Edgar Filing: ATLAS PIPELINE PARTNERS LP

Form 10-Q

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, 2007

¨	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:1-4998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


DELAWARE		23-3011077
(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

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

ATLAS PIPELINE PARTNERS, 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, 2007 and December 31, 2006 (Unaudited)	3

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2007 and 2006 (Unaudited)	4

	Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2007 (Unaudited)	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006 (Unaudited)	6

	Notes to Consolidated Financial Statements (Unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	46

PART II.	OTHER INFORMATION

Item 6.	Exhibits	47

SIGNATURES		48

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	September 30, 2007			December 31, 2006
ASSETS

Current assets:
Cash and cash equivalents	$	24,808		$	1,795
Accounts receivable – affiliates		3,856			7,601
Accounts receivable		114,991			51,192
Current portion of derivative asset		—			5,437
Prepaid expenses and other		9,165			10,444

Total current assets		152,820			76,469

Property, plant and equipment, net		2,546,887			607,097

Long-term derivative asset		—			305

Intangible assets, net		24,131			25,530

Goodwill		63,441			63,441

Other assets, net		20,592			14,042

	$	2,807,871		$	786,884


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Current portion of long-term debt	$	35		$	71
Accounts payable		22,077			18,624
Accrued liabilities		32,057			6,410
Current portion of derivative liability		52,705			17,362
Accrued producer liabilities		65,121			32,766

Total current liabilities		171,995			75,233

Long-term derivative liability		39,323			8,505

Long-term debt, less current portion		1,157,928			324,012

Minority interest		16,143			—

Commitments and contingencies

Partners’ capital:
Preferred limited partner’s interests		36,441			39,381
Common limited partners’ interests		1,408,988			350,805
General partner’s interest		31,784			11,034
Accumulated other comprehensive loss		(54,731	)		(22,086	)

Total partners’ capital		1,422,482			379,134

	$	2,807,871		$	786,884

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, 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,
	2007			2006			2007			2006
Revenue:
Natural gas and liquids	$	229,891		$	99,997		$	436,859		$	296,083
Transportation, compression and other fees – affiliates		8,495			6,951			24,673			22,659
Transportation, compression and other fees – third Parties		12,948			6,726			33,374			20,882
Other income (loss)		(9,034	)		6,872			(39,654	)		8,233

Total revenue and other income (loss)		242,300			120,546			455,252			347,857

Costs and expenses:
Natural gas and liquids		174,727			89,679			349,639			252,577
Plant operating		9,108			3,853			18,153			11,006
Transportation and compression		3,555			2,714			9,877			7,639
General and administrative		36,424			5,069			48,735			13,465
Compensation reimbursement – affiliates		1,392			378			2,820			1,983
Depreciation and amortization		16,176			6,152			29,381			16,685
Interest		24,040			5,700			38,126			18,191
Minority interest		1,376			—			1,376			118

Total costs and expenses		266,798			113,545			498,107			321,664

Net income (loss)		(24,498	)		7,001			(42,855	)		26,193
Preferred unit dividend effect		—			—			(3,756	)		—
Preferred unit imputed dividend cost		(624	)		(627	)		(1,858	)		(1,262	)

Net income (loss) attributable to common limited partners and the general partner	$	(25,122	)	$	6,374		$	(48,469	)	$	24,931

Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(28,242	)	$	2,567		$	(58,854	)	$	13,664
General partner’s interest		3,120			3,807			10,385			11,267

Net income (loss) attributable to common limited partners and the general partner	$	(25,122	)	$	6,374		$	(48,469	)	$	24,931

Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.90	)	$	0.20		$	(3.05	)	$	1.07

Diluted	$	(0.90	)	$	0.19		$	(3.05	)	$	1.05

Weighted average common limited partner units outstanding:
Basic		31,449			13,076			19,270			12,818

Diluted		31,449			13,248			19,270			12,975

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2007

(in thousands, except unit data)

(Unaudited)


	Number of Limited Partner Units		Preferred Limited Partner			Common Limited Partners			General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Capital
	Preferred	Common	Preferred Limited Partner			Common Limited Partners			General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Capital
Balance at January 1, 2007	40,000	13,080,418	$	39,381		$	350,805		$	11,034		$	(22,086	)	$	379,134
Preferred unit dividend	—	—		(8,524	)		—			—			—			(8,524	)
Costs incurred related to issuance of preferred dividend	—	—		(30	)		—			—			—			(30	)
Issuance of common units	—	25,606,576					1,115,275			—			—			1,115,275
Capital contribution	—	—		—			—			23,076			—			23,076
Unissued common units under incentive plans	—	—		—			36,136			—			—			36,136
Costs incurred related to issuance of units under incentive plans	—	—		—			(40	)		—			—			(40	)
Distributions paid to common limited partners and the general partner	—	—		—			(33,879	)		(12,711	)		—			(46,590	)
Distribution equivalent rights paid on unissued units under incentive plans	—	—		—			(455	)		—			—			(455	)
Other comprehensive loss	—	—		—			—			—			(32,645	)		(32,645	)
Net income (loss)	—	—		5,614			(58,854	)		10,385			—			(42,855	)

Balance at September 30, 2007	40,000	38,686,994	$	36,441		$	1,408,988		$	31,784		$	(54,731	)	$	1,422,482

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(42,855	)	$	26,193
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		29,381			16,685
Non-cash loss (gain) on derivative value		39,256			(2,107	)
Non-cash compensation expense		36,096			4,125
Amortization of deferred finance costs		6,690			1,753
Minority interest		16,143			118
Gain on asset sales and dispositions		—			(2,639	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(62,980	)		7,434
Accounts payable and accrued liabilities		61,455			(9,648	)
Accounts payable and accounts receivable – affiliates		3,747			(1,999	)

Net cash provided by operating activities		86,933			39,915

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		(1,873,703	)		(30,000	)
Capital expenditures		(93,660	)		(61,743	)
Proceeds from sales of assets		—			7,559
Other		(561	)		67

