2010		2009⁽¹⁾⁽²⁾
Natural gas and liquids:
Natural gas	$	72,421	$	58,427	$	226,806	$	184,446
NGLs		134,294		93,538		383,962		229,757
Condensate		12,526		8,280		30,895		17,243
Other		1,237		1,120		315		3,334

Total	$	220,478	$	161,365	$	641,978	$	434,780

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see Note 4).

(2)	Restated to reflect amount reclassified from Natural Gas and Liquids to Transportation, Processing and other fees (see Note 1).

NOTE 17 – SUBSEQUENT EVENTS

On October 18, 2010, APL declared a cash distribution of $0.35 per unit on its outstanding common limited partner units. Of the $19.0 million distribution, the Partnership will receive $0.4 million for its general partner interest in APL and $2.0 million for its interest in APL common limited partner units. On March 31, 2010, APL’s limited partnership agreement was amended to provide a temporary waiver of a capital contribution required for the Partnership to maintain its 2.0% general partner interest in APL, relative to the January 2010 issuance of common units for warrants exercised. The Partnership plans to make such capital contribution upon receipt of the declared distributions from APL, which will allow the general partner interest to be restored to 2.0% (see Note 5).

On October 18, 2010, the Partnership declared a cash distribution of $0.05 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The $1.4 million distribution will be paid on November 16, 2010 to unitholders of record as of the close of business on November 8, 2010.

On November 8, 2010, Atlas Pipeline Holdings GP and the Partnership entered into a definitive agreement (the “Transaction Agreement”) with Atlas Energy and Atlas Energy Resources, LLC (“ATN”), a wholly owned subsidiary of Atlas Energy, pursuant to which the Partnership agreed to purchase Atlas Energy’s interests in its partnership management business, certain producing oil & gas assets, and certain other assets for approximately $250 million, consisting of approximately 23.38 million of newly issued Partnership units (which had a value of approximately $220 million as of November 8, 2010) and $30 million in cash. The partnership management business includes fees earned on the servicing of oil and natural gas wells. The Partnership also expects to put in place debt financing of $70 million, of which $30 million will be used to pay the cash portion of the consideration in the Transaction Agreement and $34 million of which will be used to repay the Partnership’s amended and consolidated demand note with Atlas Energy. In the transaction, the Partnership will also acquire from Atlas Energy the general partner interest in the Partnership held by Atlas Energy, and Atlas Energy will distribute its approximately 41 million Partnership units to the Atlas Energy stockholders. As a result of the foregoing, following the transactions, the Partnership will cease to be controlled by Atlas Energy.

Concurrently with the execution of the Transaction Agreement, APL, Atlas Energy and ATN entered into a definitive agreement (the “APL Sale Agreement”), pursuant to which APL agreed to sell APL’s 49% non-controlling interest in Laurel Mountain to ATN for $403 million in cash, subject to certain closing adjustments (the “Laurel Mountain Sale”).

Concurrently with the execution of the Transaction Agreement and the APL Sale Agreement, Atlas Energy entered into a merger agreement with Chevron Corporation (“Chevron”), pursuant to which Chevron agreed to acquire Atlas Energy through a merger of a newly formed wholly owned subsidiary of Chevron with and into Atlas Energy (the “Chevron Merger”).

The Transaction Agreement will close upon the satisfaction of certain closing conditions, including the concurrent sale of APL’s 49% non-controlling interest in Laurel Mountain to Atlas Energy, and immediately subsequent completion of the Chevron Merger.

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, under the caption “Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2009. 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.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report.

Overview

We are a publicly-traded Delaware limited partnership (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). APL is a midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions. Our cash generating assets currently consist solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, which as of September 30, 2010, together with us, owns:

•

a 1.9% general partner interest in APL, which entitles it to receive 1.9% of the cash distributed by APL;

•

all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems in 2007, Atlas Pipeline GP agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”);

•

5,754,253 common units of APL, representing approximately 10.8% of the outstanding common units of APL, or a 10.6% limited partner interest in APL, and

•

15,000 $1,000 par value 12.0% APL Cumulative Class B preferred limited partner units.

On March 31, 2010, APL and the Operating Partnership amended their respective partnership agreements to temporarily waive the requirement that Atlas Pipeline GP make aggregate cash contributions of approximately $0.3 million, which was required in connection with APL’s issuance of 2,689,765 of its common units upon the exercise of certain warrants in January 2010. The waiver will remain in effect until Atlas Pipeline GP has received aggregate distributions from APL sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to Atlas Pipeline GP’s general partner interest in APL and the Operating Partnership is reduced to 1.9%. Both amendments were approved by APL’s conflicts committee and managing board, and were effective as of January 11, 2010.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights.

Atlas Pipeline GP’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle Atlas Pipeline GP, subject to the IDR Adjustment Agreement, to receive the following:

•

13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter;

•

23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and

•

48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter.

We pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from APL, less certain reserves for expenses and other uses of cash, including:

•

our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

•

capital contributions to maintain or increase our ownership interest in APL;

•

compliance with any law or loan obligation or other agreement restricting distributions; and

•

reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

We did not declare a cash distribution for the quarters ended March 31, 2009 through June 30, 2010. We declared a cash distribution of $0.05 per common limited partner unit for the quarter ended September 30, 2010.

Atlas Pipeline Partners, L.P.

APL is a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” APL is a leading provider of natural gas gathering services in the Anadarko and Permian Basins located in the southwestern and mid-continent United States and the Appalachian Basin in the northeastern United States. In addition, APL is a leading provider of natural gas processing and treating services in Oklahoma and Texas.

APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

APL’s Mid-Continent operations, as of September 30, 2010, owns, has interests in and operates five natural gas processing plants with aggregate capacity of approximately 520 MMCFD. These facilities are connected to approximately 8,300 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points to APL’s natural gas processing and treating plants, as well as third-party pipelines.

The Appalachia operations of APL are conducted principally through its 49% ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately

1,800 miles of natural gas gathering systems in the Appalachian Basin located in the northeastern United States. APL also owns and operates approximately 80 miles of active natural gas gathering pipelines in northeastern Tennessee.

Recent Events

On July 19, 2010, we entered into an amended and consolidated demand note (the “Note”) with Atlas Energy to consolidate the debt in one instrument owed to Atlas Energy under our subordinate loan and guaranty note with Atlas Energy and Atlas Energy’s $16.0 million advance under its guaranty of our credit facility. The principal amount of the Note is $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by Atlas Energy for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable upon demand (see “-Our Subordinate Loan and Guaranty Note with Atlas Energy”).