Net cash used in investing activities		(1,967,924	)		(84,117	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of debt		826,073			36,610
Payment of preferred unit dividend		(8,524	)		—
Repayment of debt		—			(38,990	)
Borrowings under credit facility		197,500			37,000
Repayments under credit facility		(202,000	)		(33,000	)
Net proceeds from issuance of common limited partner units		1,115,275			19,704
Net proceeds from issuance of preferred limited partner units		—			39,906
General partner capital contribution		23,076			1,206
Distributions paid to common limited partners and the general partner		(46,590	)		(43,539	)
Other		(806	)		(946	)

Net cash provided by financing activities		1,904,004			17,951

Net change in cash and cash equivalents		23,013			(26,251	)
Cash and cash equivalents, beginning of period		1,795			34,237

Cash and cash equivalents, end of period	$	24,808		$	7,986

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2007

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the transmission, gathering and processing of natural gas. The Partnership’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 the Partnership. Atlas Pipeline Partners GP, LLC (the “General Partner”), through its general partner interests in the Partnership and the Operating Partnership, owns a 2% general partner interest in the consolidated pipeline operations, through which it manages and effectively controls both the Partnership and the Operating Partnership. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests. The General Partner also owns 5,476,253 limited partner units in the Partnership which have not been registered with the Securities and Exchange Commission and, therefore, their resale in the public market is subject to restrictions under the Securities Act. On October 10, 2007, the Partnership filed a registration statement on Form S-3 which would, among other things, register the resale of the limited partner units. The registration statement is not yet effective. At September 30, 2007, the Partnership had 38,686,994 common limited partnership units, including the 5,476,253 unregistered common units held by the General Partner, and 40,000 $1,000 par value cumulative convertible preferred limited partnership units outstanding (see Note 4).

The Partnership’s General Partner is a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P. (“AHD”), a publicly-traded partnership (NYSE: AHD). Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), had a 64.0% ownership interest in AHD’s outstanding common units at September 30, 2007. Atlas America also had a 49.0% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN) focused on the development of natural gas and oil in the Appalachian basin. Substantially all of the natural gas the Partnership transports in the Appalachian Basin is derived from wells operated by Atlas Energy.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2006 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, 2006. The results of operations for the three and nine month periods ended September 30, 2007 may not necessarily be indicative of the results of operations for the full year ending December 31, 2007.

Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation. During June 2006, the Partnership identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during the third and fourth quarters of 2005 and first quarter of 2006, the Partnership recorded an adjustment of $1.2 million during the second quarter of 2006 to increase natural gas and liquids cost of goods sold. If the $1.2 million adjustment had been recorded when the inaccuracies arose, reported net income would have been reduced by approximately 2.7%, 8.3% and 1.4% for the third quarter of 2005, fourth quarter of 2005, and first quarter of 2006, respectively.

In August 2006, the Partnership sustained fire damage to a compressor station within the Velma region of its Mid-Continent segment. The Partnership maintains property damage and business interruption insurance for all of its assets and operating activities. At September 30, 2006, the Partnership recorded $1.2 million in prepaid expenses and other within its consolidated balance sheet for the estimated net book value of the assets damaged as a result of the incident, which were expected to be recoverable through cash proceeds received from its insurance coverage. During the fourth quarter of 2006, the Partnership received a $1.5 million partial settlement from its insurance providers related to this incident and reached a final settlement for an additional $2.6 million of insurance proceeds to be received during the first quarter of 2007. At December 31, 2006, the Partnership recorded the additional $2.6 million in prepaid expenses and other within its consolidated balance sheet and interest income and other within its consolidated statements of operations for the insurance proceeds settlement amount, which was received in February 2007.

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, 2006.

Principles of Consolidation and Minority Interest

The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. The General Partner’s interest in the Operating Partnership is reported as part of its overall 2% general partner interest in the Partnership. All material intercompany transactions have been eliminated.

On July 27, 2007, the Partnership acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 8). The transaction was effected by the formation of two joint venture companies which own the respective systems, of which the Partnership has a 95% ownership interest and Anadarko has a 5% interest in each. The Partnership consolidates 100% of these joint ventures. The Partnership reflects Anadarko’s 5% ownership interest in the net income of these joint ventures as minority interest on its statements of operations. The Partnership also reflects Anadarko’s investment in the net assets of the joint ventures as minority interest on its consolidated balance sheet. In connection with the Partnership’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, the joint ventures issued cash to Anadarko of $1.9 billion in return for a note receivable. This note receivable is reflected within minority interest on the Partnership’s consolidated balance sheet.

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 Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system.

The consolidated financial statements also include the financial statements of NOARK Pipeline System, Limited Partnership (“NOARK”), an entity in which the Partnership currently owns a 100% ownership interest (see Note 8). In May 2006, the Partnership acquired the remaining 25% ownership interest in NOARK from Southwestern Energy Pipeline Company (“Southwestern”), a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Prior to this transaction, the Partnership owned a 75% ownership interest in NOARK, which it had acquired in October 2005 from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE). In connection with the acquisition of the remaining 25% ownership interest, Southwestern assumed liability for $39.0 million in principal amount outstanding of NOARK’s 7.15% notes due in 2018, which had been presented as long-term debt on the Partnership’s consolidated balance sheet prior to the acquisition of the remaining 25% ownership interest. Subsequent to the acquisition of the remaining 25%

ownership interest in NOARK, the Partnership consolidates 100% of NOARK’s financial statements. The minority interest expense reflected on the Partnership’s consolidated statements of operations for the nine months ended September 30, 2006 represents Southwestern’s interest in NOARK’s net income prior to the May 2006 acquisition.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Actual results could differ from those estimates (see Item 2, “Management’s Discussion and Analysis” for further discussion).

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 for the three and nine months ended September 30, 2007 represent actual results in all material respects (see “–Revenue Recognition” accounting policy for further description).

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholder’s interests, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its 2% interest and incentive distributions (see Note 5), with a priority allocation of net income in an amount equal to the general partner’s incentive distributions, in accordance with the partnership agreement, and the remaining net income or loss allocated with respect to the general partner’s and limited partners’ ownership interests. Diluted net income attributable to common limited partners per unit is calculated by dividing net income attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of phantom unit awards, as calculated by the treasury stock method, and the dilutive effect of convertible securities. Phantom units consist of common units issuable under the terms of the Partnership’s Long-Term Incentive Plan and Incentive Compensation Agreements (see Note 12). The following table sets forth the reconciliation of the weighted average number of common limited partner units used to compute basic net income attributable to common limited partners per unit with those used to compute diluted net income attributable to common limited partners per unit (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
Weighted average number of common limited partner units – basic	31,449	13,076	19,270	12,818
Add: effect of dilutive unit incentive awards⁽¹⁾	—	172	—	157

Weighted average number of common limited partner units – diluted	31,449	13,248	19,270	12,975

⁽¹⁾	For the three and nine months ended September 30, 2007, approximately 619,000 and 378,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

For the periods presented in the table above, potential common limited partner units issuable upon conversion of the Partnership’s 40,000 $1000 par value cumulative convertible preferred limited partner units were excluded from the computation of diluted net income (loss) attributable to common limited partners as the impact of the conversion would have been anti-dilutive (see Note 4 for additional information regarding the conversion features of the preferred limited partner units).

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)” and include only changes in the fair value of unsettled derivative contracts. 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,
	2007			2006			2007			2006
Net income (loss)	$	(24,498	)	$	7,001		$	(42,855	)	$	26,193

Preferred unit dividend		—			—			(3,756	)		—

Preferred unit imputed dividend cost		(624	)		(627	)		(1,858	)		(1,262	)

Net (loss) income attributable to common limited partners and the general partner		(25,122	)		6,374			(48,469	)		24,931

Other comprehensive income (loss):

Changes in fair value of derivative instruments accounted for as hedges		(38,072	)		8,536			(56,193	)		(9,935	)
Add: adjustment for realized losses reclassified to net income (loss)		12,850			4,896			23,548			10,518

Total other comprehensive (loss) income		(25,222	)		13,432			(32,645	)		583

Comprehensive (loss) income	$	(50,344	)	$	19,806		$	(81,114	)	$	25,514

Revenue Recognition

Revenue in the Partnership’s Appalachia segment is recognized at the time the natural gas is transported through its gathering systems. Under the terms of its natural gas gathering agreements with Atlas Energy and its affiliates, the Partnership receives fees for gathering natural gas from wells owned by Atlas Energy and by drilling investment partnerships sponsored by Atlas Energy. The fees received for the gathering services under the Atlas Energy agreements are generally the greater of 16% of the gross sales price for gas produced from the wells, or $0.35 or $0.40 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantially all natural gas gathering revenue in the Appalachia segment is derived from these agreements. Fees for transportation services provided to independent third parties whose wells are connected to the Partnership’s Appalachia gathering systems are at separately negotiated prices.

The Partnership’s Mid-Continent segment revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, the Partnership purchases 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, the

Partnership transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the Partnership’s regulated transmission pipeline is recognized at the time the transportation service is provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with the Partnership’s gathering and processing operations, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. The Partnership’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.

POP Contracts. These contracts provide for the Partnership to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, the Partnership and the producer are directly dependent on the volume of the commodity and its value; the Partnership owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require the Partnership, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, the Partnership bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas received by the Elk City/Sweetwater system, which has keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the natural gas can be bypassed around the Elk City and Sweetwater processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at September 30, 2007 and December 31, 2006 of $72.4 million and $20.2 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within its consolidated balance sheets.

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 8.1% and 8.0% for the three and nine months ended September 30, 2007, respectively, and 8.1% for both the three and nine months ended September 30, 2006. The amount of interest capitalized was $0.8 million and $1.0 million for the three months ended September 30, 2007 and 2006, respectively, and $1.8 million and $1.9 million for both the nine months ended September 30, 2007 and 2006.

Intangible Assets

The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions (see Note 8). The following table reflects the components of intangible assets being amortized at September 30, 2007 and December 31, 2006 (in thousands):


	September 30, 2007			December 31, 2006			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts	$	12,810		$	12,390		8
Customer relationships		17,260			17,260		20

	$	30,070		$	29,650

Accumulated Amortization:
Customer contracts	$	(3,818	)	$	(2,646	)
Customer relationships		(2,121	)		(1,474	)

	$	(5,939	)	$	(4,120	)

Net Carrying Amount:
Customer contracts	$	8,992		$	9,744
Customer relationships		15,139			15,786

	$	24,131		$	25,530

During the third quarter of 2006, the Partnership adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to customer contracts and customer relationships based upon the findings of an independent valuation firm (see Note 8) and allocated additional amounts to property, plant and equipment (see Note 6).

Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized 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, the Partnership will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for the Partnership’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence at the date of acquisition. The estimated useful life for the Partnership’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition. Amortization expense on intangible assets was $0.6 million and ($0.9) million for the three months ended September 30, 2007 and 2006, respectively, and $1.8 million and $1.4 million for the nine months ended September 30, 2007 and 2006, respectively. Amortization expense related to intangible assets is estimated to be $2.5 million for each of the next five calendar years commencing in 2008.

Goodwill

At September 30, 2007 and December 31, 2006, the Partnership had $63.4 million of goodwill recorded in connection with consummated acquisitions (see Note 8). The changes in the carrying amount of goodwill for the nine months ended September 30, 2007 and 2006 were as follows (in thousands):


	Nine Months Ended September 30,
	2007		2006
Balance, beginning of period	$	63,441	$	111,446
Goodwill acquired (preliminary allocation) – 25% interest in NOARK		—		30,195
Reduction in minority interest deficit acquired		—		(118	)
Purchase price allocation adjustment – NOARK		—		(78,082	)

Balance, end of period	$	63,441	$	63,441

During the third quarter of 2006, the Partnership adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to goodwill based upon the findings of an independent valuation firm (see Note 8) and allocated additional amounts to property, plant and equipment (see Note 6). The Partnership tests its goodwill for impairment at each year end by comparing enterprise fair values to carrying values. The evaluation of impairment under SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performance of the Partnership’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Partnership’s assumptions and, if required, recognition of an impairment loss. The Partnership’s test of goodwill at December 31, 2006 resulted in no impairment, and no impairment indicators have been noted as of September 30, 2007. The Partnership will continue to evaluate its goodwill at least annually and if impairment indicators arise, and will reflect the impairment of goodwill, if any, within the consolidated statement of operations for the period in which the impairment is indicated.