On September 1, 2010, APL entered into an amendment to its credit facility agreement, which:

•

revised the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to premiums associated with APL’s hedging agreements, not to exceed 15% of Consolidated EBITDA and to exclude the net gains or losses attributable to a disposition of assets other than in the ordinary course of business; and

•

effective upon the closing of APL’s sale of the Elk City system, adjusted the maximum ratio of funded debt (as defined in the credit facility) to Consolidated EBITDA to 4.75 to 1.0 from 7.0 to 1.0; the maximum ratio of senior secured funded debt (as defined in the credit facility) to Consolidated EBITDA to 2.75 to 1.0 from 4.25 to 1.0; and the minimum ratio of Consolidated EBITDA to consolidated interest expense to 2.50 to 1.0 from 1.9 to 1.0.

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems, the related processing and treating facilities (including the Prentiss treating facility) and the Nine Mile processing plant (collectively “Elk City”) to a subsidiary of Enbridge Energy Partners, L.P. (NYSE: EEP) for $682 million in cash, excluding working capital adjustments and transaction costs (See “Item 1. Notes to Consolidated Financial Statements (Unaudited) -Note 4). APL utilized the proceeds from the sale to repay its senior secured term loan and a portion of its indebtedness under its revolving credit facility (see “APL Term Loan and Revolving Credit Facility”).

Subsequent Events

On October 18, 2010, APL declared a cash distribution of $0.35 per unit on its outstanding common limited partner units. Of the $19.0 million distribution, we will receive $0.4 million for our general partner interest in APL and $2.0 million for our interest in APL common limited partner units. On March 31, 2010, APL’s limited partnership agreement was amended to provide a temporary waiver of a capital contribution required for us to maintain our 2.0% general partner interest in APL, relative to the January 2010 issuance of common units for warrants exercised. We plan to make such capital contribution upon receipt of the declared distributions from APL, which will allow the general partner interest to be restored to 2.0%.

On October 18, 2010, we declared a cash distribution of $0.05 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The $1.4 million distribution will be paid on November 16, 2010 to unitholders of record as of the close of business on November 8, 2010.

On November 8, 2010, we and Atlas Pipeline Holdings GP entered into a definitive agreement (the “Transaction Agreement”) with Atlas Energy and Atlas Energy Resources, LLC (“ATN”), a wholly owned subsidiary of Atlas Energy, pursuant to which we agreed to purchase Atlas Energy’s interests in its partnership management business, certain producing oil & gas assets, and certain other assets for approximately $250 million, consisting of approximately 23.38 million of our newly issued units (which had a value of approximately $220 million as of November 8, 2010) and $30 million in cash. The partnership management business includes fees earned on the servicing of oil and natural gas wells. We also expect to put in place debt financing of $70 million, of which $30 million will be used to pay the cash portion of the consideration in the Transaction Agreement and $34 million of which will be used to repay our amended and consolidated demand note with Atlas Energy. In the transaction, we will also acquire from Atlas Energy the general partner interest in us held by Atlas Energy, and Atlas Energy will distribute its approximately 41 million units in us to the Atlas Energy stockholders. As a result of the foregoing, following the transactions, we will cease to be controlled by Atlas Energy.

Contractual Revenue Arrangements

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

•

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

•

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

•

the NGL and British Thermal Unit (“BTU”) content of the gas that is gathered and processed;

•

the contract terms with each producer; and

•

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

APL’s revenue consists of the fees earned from its gathering and processing operations. 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.

In APL’s Appalachia segment, substantially all of the natural gas it gathers via Laurel Mountain is for Atlas Energy under contracts in which Laurel Mountain earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas, inclusive of the effects of financial and physical hedging, subject, in most cases, to a minimum of $0.35 per thousand cubic feet, or MCF, depending on the ownership of the well. The balance of the natural gas gathered by Laurel Mountain and APL’s Tennessee operations is for third-party operators generally under fixed-fee contracts. See “Item 1. Notes to Consolidated Financial Statements (Unaudited) -Note 2 -Revenue Recognition” for further discussion of contractual revenue arrangements.

Recent Trends and Uncertainties

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

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

As a result of APL’s Percentage of Proceeds and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) -Note 2 -Revenue Recognition”). APL believes that 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 generally expects NGL prices to follow changes in crude oil prices over the long term, which APL 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 recent past. Lower drilling levels and shut in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL closely monitors the risks associated with commodity price changes on APL’s future operations and, where appropriate, uses various commodity based derivative instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of APL’s assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk -Commodity Price Risk” for further discussion of commodity price risk.

Currently, there is an extremely significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL’s borrowing capabilities and APL’s ability to raise additional capital, and an increase in the volatility of the price of our and APL’s common units. While we and APL have no definitive plans to access the capital markets, should we and APL decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Results of Operations

The following table illustrates selected volumetric information related to APL’s reportable segments for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Pricing:
Mid-Continent Weighted Average Prices:
NGL price per gallon – Conway hub	$	0.85	$	0.66	$	0.93	$	0.62
NGL price per gallon – Mt. Belvieu hub		0.95		0.81		1.04		0.71

Natural gas sales ($/Mcf):
Velma		4.03		2.90		4.35		2.99
Elk City		4.10		2.95		4.17		3.02
Chaney Dell		4.01		2.92		4.35		3.01
Midkiff/Benedum		3.99		3.02		4.30		3.11
Weighted Average		4.01		2.95		4.31		3.03

NGL sales ($/gallon):
Velma		0.80		0.65		0.87		0.60
Elk City		0.91		0.70		0.91		0.63
Chaney Dell		0.91		0.70		0.92		0.62
Midkiff/Benedum		0.94		0.84		1.00		0.73
Weighted Average		0.89		0.72		0.93		0.64

Condensate sales ($/barrel):
Velma		74.92		66.34		76.19		55.06
Elk City		71.28		61.76		72.96		48.76
Chaney Dell		68.73		63.46		71.33		50.19
Midkiff/Benedum		74.82		66.58		74.06		55.29
Weighted Average		72.75		65.79		73.42		53.91