New Accounting Standards

In September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2007. The Partnership has previously followed the requirements of EITF No. 03-6 in calculating its net earnings per limited partner unit and will apply the requirements of EITF No. 07-4 as it pertains to MLPs upon its adoption during the quarter ended March 31, 2008.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. SFAS No. 159 offers various options in electing to apply its provisions, and at this time the Partnership has not made any decisions with regards to its application to its financial position or results of operations. The Partnership is currently evaluating whether SFAS No. 159 will have an impact on its financial position and results of operations.

In December 2006, the FASB issued FASB Staff Position EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“EITF 00-19-2”). EITF 00-19-2 provides guidance related to the accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”). EITF 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. The Partnership adopted EITF 00-19-2 on January 1, 2007. The Partnership reviewed the penalty terms in the registration rights agreement related to its private placement entered into on July 27, 2007 (see Note 3), pursuant to the guidance in the EITF, and determined that the probability of payment is remote under SFAS No. 5 based upon the Partnership’s status of current related filings. As a result, the application of EITF 00-19-2 did not have an effect on the Partnership’s financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. This statement does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Partnership is currently evaluating whether SFAS No. 157 will have an impact on its financial position and results of operations.

NOTE 3 – COMMON UNIT EQUITY OFFERINGS

In July 2007, the Partnership sold 25.6 million common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25.6 million common units sold by the Partnership, 3.8 million were purchased by AHD for $168.8 million. The Partnership also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in the Partnership. The Partnership utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 8).

The common units sold by the Partnership in the July 2007 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulates that the Partnership will (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. If the Partnership does not meet the aforementioned deadline for the common units to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.25% of the gross proceeds from the private placement, or approximately $2.8 million, for the first 30-day period after March 2, 2008, increasing by an additional 0.25% per 30-day period thereafter, up to a maximum of 1.0% of the gross proceeds of the private placement per 30-day period. On October 10, 2007, the Partnership filed a registration statement with the Securities and Exchange Commission for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously.

In May 2006, the Partnership sold 500,000 common units to Wachovia Securities, which then offered the common units to public investors. The units, which were issued under the Partnership’s previously filed shelf registration statement, resulted in net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. The Partnership utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with its acquisition of the remaining 25% ownership interest in NOARK.

NOTE 4 – PREFERRED UNIT EQUITY OFFERING

On March 13, 2006, the Partnership entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. The Partnership also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to the Partnership’s right under the agreement to require Sunlight Capital to purchase such additional units. The preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for the Partnership’s common units. On April 18, 2007, the Partnership and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of the preferred units were amended to entitle them to receive dividends of 6.5% per annum commencing on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for common unit distributions after March 13, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of the Partnership’s common units as of the date of the notice of conversion. The Partnership may elect to pay cash rather than issue common units in satisfaction of a

conversion request. The Partnership has the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.82. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, the Partnership issued $8.5 million of its 8.125% senior unsecured notes due 2015 (the “Notes”) (see Note 10) to Sunlight Capital. The Partnership recorded the Notes as long-term debt and a preferred unit dividend within partners’ capital, and has reduced net income attributable to common limited partners and the general partner by $3.8 million of this amount, which is the portion deemed to be attributable to the concessions of the common limited partners and the general partner to the preferred unitholder, on its consolidated statements of operations.

The preferred units are reflected on the Partnership’s consolidated balance sheet as preferred equity within partners’ capital. In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 68, “Increasing Rate Preferred Stock,” the preferred units were originally recorded on the consolidated balance sheet at the amount of net proceeds received less an imputed dividend cost. The imputed dividend cost of $2.4 million was the result of the preferred units not having a dividend yield during the first year after their issuance on March 13, 2006 and was amortized in full as of March 12, 2007. As a result of the amended agreement, the Partnership recognized an imputed dividend cost of $2.5 million that will be amortized during the year commencing March 13, 2007 and is based upon the present value of the net proceeds received using the 6.5% stated yield.

Amortization of the imputed dividend cost, which is presented as a reduction of net income to determine net income attributable to common limited partners and the general partner on its consolidated statements of operations, was $0.6 million and $1.9 million for the three and nine months ended September 30, 2007, respectively. Amortization of the imputed dividend cost was $0.6 million and $1.3 million for the three and nine months ended September 30, 2006, respectively, based on the $2.4 million imputed cost during the initial year after the unit issuance. If converted to common units, the preferred equity amount converted will be reclassified to common unit equity within partners’ capital on the Partnership’s consolidated balance sheet. Dividends accrued and paid on the preferred units and the premium paid upon their redemption, if any, will be recognized as a reduction to the Partnership’s net income in determining net income attributable to common unitholders and the general partner.

The net proceeds from the initial issuance of the preferred units were used to fund a portion of the Partnership’s capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system. The proceeds from the issuance of the additional 10,000 preferred units were used to reduce indebtedness under the Partnership’s credit facility incurred in connection with the acquisition of the remaining 25% ownership interest in NOARK.

NOTE 5 – CASH DISTRIBUTIONS

The Partnership 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. If distributions in any quarter exceed specified target levels, the general partner will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by the Partnership for the period from January 1, 2006 through September 30, 2007 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 14, 2006	December 31, 2005	$	0.83	$	10,416	$	3,638
May 15, 2006	March 31, 2006		0.84		10,541		3,766
August 14, 2006	June 30, 2006		0.85		11,118		4,059
November 14, 2006	September 30, 2006		0.85		11,118		4,059

February 14, 2007	December 31, 2006		0.86		11,249		4,193
May 15, 2007	March 31, 2007		0.86		11,249		4,193
August 14, 2007	June 30, 2007		0.87		11,380		4,326

In connection with the Partnership’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 8), AHD, which holds all of the incentive distribution rights in the Partnership, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to the Partnership through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

On October 23, 2007, the Partnership declared a cash distribution of $0.91 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2007. The $39.7 million distribution, including $4.5 million to the General Partner after the allocation of $4.9 of its incentive distribution rights back to the Partnership, will be paid on November 14, 2007 to unitholders of record at the close of business on November 7, 2007.