Volumes⁽¹⁾:
Appalachia:
Laurel Mountain system:
Average throughput volume – mcfd⁽²⁾		114,878		96,315		104,484		96,581
Tennessee system
Average throughput volume – mcfd		9,142		9,674		8,767		7,428
Mid-Continent:
Velma system:
Gathered gas volume – mcfd		90,377		81,562		81,107		75,919
Processed gas volume – mcfd		84,255		78,714		75,531		73,351
Residue gas volume – mcfd		68,713		62,219		61,559		57,959
NGL volume – bpd		10,231		8,922		8,749		8,158
Condensate volume – bpd		369		389		410		383
Chaney Dell system:
Gathered gas volume – mcfd		225,395		268,723		223,511		282,756
Processed gas volume – mcfd		211,533		202,516		197,197		216,407
Residue gas volume – mcfd		187,024		218,420		177,245		238,167
NGL volume – bpd		11,561		13,376		11,785		13,574
Condensate volume – bpd		599		750		661		861
Midkiff/Benedum system:
Gathered gas volume – mcfd		188,960		166,423		175,985		160,631
Processed gas volume – mcfd		170,988		152,314		161,474		149,516
Residue gas volume – mcfd		109,167		104,895		104,742		103,078
NGL volume – bpd		28,557		19,926		26,533		21,006
Condensate volume – bpd		1,867		1,942		1,353		1,426
Discontinued Operations⁽³⁾:
Elk City/Sweetwater system:
Gathered gas volume – mcfd		265,744		211,287		254,298		228,630
Processed gas volume – mcfd		224,982		200,182		208,952		223,438
Residue gas volume – mcfd		198,072		181,011		194,228		203,034
NGL volume – bpd		12,899		10,792		11,396		11,361
Condensate volume – bpd		434		260		477		374

(1)	“Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.

(2)	Includes 100% of the throughput volume of Laurel Mountain.

(3)	Includes Elk City/Sweetwater volumes through September 16, 2010, due to our sale of the Elk City gas gathering and processing systems (see “-Recent Events”)

Financial Presentation

We currently have no separate operating activities apart from those conducted by APL, and our cash flows consist of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a component of equity on our consolidated balance sheet. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

On September 16, 2010, APL completed the sale of Elk City (see “–Recent Events”). As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of Elk City as discontinued operations.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Revenue. The following table details the revenue changes between the three months ended September 30, 2010 and 2009 (dollars in thousands):


	Three Months Ended September 30,
	2010			2009⁽¹⁾		Change			Percent Change
Revenues:
Natural gas and liquids	$	220,478		$	161,365	$	59,113			36.6	%
Transportation, processing and other fee revenue		9,951			11,902		(1,951	)		(16.4	)%
Other income (loss), net		(4,310	)		2,946		(7,256	)		(246.3	)%

Total Revenues	$	226,119		$	176,213	$	49,906			28.3	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Natural gas and liquids revenue was $220.5 million for the three months ended September 30, 2010, an increase of $59.1 million from $161.4 million for the prior year comparable period. The increase was primarily attributable to a favorable price change as a result of higher realized commodity prices, partially offset by lower production volumes at APL’s Chaney Dell system.

APL’s Midkiff/Benedum system’s NGL production volume for the three months ended September 30, 2010 was 28,557 BPD, an increase of 43.3% when compared to the prior year period, representing an increase in production efficiency due to the start-up of the new Consolidator plant, which provides greater recoveries, increasing the liquid volumes extracted from the natural gas stream. The Chaney Dell system had NGL production volume of 11,561 BPD for the three months ended September 30, 2010, a 13.6% decrease when compared to the prior year period of 13,376 BPD. Decreased NGL volumes for the Chaney Dell system were partially a result of ethane rejection during the current period.

Transportation, processing and other fee revenue decreased to $10.0 million for the three months ended September 30, 2010 compared with $11.9 million for the prior year period. This $1.9 million decrease was primarily due to a $1.6 million decrease from APL’s Chaney Dell system due to lower gathered volumes, as a result of decreased number of well connects over the past year, resulting from lower capital spending.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a loss of $4.3 million for the three months ended September 30, 2010, which represents an unfavorable movement of $7.3 million from the prior year period gain of $2.9 million. APL enters into derivative instruments principally 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.”

Costs and Expenses. The following table details the costs and expenses changes between the three months ended September 30, 2010 and 2009 (dollars in thousands):


	Three Months Ended September 30,
	2010		2009⁽¹⁾		Change			Percent Change
Costs and Expenses:
Natural gas and liquids	$	178,920	$	131,503	$	47,417			36.1	%
Plant operating		12,552		11,663		889			7.6	%
Transportation and compression		300		134		166			123.9	%
General and administrative		8,037		9,482		(1,445	)		(15.2	)%
Depreciation and amortization		18,566		17,916		650			3.6	%
Interest expense		28,448		29,300		(852	)		(2.9	)%

Total Costs and Expenses	$	246,823	$	199,998	$	46,825			23.4	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Natural gas and liquids cost of goods sold of $178.9 million for the three months ended September 30, 2010 represented an increase of $47.4 million from the prior year period due primarily to an increase in average commodity prices, as discussed above in revenues.

Plant operating expenses of $12.6 million for the three months ended September 30, 2010 represented an increase of $0.9 million from the prior year period mainly due to a $0.5 million increase associated with APL’s Midkiff/Benedum system resulting from higher compressor rentals and labor costs related to APL’s new Consolidator gas plant.

General and administrative expense, including amounts reimbursed to affiliates, decreased $1.4 million to $8.0 million for the three months ended September 30, 2010 compared with $9.5 million for the prior year period. The decrease was primarily due to a $1.4 million decrease in APL salaries and wages resulting mainly from an allocation of direct costs associated with APL’s sale of Elk City.

Depreciation and amortization increased $0.7 million to $18.6 million for the three months ended September 30, 2010 due primarily to expansion capital expenditures incurred at APL’s Midkiff/Benedum system subsequent to September 30, 2009.

Interest expense decreased to $28.4 million for the three months ended September 30, 2010 as compared with $29.3 million for the prior year period. This $0.9 million decrease was primarily due to a $3.1 million decrease in APL’s interest rate swap expense, plus a $2.1 million decrease in interest expense on APL’s term loan

and revolving credit facility, partially offset by a $4.1 million increase in amortized deferred finance costs. The decreased interest rate swap expense is due to the unfavorable impact of interest rate swaps in the prior year period. The decreased interest expense on APL’s term loan and revolving credit facility is primarily due to the reduction of principal related to the retirement of APL’s term loan and the majority of APL’s revolving credit facility with proceeds from the sale of APL’s Elk City system (see “Recent Events”). The increased amortization of deferred finance costs was due principally to accelerated amortization associated with the retirement of APL’s term loan.