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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


	September 30, 2007			December 31, 2006			Estimated Useful Lives in Years
Pipelines, processing and compression facilities	$	2,289,773		$	611,575		15 – 40
Rights of way		313,165			30,401		20 – 40
Buildings		4,230			3,800		40
Furniture and equipment		5,600			3,288		3 – 7
Other		5,624			2,081		3 – 10

		2,618,392			651,145
Less – accumulated depreciation		(71,505	)		(44,048	)

	$	2,546,887		$	607,097

In July 2007, the Partnership acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 8). Due to the recent date of acquisition, the purchase price allocation is based upon estimated values determined by the Partnership, which are subject to adjustment and could change significantly as it continues to evaluate this allocation. At September 30, 2007, the portion of the purchase price allocated to property, plant and equipment for this acquisition is primarily located within pipeline, processing, and compression facilities.

In May 2006, the Partnership acquired the remaining 25% ownership interest in NOARK for $69.0 million in cash, including the repayment of the $39.0 million of NOARK notes at the date of acquisition (see Note 8). The Partnership acquired the initial 75% ownership interest in NOARK for approximately $179.8 million in October 2005 (see Note 8). During the third quarter of 2006, the Partnership adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to customer contracts and customer relationships intangible assets and goodwill based upon the findings of an independent valuation firm (see Note 8) and allocated additional amounts to property, plant and equipment.

NOTE 7 – OTHER ASSETS

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


	September 30, 2007		December 31, 2006
Deferred finance costs, net of accumulated amortization of $10,662 and $3,972 at September 30, 2007 and December 31, 2006, respectively	$	18,470	$	12,530
Security deposits		1,915		1,415
Other		207		97

	$	20,592	$	14,042

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 10). In July 2007, the Partnership recorded $5.0 million for accelerated amortization of deferred financing costs associated with the replacement of its previous credit facility with a new facility (see Note 10).

NOTE 8 – ACQUISITIONS

Chaney Dell and Midkiff/Benedum

On July 27, 2007, the Partnership acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which the Partnership contributed $1.9 billion and Anadarko contributed the Assets.

In connection with this acquisition, the Partnership has reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.5% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. The Partnership will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

The Partnership funded the purchase price in part from the private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by AHD. AHD, which holds all of the incentive distribution rights in the Partnership, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to the Partnership through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (see Note 5). The Partnership funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see Note 10).

The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the preliminary purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):


Prepaid expenses and other	$	1,254
Property, plant and equipment		1,879,581

Total assets acquired		1,880,835

Accounts payable and accrued liabilities		(2,209	)

Net cash paid for acquisition	$	1,878,626

Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change significantly as the Partnership continues to evaluate this allocation. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Partnership’s consolidated financial statements from the date of acquisition.

NOARK

In May 2006, the Partnership acquired the remaining 25% ownership interest in NOARK from Southwestern, for a net purchase price of $65.5 million, consisting of $69.0 million of cash to the seller (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in NOARK’s working capital (including cash on hand and net payables to the seller) at the date of acquisition of $3.5 million. In October 2005, the Partnership acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas Pipeline, LLC, which owned the initial 75% ownership interest in NOARK, for total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. NOARK’s assets included a Federal Energy Regulatory Commission (“FERC”)-regulated interstate pipeline and an unregulated natural gas gathering system. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in both acquisitions, based on their fair values at the date of the respective acquisitions (in thousands):


Cash and cash equivalents	$	16,215
Accounts receivable		11,091
Prepaid expenses		497
Property, plant and equipment		232,576
Other assets		140

Total assets acquired		260,519

Accounts payable and accrued liabilities		(50,689	)

Net assets acquired		209,830

Less: Cash and cash equivalents acquired		(16,215	)

Net cash paid for acquisitions	$	193,615

The Partnership’s ownership interests in the results of NOARK’s operations associated with each acquisition are included within its consolidated financial statements from the respective dates of the acquisitions.

The following data presents pro forma revenue and net income for the Partnership as if the acquisitions discussed above, the equity offerings in July 2007 and May 2006 (see Note 3), the issuance of an $830.0 million term loan and a new $300.0 million senior secured credit facility and respective borrowings under these facilities (see note 10), the May 2006 issuance of senior notes (see note 10), and the May 2006 and March 2006 issuances of the cumulative convertible preferred units (see Note 4) had occurred on January 1, 2006. The Partnership has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if the Partnership had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per unit data):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2006		2007			2006
Total revenue and other income (loss)	$	242,300		$	304,661	$	776,484		$	844,231
Net income (loss)	$	(19,417	)	$	14,371	$	(33,066	)	$	28,941
Net income (loss) attributable to common limited partners and the general partner	$	(23,274	)	$	9,782	$	(49,257	)	$	12,907
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.60	)	$	0.25	$	(1.27	)	$	0.31

Diluted	$	(0.60	)	$	0.25	$	(1.27	)	$	0.31

NOTE 9 – DERIVATIVE INSTRUMENTS

The Partnership 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 swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

The Partnership formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity futures and derivative contracts to the forecasted transactions. The Partnership assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying commodity, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Partnership through the utilization of market data, will be recognized immediately within other income (loss) in its consolidated statements of operations.

Derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassifies them to natural gas and liquids revenue within natural gas and liquids revenue in its consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss) in its consolidated statements of operations as they occur. At September 30, 2007 and December 31, 2006, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $92.0 million and $20.1 million, respectively. Of the $54.7 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at September 30, 2007, if the fair values of the instruments remain at current market values, the Partnership will reclassify $35.1 million of losses to natural gas and liquids revenue in its consolidated statements of operations over the next twelve month period as these contracts expire, and $19.6 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes.