Other income items. The following table details the changes between the three months ended September 30, 2010 and 2009 for other income items (dollars in thousands):


	Three Months Ended September 30,
	2010			2009⁽¹⁾			Change			Percent Change
Equity income in joint venture	$	1,787		$	1,430		$	357			25.0	%
Loss on asset sale		—			(994	)		994			100.0	%
Income from discontinued operations		305,927			9,215			296,712			3,219.9	%
Income attributable to non-controlling interests		(1,076	)		(954	)		(122	)		12.8	%
(Income) loss attributable to non-controlling interests in APL		(251,488	)		11,487			(262,975	)		(2,289.3	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to our sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Equity income of $1.8 million for the three months ended September 30, 2010, which represents APL’s ownership interest in the net income of Laurel Mountain, increased $0.4 million from the prior year period.

Loss on asset sale of $1.0 million from the prior year period is an adjustment, for post-closing costs, to the gain recognized on APL’s contribution of a 51% ownership interest in its Appalachia natural gas gathering system to Laurel Mountain, which closed on May 31, 2009.

Income of $305.9 million from discontinued operations for the three months ended September 30, 2010 represents a $311.5 million gain on sale associated with APL’s Elk City system (see “Recent Events”), which was sold on September 16, 2010, offset by a $5.6 million loss related to the income of APL’s Elk City. The $5.6 million loss is a decrease of $14.8 million from the prior year period, primarily due to a $13.2 million unfavorable impact of certain gains and losses recognized on derivatives mainly resulting from the recognition of $10.6 million of losses reclassified from other comprehensive income, due to the sale of APL’s Elk City.

Income attributable to non-controlling interests was $1.1 million for the three months ended September 30, 2010 compared with $1.0 million for the prior year period. This change was primarily due to higher net income for APL’s Midkiff/Benedum joint venture, which was formed to accomplish APL’s acquisition of control of the system. The increase in net income of APL’s Midkiff/Benedum joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher prices and volumes. The non-controlling interest expense represents Anadarko Petroleum Corporation’s interest in the net income of APL’s Chaney Dell and Midkiff/Benedum joint ventures.

(Income) loss attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, was income $251.5 million for the three months ended September 30, 2010 compared with loss of $11.5 million for the prior year period. This change was primarily due to an increase in APL’s net earnings between periods, mainly as a result of the sale of APL’s Elk City system.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Revenue. The following table details the revenue changes between the nine months ended September 30, 2010 and 2009 (dollars in thousands):


	Nine Months Ended September 30,
	2010		2009⁽¹⁾			Change			Percent Change
Revenues:
Natural gas and liquids	$	641,978	$	434,780		$	207,198			47.7	%
Transportation, processing and other fee revenue		29,944		48,906			(18,962	)		(38.8	)%
Other income (loss), net		10,551		(13,380	)		23,931			178.9	%

Total Revenues	$	682,473	$	470,306		$	212,167			45.1	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Natural gas and liquids revenue was $642.0 million for the nine months ended September 30, 2010, an increase of $207.2 million from $434.8 million for the prior year comparable period. The increase was primarily attributable to a favorable price change as a result of higher realized commodity prices combined with lower qualified hedge losses. Gains and losses within other comprehensive income related to previously designated hedges are recorded within natural gas and liquids revenue, while all other gains and losses related to derivative instruments are recorded within other income (loss), net. 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.”

APL’s Midkiff/Benedum system’s NGL production volume for the nine months ended September 30, 2010 was 26,533 BPD, an increase of 26.3% when compared to the prior year period, representing an increase in production efficiency, primarily due to the start-up of APL’s new Consolidator plant, which provides greater recoveries, increasing the liquid volumes extracted from the natural gas stream. Processed natural gas volume on APL’s Chaney Dell system was 197.2 MMCFD for the nine months ended September 30, 2010, a decrease of 8.9% compared to 216.4 MMCFD for the prior year. The Chaney Dell system had NGL production volume of 11,785 BPD for the nine months ended September 30, 2010, a 13.2% decrease when compared to the prior year period of 13,574 BPD. Decreased volumes for the Chaney Dell system were a result of weather related downtime at the facilities and a decreased number of well connects over the past year, resulting from lower capital spending.

Transportation, processing and other fee revenue decreased to $29.9 million for the nine months ended September 30, 2010 compared with $48.9 million for the prior year period. This $19.0 million decrease was primarily due to a $17.7 million decrease from APL’s Appalachia system as a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, a joint venture in which it has a 49% ownership interest. After the contribution we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a gain of $10.6 million for the nine months ended September 30, 2010, which represents a favorable movement of $23.9 million from the prior year period loss of $13.4 million.

Costs and Expenses. The following table details the costs and expenses changes between the nine months ended September 30, 2010 and 2009 (dollars in thousands):


	Nine Months Ended September 30,
	2010		2009⁽¹⁾		Change			Percent Change
Costs and Expenses:
Natural gas and liquids	$	521,495	$	368,658	$	152,837			41.5	%
Plant operating		36,492		33,065		3,427			10.4	%
Transportation and compression		721		6,256		(5,535	)		(88.5	)%
General and administrative		25,350		26,586		(1,236	)		(4.6	)%
Depreciation and amortization		55,647		55,567		80			0.1	%
Interest expense		80,588		77,924		2,664			3.4	%

Total Costs and Expenses	$	720,293	$	568,056	$	152,237			26.8	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Natural gas and liquids cost of goods sold of $521.5 million for the nine months ended September 30, 2010 represented an increase of $152.8 million from the prior year period due primarily to an increase in average commodity prices partially offset by lower volumes in comparison to the prior year period, as discussed above in revenues.

Plant operating expenses of $36.5 million for the nine months ended September 30, 2010 represented an increase of $3.4 million from the prior year period due partially due to a $2.5 million increase associated with APL’s Midkiff/Benedum system resulting from higher compressor rentals and labor costs related to APL’s new Consolidator gas plant.

Transportation and compression expenses decreased to $0.7 million for the nine months ended September 30, 2010 compared with $6.3 million for the prior year period due to APL’s contribution of its Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, decreased $1.2 million to $25.4 million for the nine months ended September 30, 2010 compared with $26.6 million for the prior year period. The decrease was primarily related to a $1.7 million decrease in APL’s salaries and wages resulting partially from non-recurring severance expense incurred during the prior year period.

Depreciation and amortization increased $0.1 million to $55.7 million for the nine months ended September 30, 2010. Depreciation in APL’s Mid-Continent segment increased $3.1 million due primarily to expansion capital expenditures incurred subsequent to September 30, 2009, offset by a decrease of $3.0 million in APL’s Appalachia segment due to the sale of assets in the second quarter of 2009.

Interest expense increased to $80.6 million for the nine months ended September 30, 2010 as compared with $77.9 million for the prior year period. This $2.7 million increase was primarily due to a $3.4 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, a $2.6 million higher amortization of deferred finance costs, $1.7 million of lower interest capitalized as a component of APL’s capital expenditures and a $1.6 million increase in interest expense associated with APL’s term loan, offset by a $6.8 million decrease in interest rate swap expense. The higher interest expense on APL’s revolving credit facility and term loan is due to higher weighted average interest rates of 6.9% in the nine months ended September 30, 2010 compared to average rates of 5.9% in the prior year period. The increased amortization of deferred finance costs was due principally to accelerated amortization associated with the retirement of APL’s term loan with the proceeds from the sale of its Elk City system (see “Recent Events”). The lower capitalized interest is a result of fewer capital projects in the current period.

Other income items. The following table details the changes between the nine months ended September 30, 2010 and 2009 for other income items (dollars in thousands):


	Nine Months Ended September 30,
	2010			2009⁽¹⁾			Change			Percent Change
Equity income in joint venture	$	4,137		$	2,140		$	1,997			93.3	%
Gain on sale of assets		—			108,947			(108,947	)		(100.0	)%
Income from discontinued operations		320,684			81,241			239,443			294.7	%
Income attributable to non-controlling interests		(3,338	)		(2,075	)		(1,263	)		(60.9	)%
Income attributable to non-controlling interests in APL		(251,721	)		(82,201	)		(169,520	)		(206.2	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to our sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Equity income of $4.1 million for the nine months ended September 30, 2010 represents APL’s ownership interest in the net income of Laurel Mountain and is an increase of $2.0 million from the prior year period, which only included four months of operations.

Gain on asset sale of $108.9 million from the prior year period is the gain recognized on APL’s contribution of a 51% ownership interest in its Appalachia natural gas gathering system to Laurel Mountain.

Income from discontinued operations of $320.7 million for the nine months ended September 30, 2010 increased $239.4 million compared with $81.2 million for the prior year period. The increase is primarily due to the $311.5 million gain on sale of APL’s Elk City system in the current year period compared to the $51.1 million gain on sale of APL’s NOARK gas gathering and interstate pipeline which was sold in May 2009.

Income attributable to non-controlling interests was $3.3 million for the nine months ended September 30, 2010 compared with $2.1 million for the prior year period. This change was primarily due to higher net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish APL’s acquisition of control of the respective systems. The increase in net income of APL’s Chaney Dell and Midkiff/Benedum joint ventures was principally due to higher gross margins on the sale of commodities, resulting from higher prices. The non-controlling interest expense represents Anadarko Petroleum Corporation’s interest in the net income of APL’s Chaney Dell and Midkiff/Benedum joint ventures.

Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, increased $169.5 million to income of $251.7 million for the nine months ended September 30, 2010 compared with income of $82.2 million for the prior year period. This change was primarily due to an increase in APL’s net earnings between periods.

Liquidity and Capital Resources

General

Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and cash on hand. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through the retention of cash and our capital contributions to APL through the retention of cash from distributions received from APL. Under APL’s revolving credit facility, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million. APL met these requirements for the quarter ended September 30, 2010 (see “-APL Term Loan and Revolving Credit Facility”).

Our credit facility terminated on April 13, 2010 (see “-Our Credit Facility”). We repaid $4.0 million on January 13, 2010, and the balance of the indebtedness under the credit facility on April 13, 2010. Payments were made by funding from Atlas Energy under its guaranty of our obligations (see “-Our Demand Note with Atlas Energy”).

At September 30, 2010, we had a working capital deficit of $81.6 million compared with a working capital deficit of $63.5 million at December 31, 2009. We believe that we will have sufficient liquid assets, including our ownership of 5.8 million limited partner units in APL, to meet our financial commitments, debt service obligations, and possible contingencies for at least the next twelve-month period. However, we are subject to business and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of our ownership interests in APL.

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 general partner. In general, we expect APL 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 borrowings; and

•

debt principal payments through operating cash flows and additional borrowings as they become due or by the issuance of additional limited partner units or APL asset sales.

At September 30, 2010, APL had $12.0 million of outstanding borrowings under its $380.0 million senior secured credit facility and $5.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $362.9 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “-APL Term Loan and Revolving Credit Facility”). APL was in compliance with its credit facility covenants at September 30, 2010. At September 30, 2010, APL had a working capital deficit of $46.9 million compared with a $30.6 million working capital deficit at December 31, 2009. We believe that APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet its financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and the sale of its assets.

Recent instability in the financial markets, as a result of recession or otherwise, has caused volatility in the markets and may impact the availability of funds from those markets. This may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund our and APL’s operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We or APL cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The following table details the cash flow changes between the nine months ended September 30, 2010 and 2009 (dollars in thousands):


	Nine Months Ended September 30,
	2010			2009			Change			Percent Change
Net cash provided by operating activities	$	100,252		$	49,315		$	50,937			103.3	%
Net cash provided by investing activities		629,888			258,762			371,126			143.4	%
Net cash used in financing activities		(731,028	)		(309,774	)		(421,254	)		(136.0	)%

Net change in cash and cash equivalents	$	(888	)	$	(1,697	)	$	809			47.7	%

Net cash provided by operating activities of $100.3 million for the nine months ended September 30, 2010 represented an increase of $50.9 million from $49.3 million of net cash provided by operating activities for the prior year period. The increase was derived from a $54.3 million favorable gross margin in continuing operations related to the sale of natural gas and liquids, as a result of higher prices.

Net cash provided by investing activities was $629.9 million for the nine months ended September 30, 2010, an increase of $371.1 million from $258.8 million of net cash provided by investing activities for the prior year period. This increase was principally due to the net proceeds of $674.4 million received from the sale of APL’s Elk City system in the current period compared to $292.0 million received from the sale of APL’s NOARK gas gathering and interstate pipeline system in the prior year period combined with the $110.4 million received from the sale of APL’s 51% interest in the Appalachia assets in the prior year period, and due to an $83.9 million decrease in capital expenditures compared to the prior year period (see further discussion of capital expenditures under “Liquidity and Capital Resources -Capital Requirements”).