On June 3, 2007, the Partnership signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see Note 8). In connection with certain additional agreements entered into to finance this transaction, the Partnership agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, the Partnership entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreements. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, the Partnership recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in its consolidated statements of operations. The Partnership recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the nine months ended September 30, 2007. Upon closing of the acquisition in July 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133. The Partnership designated these instruments as cash flow hedges and will evaluate these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

Ineffective hedge gains or losses are recorded within other income (loss) in the Partnership’s consolidated statements of operations while the hedge contracts are open and may increase or decrease until settlement of the contract. The following table summarizes the Partnership’s derivative activity for the periods indicated (amounts in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(12,850	)	$	(4,896	)	$	(23,548	)	$	(10,518	)
Gain/(loss) from change in market value of non- qualifying derivatives⁽²⁾		(15,595	)		3,166			(35,731	)		3,166
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		7,164			508			(3,526	)		1,445
Loss from cash settlement of non-qualifying derivatives⁽²⁾		(3,037	)		—			(3,037	)		—

(1)	Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

(2)	Included within other income (loss) on the Partnership’s consolidated statements of operations.

A portion of the Partnership’s future natural gas, NGL and condensate sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to natural gas and liquids revenue within the Partnership’s consolidated statements of operations.

As of September 30, 2007, the Partnership had the following NGLs, natural gas, and crude oil volumes hedged, including derivatives that do not qualify for hedge accounting:

Natural Gas Liquids Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽¹⁾
	(gallons)	(per gallon)		(in thousands)
2007	42,651,000	$	0.893	$	(10,739	)
2008	61,362,000		0.706		(13,556	)
2009	8,568,000		0.746		(1,752	)

				$	(26,047	)

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽²⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2007	390,000	25,789,680	$	60.00	$	58		Puts purchased
2007	390,000	25,789,680		75.15		(2,513	)	Calls sold
2008	3,744,600	249,257,484		60.00		5,119		Puts purchased
2008	3,744,600	249,257,484		79.38		(15,961	)	Calls sold
2009	4,752,000	324,233,280		60.00		13,292		Puts purchased
2009	4,752,000	324,233,280		78.68		(22,694	)	Calls sold
2010	2,413,500	169,282,890		60.00		8,064		Puts purchased
2010	2,413,500	169,282,890		77.28		(12,643	)	Calls sold

					$	(27,278	)

Natural Gas Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾		(in thousands)
2007	1,449,000	$	8.197	$	1,736
2008	5,484,000		8.795		4,608
2009	5,724,000		8.611		1,958
2010	2,820,000		8.635		1,132

				$	9,434

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	1,449,000	$	(0.729	)	$	135
2008	5,484,000		(0.727	)		388
2009	5,724,000		(0.513	)		550
2010	2,820,000		(0.572	)		435

					$	1,508

Natural Gas Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	3,909,000	$	8.633	⁽⁴⁾	$	(6,819	)
2008	16,260,000		8.923	⁽⁵⁾		(16,293	)
2009	15,564,000		8.680			(6,402	)
2010	7,200,000		8.635			(2,891	)

					$	(32,405	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	3,909,000	$	(1.048	)	$	161
2008	15,276,000		(1.186	)		(1,820	)
2009	14,820,000		(0.686	)		(5,485	)
2010	7,200,000		(0.560	)		(2,930	)

					$	(10,074	)


Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽²⁾
	(barrels)	(per barrel)			(in thousands)
2007	17,600	$	56.477		$	(427	)
2008	65,400		59.424			(1,133	)
2009	33,000		62.700			(362	)

					$	(1,922	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	Average Strike Price	Fair Value Asset/(Liability)⁽²⁾			Option Type
	(barrels)	(per barrel)	(in thousands)
2007	189,300	60.000		(39	)	Puts purchased
2007	189,300	75.363		(998	)	Calls sold
2008	691,800	60.000		675		Puts purchased
2008	691,800	78.004		(3,266	)	Calls sold
2009	738,000	60.000		2,060		Puts purchased
2009	738,000	80.622		(3,038	)	Calls sold
2010	402,000	60.000		1,308		Puts purchased
2010	402,000	79.341		(1,804	)	Calls sold
2011	30,000	60.000		124		Puts purchased
2011	30,000	74.500		(193	)	Calls sold
2012	30,000	60.000		138		Puts purchased
2012	30,000	73.900		(211	)	Calls sold

			$	(5,244	)

		Total net liability	$	(92,028	)

⁽¹⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

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

⁽³⁾	Mmbtu represents million British Thermal Units.

⁽⁴⁾	Includes the Partnership’s premium received from its sale of an option for it to sell 1,200,000 mmbtu of natural gas at an average price of $17.00 per mmbtu for the year ended December 31, 2007.

⁽⁵⁾	Includes the Partnership’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

NOTE 10– DEBT

Total debt consists of the following (in thousands):


	September 30, 2007			December 31, 2006
Revolving credit facility	$	33,500		$	38,000
Term loan		830,000			—
Senior notes		294,419			285,977
Other debt		44			106

		1,157,963			324,083
Less current maturities		(35	)		(71	)

	$	1,157,928		$	324,012

Term Loan and Credit Facility

In connection with the Partnership’s July 27, 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum Systems (see Note 8), the Partnership entered into a new credit facility, comprised of an $830.0 senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. The Partnership borrowed $830.0 million under the term loan and $15.0 million under the revolving credit facility to finance a portion of the acquisition purchase price and to repay indebtedness under its prior revolving credit facility. Borrowings under the credit facility bear interest, at the Partnership’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). The weighted average interest rate on the outstanding revolving credit facility borrowings at September 30, 2007 was 8.5%, and the weighted average interest rate on the outstanding term loan borrowings at September 30, 2007 was 8.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.1 million was outstanding at September 30, 2007. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnership’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of its consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on the Partnership’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. The Partnership is in compliance with these covenants as of September 30, 2007. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt or equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days.