Net cash used in financing activities was $731.0 million for the nine months ended September 30, 2010, an increase of $421.3 million from $309.8 million of net cash used in financing activities for the prior year period. This increase was mainly due to a $301.0 million net increase in repayments of the outstanding principal balance on our credit facility and a portion of APL’s revolving credit facility and a $159.8 million increase in repayments of APL’s term loan, partially offset by a $22.3 million decrease in distributions paid to non-controlling interests in APL. The increase in repayments of the outstanding principal balance on APL’s term loan and revolving credit facility is due to the retirement of the term loan and a portion of the revolving credit facility with the proceeds from the sale of the Elk City system.

Capital Requirements

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

•

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

•

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009⁽¹⁾		2010		2009⁽¹⁾
Maintenance capital expenditures	$	2,595	$	762	$	6,478	$	1,732
Expansion capital expenditures		8,745		4,725		25,600		95,750

Total	$	11,340	$	5,487	$	32,078	$	97,482

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

Expansion capital expenditures increased to $8.7 million for the three ended September 30, 2010, compared with $4.7 million for the prior year comparable period, partially due to enhancements to APL’s Woolsey Compression Station within the Chaney Dell system. Expansion capital expenditures decreased to $25.6 million for the nine months ended September 30, 2010, compared with $95.8 million for the nine months ended September 30, 2009, due partially to the construction of APL’s Madill to Velma pipeline and APL compressor upgrades in the prior year periods, compounded by a reduction of well connects in the current periods. The increase in maintenance capital expenditures for the three and nine months ended September 30, 2010 when compared with the comparable prior year periods was partially due to planned maintenance expense at APL’s Waynoka plant plus fluctuations in the timing of other scheduled maintenance activity. As of September 30, 2010, APL has approved expenditures of approximately $25.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Our Partnership Distributions

The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our 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. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. 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. On October 18, 2010, we declared a cash distribution of $0.05 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The distribution will be paid on November 16, 2010 to unitholders of record as of the close of business on November 8, 2010.

APL’s Partnership Distributions

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

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

Available cash is initially distributed 98.1% to APL’s common limited partners and 1.9% 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 1.9% of the aggregate amount of cash being distributed. During July 2007, Atlas Pipeline GP, as sole owner of APL’s general partner, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. No incentive distributions were declared for the nine months ended September 30, 2010.

APL’s senior secured credit facility restricted it from paying cash distributions through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million at the end of the quarter (see “-APL Term Loan and Revolving Credit Facility”). APL met the requirements of the credit agreement for the quarter ending September 30, 2010. On October 18, 2010, APL declared a cash distribution of $0.35 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2010. The will be paid on November 12, 2010 to unitholders of record as of the close of business on November 8, 2010.

Off Balance Sheet Arrangements

As of September 30, 2010, our off balance sheet arrangements are limited to APL’s letters of credit, issued under the provisions of APL’s revolving credit facility, totaling $5.1 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where APL operates, (ii) surety and (iii) counterparty support.

Our Equity Offerings

On June 1, 2009, a newly created, wholly-owned subsidiary of ours, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% cumulative Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash. We utilized the net proceeds from the issuance to reduce borrowings under our senior secured credit facility (see “-Our Credit Facility”). Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for our common units. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the 12% cumulative Class B Preferred Units of APL that we own, the amounts eliminate in consolidation of our consolidated balance sheet as of September 30, 2010.

APL Common Equity Offerings

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from Atlas Pipeline, GP of $0.4 million for Atlas Pipeline, GP to maintain its 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and revolving credit facility (see “-Term Loan and Revolving Credit Facility”) and to fund the early termination of certain derivative agreements. See “Item 1. Notes to Consolidated Financial Statements (Unaudited) -Note 10”.

On January 7, 2010, APL executed amendments to the warrants which were originally issued in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see “-Term Loan and Credit Facility”) and to fund the early termination of certain derivative agreements. See “Item 1. Notes to Consolidated Financial Statements (Unaudited) -Note 10”.

APL Preferred Units

Our Credit Facility

On April 13, 2010, our credit facility was terminated. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes required us to immediately repay $30 million of the borrowings under the credit facility with scheduled payments on July 13, 2009, October 13, 2009, January 13, 2010 and the balance of the indebtedness paid on April 13, 2010. All payments were made by funding from Atlas Energy under its guaranty of our obligations.

Our June 1, 2009 $30.0 million repayment was funded from the proceeds of (i) a loan from Atlas Energy in the amount of $15.0 million (see “ -Our Demand Note with Atlas Energy”) and (ii) the purchase by APL of $15.0 million of preferred equity in AHD Sub. Additionally, Atlas Energy guaranteed the remaining balance outstanding under the credit facility pursuant to a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, we issued to Atlas Energy a promissory note (see “-Our Demand Note with Atlas Energy”).

Our Demand Note with Atlas Energy

On June 1, 2009, in connection with our amendment of the credit facility, we borrowed $15.0 million from Atlas Energy under a 12% per annum subordinate loan. We incurred interest expense of $1.0 million and $0.2 million on the subordinate loan during the nine months ended September 30, 2010 and 2009, respectively, which was included in interest expense on our statements of operations. The interest was added to the balance of the subordinate loan.

Also, on June 1, 2009, in consideration of Atlas Energy’s guaranty of the indebtedness under our credit facility, we entered into a guaranty note with Atlas Energy. Atlas Energy funded $8.0 million in both the nine months ended September 30, 2010 and the twelve months ended December 31, 2009, under its guaranty of our obligations. We incurred $0.1 million and $0.2 million in fees and interest under the guaranty note during the nine months ended September 30, 2010 and 2009, respectively, which was included in interest expense on our statements of operations. The interest and fees were added to the balance of the guaranty note.

The subordinate loan and guaranty note matured on April 14, 2010, the day following the date that we repaid all outstanding borrowings under our credit facility. On July 19, 2010, we entered into an amended and consolidated demand note (the “Note”) with Atlas Energy to consolidate in one instrument the debt owed to Atlas Energy under the $15.0 million subordinate loan, the $0.3 million guaranty note and the $16.0 million advance under Atlas Energy’s guaranty of our credit facility, plus accrued interest. The initial principal of the Note is $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by Atlas Energy for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable on demand. During the three and nine months ended September 30, 2010, we accrued $1.0 million in interest expense, which was added to the principal amount of the Note. As of September 30, 2010, we reflected $34.4 million in the current portion of long term debt on our consolidated balance sheet related to our obligations to Atlas Energy.

APL Term Loan and Revolving Credit Facility

At September 30, 2010, APL had a senior secured credit facility with a syndicate of banks which consisted of a $380.0 million revolving credit facility which matures in July 2013. APL’s term loan, which was a part of the credit facility, was paid in full in September 2010. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR, subject to a floor of 2% per annum, plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at September 30, 2010 was 7.8%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $5.1 million was outstanding at September 30, 2010. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by APL’s Chaney Dell and Midkiff/Benedum joint ventures and APL’s Laurel Mountain joint venture. Borrowings are also secured by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of September 30, 2010 and expects to be in compliance in future periods.

The events which constitute an event of default for the APL credit facility include 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 September 1, 2010, APL entered into an amendment to its credit facility agreement to:

•

increase the amount APL is permitted to invest in Laurel Mountain from $10.0 million to $60.0 million per year, with any unused amount being carried forward to the next year;

•

revise the definition of “Consolidated EBITDA” to include premiums associated with permitted hedging agreements, not to exceed 15% of Consolidated EBITDA, and to exclude net after-tax gains or losses attributable to a disposition of assets other than in the ordinary course of business; and

•

effective upon the closing of APL’s sale of the Elk City system (see “Recent Events”), adjusted the maximum ratio of funded debt (as defined in the credit facility) to Consolidated EBITDA to 4.75 to 1.0 from 7.0 to 1.0; the maximum ratio of senior secured funded debt (as defined in the credit facility) to Consolidated EBITDA to 2.75 to 1.0 from 4.25 to 1.0; and the minimum ratio of Consolidated EBITDA to consolidated interest expense to 2.50 to 1.0 from 1.9 to 1.0.

As of September 30, 2010, APL’s leverage ratio was 3.16 to 1.0, its senior secured leverage ratio was 0.11 to 1.0, and its interest coverage ratio was 3.21 to 1.0.

APL Senior Notes

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, depreciation and amortization,

asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2009, and there have been no material changes to these policies through September 30, 2010.

Fair Value of Financial Instruments

We use a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

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

We and APL use a fair value methodology to value the assets and liabilities for our respective outstanding derivative contracts (see “Item 1. Notes to Consolidated Financial Statements (Unaudited -Note 10”)). At September 30, 2010, all of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3.

Recently Adopted Accounting Standards

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures - Improving Disclosures about Fair Value Measurements,” to provide enhanced disclosure requirements for activity in Levels 1, 2 and 3 fair value measurements. The update requires significant transfers in and out of Levels 1 and 2 fair value measurements to be reported separately and the reasons for such transfers to be disclosed. The update also requires information regarding purchases, sales, issuances, and settlements to be disclosed separately on a gross basis in the reconciliation of fair value measurements using unobservable inputs for all activity in Level 3 fair value measurements. Additionally, the update clarifies that fair value measurement for each class of assets and liabilities must be disclosed as well as disclosures pertaining to the inputs and valuation techniques for both recurring and nonrecurring fair value measurements in Levels 2 and 3. These requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those requirements will be effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We adopted these requirements on January 1, 2010 and it did not have a material impact on our financial position, results of operations or related disclosures.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. As our assets currently consist solely of our ownership interests in APL, the following information principally encompasses APL’s exposure to market risks unless otherwise noted. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our and APL’s market risk sensitive instruments were entered into for purposes other than trading.

General

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

We and APL 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 APL manage these risks through regular operating and financing activities and periodical use of derivative instruments. 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 September 30, 2010. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and APL’s business.

Current market conditions elevate our and APL’s concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us and APL, if any. The counterparties to APL’s commodity derivative contracts are banking institutions currently participating in APL’s revolving credit facility. We and APL may choose to do business with counterparties outside of APL’s credit facility in the future. The creditworthiness of our and APL’s counterparties is constantly monitored, and we and APL are not aware of any inability on the part of our respective counterparties to perform under our contracts.

Interest Rate Risk. At September 30, 2010, APL had a $380.0 million senior secured revolving credit facility ($12.0 million outstanding). Borrowings under APL’s credit facility bear interest, at APL’s option at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL entered into an amendment to its senior secured revolving credit facility agreement which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. The weighted average interest rate for APL’s revolving credit facility borrowings was 7.8% at September 30, 2010. At September 30, 2010, we and APL had no interest rate derivative contracts. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would not change our and APL’s annual interest expense.

Commodity Price Risk. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. For gathering services, APL receives fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, APL either receives fees or commodities as payment for these services, based on the type of contractual agreement. APL uses a number of different derivative instruments in connection with its commodity price risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract

period. See “Item 1. Notes to Consolidated Financial Statements (Unaudited) Note 10” for further discussion of APL’s derivative instruments. Average estimated 2010 market prices for NGLs, natural gas and condensate, based upon New York Mercantile Exchange (“NYMEX”) forward price curves as of October 6, 2010, are $1.05 per gallon, $4.30 per million BTU and $85.65 per barrel, respectively. A 10% change in these prices would change APL’s forecasted gross margin for the twelve-month period ended September 30, 2011 by approximately $15.0 million.

During the nine months ended September 30, 2010 and 2009, APL made net payments of $25.3 million and $5.0 million, respectively, related to the early termination of derivative contracts. The terminated derivative contracts were to expire at various times through the fourth quarter of 2010. During the three and nine months ended September 30, 2010 and 2009, we recognized the following derivative activity related to APL’s early termination of these derivative instruments within our consolidated statements of operations (in thousands):


Early termination of derivative contracts	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Cash paid for early termination	$	—		$	—		$	(25,315	)	$	(5,000	)
Equity applied to prior period early termination		—			—			(8,421	)		—

Total realized loss at early termination⁽²⁾	$	—		$	—		$	(33,736	)	$	(5,000	)


Net cash derivative gain included within natural gas and liquids revenue	$	—		$	—		$	12,198		$	—
Net cash derivative expense included within other income (loss), net		—			—			(34,599	)		(2,260	)
Net cash derivative expense included within discontinued operations		—			—			(11,335	)		(2,740	)

Total realized loss at early termination⁽²⁾		—			—			(33,736	)		(5,000	)
Recognition of deferred hedge loss from prior periods included within natural gas and liquids revenue⁽³⁾		(2,519	)		(13,565	)		(23,216	)		(33,629	)
Recognition of deferred hedge gain from prior periods included within other income (loss), net⁽³⁾		2,911			11,262			32,150			24,148
Recognition of deferred hedge gain from prior periods included within discontinued operations⁽³⁾		(1,325	)		(2,185	)		4,137			(9,854	)

Total realized loss from early termination recognized in current period⁽²⁾	$	(933	)	$	(4,488	)	$	(20,665	)	$	(24,335	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to our sale of the Elk City gas gathering and processing systems (see “-Recent Events”).