The events which constitute an event of default for the Partnership’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against the Partnership in excess of a specified amount, and a change of control of the Partnership’s General Partner. The credit facility requires the Partnership to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. The first measurement period of these covenants is December 31, 2007.

The Partnership is 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.

Senior Notes

At September 30, 2007, the Partnership has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, prior to December 15, 2008, the Partnership may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Partnership 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 the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under its Credit Facility. On April 18, 2007, the Partnership issued Sunlight Capital $8.5 million of its Senior Notes in consideration of its consent to the amendment of the Partnership’s preferred units agreement (see Note 4).

The indenture governing the Senior Notes contains covenants, including limitations of the Partnership’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. The Partnership is in compliance with these covenants as of September 30, 2007.

NOTE 11 – COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings arising out of 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.

As of September 30, 2007, the Partnership is committed to expend approximately $91.3 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 12 – STOCK COMPENSATION

Long-Term Incentive Plan

The Partnership has a Long-Term Incentive Plan (“LTIP”), 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 Plan is administered by a committee (the “Committee”) appointed by General Partner’s managing board. The Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the LTIP through September 30, 2007.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the Committee, cash equivalent to the fair market value of a common unit. In addition, the Committee may grant a participant 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. A unit option entitles the grantee to purchase the Partnership’s common limited partner units at an exercise price determined by the Committee at its discretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of the General Partner, the Committee will determine the vesting period for phantom units and the exercise period for options. Through September 30, 2007, phantom units granted under the LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Committee, although no awards currently outstanding contain any such provision. 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 LTIP. Of the units outstanding under the LTIP at September 30, 2007, 57,231 units will vest within the following twelve months. All units outstanding under the LTIP at September 30 2007 include DERs granted to the participants by the Committee. The amounts paid with respect to DERs were $0.2 million and $0.1 million during the three months ended September 30, 2007 and 2006, respectively, and $0.5 million and $0.3 million during the nine months ended September 30, 2007 and 2006, respectively. These amounts were recorded as reductions of Partners’ Capital on the Partnership’s consolidated balance sheet.

The Partnership follows the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”). Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Outstanding, beginning of period		184,162			111,219			159,067			110,128
Granted⁽¹⁾		—			33,000			25,095			34,091
Matured		(38,401	)		(31,152	)		(38,401	)		(31,152	)
Forfeited		(1,000	)		—			(1,000	)		—

Outstanding, end of period		144,761			113,067			144,761			113,067

Non-cash compensation expense recognized (in thousands)	$	592		$	450		$	2,466		$	1,294

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $43.05 for awards granted for the three months ended September 30, 2006. There were no awards granted for the three months ended September 30, 2007. The weighted average price was $50.09 and $42.99 for awards granted for the nine months ended September 30, 2007 and 2006, respectively.

At September 30, 2007, the Partnership had approximately $3.2 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIP based upon the fair value of the awards.

Incentive Compensation Agreements

The Partnership has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals are entitled to receive common units of the Partnership upon the vesting of the awards, which is dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units to be issued under the incentive compensation agreements, 58,824 will be issued prior to December 31, 2007. The remaining common units to be issued under the incentive compensation agreements will be determined based upon the financial performance of certain Partnership assets for the year ended December 31, 2008.

The Partnership recognized compensation expense of $31.2 million and $1.2 million for the three months ended September 30, 2007 and 2006, respectively, and $33.6 million and $2.8 million for the nine months ended September 30, 2007 and 2006, respectively, related to the vesting of awards under these incentive compensation agreements. The increase in non-cash compensation expense was due to an increase in common unit awards estimated by management to be issued under incentive compensation agreements to certain key employees as a result of the acquisition of the Chaney Dell and Midkiff/Benedum systems. The ultimate

number of common units estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain Partnership assets for the year ended December 31, 2008. The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. Management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance. Based upon management’s estimate of the probable outcome of the performance targets at September 30, 2007, 877,543 common unit awards are ultimately expected to be issued under these agreements, which represents the amount of common units expected to be issued under the incentive compensation agreements. The Partnership follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

NOTE 13 – RELATED PARTY TRANSACTIONS

The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by the General Partner and employees of Atlas America. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses the General Partner and its affiliates for compensation and benefits related to their employees who perform services for the Partnership based upon an estimate of the time spent by such persons on activities for the Partnership. Other indirect costs, such as rent for offices, are allocated to the Partnership by Atlas America based on the number of its employees who devote their time to activities on the Partnership’s behalf.

The partnership agreement provides that the General Partner will determine the costs and expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. The Partnership reimbursed the General Partner and its affiliates $1.4 million and $0.4 million for the three months ended September 30, 2007 and 2006, respectively, and $2.8 million and $2.0 million for nine months ended September 30, 2007 and 2006, respectively, for compensation and benefits related to their executive officers. For the three months ended September 30, 2007 and 2006, direct reimbursements were $6.2 million and $8.0 million, respectively, and $18.5 million and $21.2 million for the nine months ended September 30, 2007 and 2006, respectively, including certain costs that have been capitalized by the Partnership. The General Partner believes that the method utilized in allocating costs to the Partnership is reasonable.

Under an agreement between the Partnership and Atlas Energy, Atlas Energy must construct up to 2,500 feet of sales lines from its existing wells in the Appalachian region to a point of connection to the Partnership’s gathering systems. The Partnership must, at its own cost, extend its system to connect to any such lines within 1,000 feet of its gathering systems. With respect to wells to be drilled by Atlas Energy that will be more than 3,500 feet from the Partnership’s gathering systems, the Partnership has various options to connect those wells to its gathering systems at its own cost.