(2)

Realized gain (loss) represents the gain/loss recognized when the derivative contract is settled. A portion of realized gain (loss) recognized in other income (loss), net is a reclassification of unrealized gain (loss) previously recognized as a factor of recording the changes in the fair value of the derivatives prior to settlement.

(3)	Non-Cash recognition of deferred hedge gain (loss) includes (i) theoretical premiums related to calls sold in conjunction with puts purchased in costless collars in which the puts were sold as part of the equity unwinds in 2008 and (ii) the effective portion of hedges deferred to OCI.

In addition, we will recognize, in our consolidated statement of operations, $5.8 million net income, related to APL derivative contracts terminated in 2008, during the periods for which the hedged physical transactions are forecasted to be settled, with $0.7 million of income to be recognized during the remainder of the year ending December 31, 2010 and $2.8 million and $2.3 million of income to be recognized during the years ending December 31, 2011 and 2012, respectively.

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 September 30, 2010, 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.

PART II. OTHER INFORMATION

ITEM 1A.

RISK FACTORS

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, the investor should consider carefully the risks and uncertainties described in this item and under Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2009. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s and APL’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership and APL, which participate in that market. The Commodity Futures Trading Commission (“CFTC”) has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require the Partnership and APL to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to the Partnership and APL is uncertain at this time. The financial reform legislation may also require the counterparties to the Partnership’s and APL’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral); materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks the Partnership and APL encounters; reduce APL’s ability to monetize or restructure its existing derivative contracts; and increase the exposure to less creditworthy counterparties. If APL reduces its use of derivatives as a result of the legislation and regulations, the Partnership’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Partnership’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership, its financial condition, and its results of operations.

ITEM 6.

EXHIBITS


Exhibit No.		Description

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

3.2(a)		Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽²⁾

3.2(b)		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P. ⁽³⁾

4.1		Specimen Certificate Representing Common Units⁽¹⁾

10.1		Certificate of Formation of Atlas Pipeline Holdings GP, LLC⁽¹⁾

10.2(a)		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽¹⁾

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

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

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

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

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

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

10.2(h)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹³⁾

10.2(i)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁵⁾

10.3		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽¹³⁾

10.4		Amended and Restated Certificate of Designation for 12% Cumulative Class B Preferred Units of Atlas Pipeline Partners, L.P.⁽⁷⁾

10.5		Certificate of Designation for 12% Cumulative Class C Preferred Units of Atlas Pipeline Partners, L.P.⁽¹⁵⁾

10.6		Long-Term Incentive Plan⁽⁶⁾

10.7(a)		Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereto⁽²⁾

10.7(b)		First Amendment to Revolving Credit Agreement dated as of June 1, 2009⁽⁸⁾

10.8		Atlas Pipeline Holdings II, LLC Limited Liability Company Agreement⁽⁸⁾

10.9		Promissory Note to Atlas America, Inc. dated June 1, 2009⁽⁸⁾

10.10		Guaranty Note to Atlas America, Inc. dated June 1, 2009⁽⁸⁾

10.11		Amended, Restated and Consolidated Promissory Note to Atlas Energy, Inc., dated July 19, 2010⁽¹⁴⁾

10.12		ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC⁽⁹⁾

10.13		Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009⁽⁹⁾

10.14(a)		Revolving Credit and Term Loan Agreement dated July 27, 2007 among Atlas Pipeline Partners, L.P., the guarantors therein, Wachovia Bank, National Association, and other banks party thereto⁽¹¹⁾

10.14(b)		Amendment No. 1 and Agreement to the Revolving Credit and Term Loan Agreement, dated June 12, 2008⁽¹¹⁾

10.14(c)		Amendment No. 2 to Revolving Credit and Term Loan Agreement, dated May 29, 2009 ⁽¹⁰⁾

10.14(d)		Amendment No. 3 to Revolving Credit and Term Loan Agreement, dated September 1, 2010⁽¹⁷⁾

10.15		Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP ⁽¹¹⁾


10.16		Securities Purchase Agreement, dated July 27, 2010, by and among Atlas Pipeline Mid-Continent, LLC, Atlas Pipeline Partners, L.P., Enbridge Pipelines (Texas Gathering) L.P. and Enbridge Energy Partners, L.P.⁽¹⁶⁾

10.17		Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras⁽¹²⁾

10.18		Form of Grant of Phantom Units to Non-Employee Managers

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

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



32.1		Section 1350 Certification

32.2		Section 1350 Certification

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

(2)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2006.

(3)	Previously filed as an exhibit to current report on Form 8-K filed January 8, 2008.

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

(5)	[Intentionally Omitted]

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

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

(8)	Previously filed as an exhibit to current report on Form 8-K filed June 2, 2009.

(9)	Previously filed as an exhibit to current report on Form 8-K filed June 5, 2009.

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

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

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

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

(14)	Previously filed as an exhibit to current report on Form 8-K filed July 23, 2010.

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

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

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

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 PIPELINE HOLDINGS, L.P.
		By: Atlas Pipeline Holdings GP, LLC, its General Partner

Date: November 9, 2010	By:	/s/ EUGENE N. DUBAY
		Eugene N. Dubay
		Chief Executive Officer, President, and Managing Board Member of the General Partner

Date: November 9, 2010	By:	/s/ ERIC T. KALAMARAS
		Eric T. Kalamaras
		Chief Financial Officer of the General Partner

Date: November 9, 2010	By:	/s/ ROBERT W. KARLOVICH, III
		Robert W. Karlovich, III
		Chief Accounting Officer of the General Partner

Targa Energy LP - FORM 10-Q - November 9, 2010

Attached files

Targa Energy LP Reports