NOTE 14 – OPERATING SEGMENT INFORMATION

The Partnership has two business segments: natural gas transmission, gathering and processing located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, western New York and western Pennsylvania, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of primarily southern Oklahoma, northern Texas, Arkansas and southeastern Missouri. Appalachia revenues are principally based on contractual arrangements with Atlas and its affiliates. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and transport of natural gas. These operating segments reflect the way the Partnership manages its operations.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Mid-Continent
Revenue:
Natural gas and liquids	$	229,511		$	99,997		$	436,479		$	296,083
Transportation, compression and other fees		12,793			6,707			33,183			20,817
Other income (loss)		(9,133	)		6,754			(39,918	)		7,709

Total revenue and other income (loss)		233,171			113,458			429,744			324,609

Costs and expenses:
Natural gas and liquids		174,471			89,679			349,383			252,577
Plant operating		9,108			3,853			18,153			11,006
Transportation and compression		1,943			1,389			5,443			4,029
General and administrative		34,806			3,590			43,506			9,753
Depreciation and amortization		14,992			5,200			26,007			14,034
Minority interest		1,376			—			1,376			118

Total costs and expenses		236,696			103,711			443,868			291,517

Segment profit (loss)	$	(3,525	)	$	9,747		$	(14,124	)	$	33,092

Appalachia
Revenue:
Natural gas and liquids	$	380		$	—		$	380		$	—
Transportation, compression and other fees – affiliates		8,494			6,951			24,673			22,659
Transportation, compression and other fees – third parties		156			19			191			65
Other income		99			118			264			524

Total revenue and other income		9,129			7,088			25,508			23,248

Costs and expenses:
Natural gas and liquids		256			—			256			—
Transportation and compression		1,612			1,325			4,434			3,610
General and administrative		1,505			929			4,025			2,848
Depreciation and amortization		1,184			952			3,374			2,651

Total costs and expenses		4,557			3,206			12,089			9,109

Segment profit	$	4,572		$	3,882		$	13,419		$	14,139

Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent	$	(3,525	)	$	9,747		$	(14,124	)	$	33,092
Appalachia		4,572			3,882			13,419			14,139

Total segment profit (loss)		1,047			13,629			(705	)		47,231
Corporate general and administrative expenses		(1,505	)		(928	)		(4,024	)		(2,847	)
Interest expense		(24,040	)		(5,700	)		(38,126	)		(18,191	)

Net income (loss)	$	(24,498	)	$	7,001		$	(42,855	)	$	26,193

Capital Expenditures:
Mid-Continent	$	41,074		$	20,706		$	78,680		$	47,903
Appalachia		9,191			5,225			14,980			13,840

	$	50,265		$	25,931		$	93,660		$	61,743


	September 30, 2007		December 31, 2006
Balance sheet
Total assets:
Mid-Continent	$	2,741,521	$	730,791
Appalachia		45,212		42,448
Corporate other		21,138		13,645

	$	2,807,871	$	786,884

Goodwill:
Mid-Continent	$	61,136	$	61,136
Appalachia		2,305		2,305

	$	63,441	$	63,441

The following tables summarize the Partnership’s total revenues by product or service for the periods indicated (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Natural gas and liquids:
Natural gas	$	76,895	$	52,359	$	161,004	$	151,195
NGLs		133,425		42,882		240,253		125,891
Condensate		10,208		1,510		14,941		4,767
Other ⁽¹⁾		9,363		3,246		20,661		14,230

Total	$	229,891	$	99,997	$	436,859	$	296,083

Transportation, compression and other fees:
Affiliates	$	8,494	$	6,951	$	24,673	$	22,659
Third Parties		12,949		6,726		33,374		20,882

Total	$	21,443	$	13,677	$	58,047	$	43,541

(1)	Includes treatment, processing, and other revenue associated with the products noted.

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 2006. 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.

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 appearing elsewhere in this report.

General

We are a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL”. Our principal business objective is to generate cash for distribution to our unitholders. We are a leading provider of natural gas gathering services in the Anadarko, Arkoma, Golden Trend and Permian Basins in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, we are a leading provider of natural gas processing and treatment services in Oklahoma and Texas. We also provide interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. Our business is conducted in the midstream segment of the natural gas industry through two operating segments: our Mid-Continent operations and our Appalachian operations.

Through our Mid-Continent operations, we own and operate:

•

a FERC-regulated, 565-mile interstate pipeline system that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 400 MMcfd;

•

seven natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

•

7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing plants or transmission lines.

Through our Appalachian operations, we own and operate 1,600 miles of natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us and Atlas America, Inc., (“Atlas America” – NASDAQ: ATLS) and its affiliates, including Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin and a publicly-traded company (NYSE: ATN), we gather substantially all of the natural gas for our Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to our gathering systems wells it operates that are located within 2,500 feet of our gathering systems. We are also party to natural gas gathering agreements with Atlas America and Atlas Energy under which we receive gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas we transport.

Significant Acquisitions

From the date of our initial public offering in January 2000 through September 2007, we have completed seven acquisitions at an aggregate cost of approximately $2.4 billion, including, most recently:

•

On July 27, 2007, we acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Assets”). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which we contributed $1.9 billion and Anadarko contributed the Assets. In connection with this acquisition, we reached an agreement with Pioneer Natural Resources Company, which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.5% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest

in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. We will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. We funded the purchase price from our private placement of $1.125 billion of our common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by Atlas Pipeline Holdings, the parent of our general partner. Our general partner, which holds all of our incentive distribution rights, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to us through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (see “—Partnership Distributions”). We funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see “—Term Loan and Credit Facility”).

•

In May 2006, we acquired the remaining 25% ownership interest in NOARK from Southwestern Energy Company (“Southwestern”) for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, we acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

Contractual Revenue Arrangements

Our principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect our revenue are:

•

the volumes of natural gas we gather, transport and process which, in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

•

the transportation and processing fees we receive which, in turn, depend upon the price of the natural gas and NGLs we transport and process, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

In our Appalachian region, substantially all of the natural gas we transport is for Atlas Energy under percentage-of-proceeds (“POP”) contracts, as described below, in which we earn a fee equal to a percentage, generally 16%, of the selling price of the natural gas subject, in most cases, to a minimum of $0.35 or $0.40 per thousand cubic feet, or mcf, depending upon the ownership of the well. Since our inception in January 2000, our Appalachian system transportation fee has always exceeded this minimum in general. The balance of the Appalachian system natural gas we transport is for third-party operators generally under fixed-fee contracts.

Our revenue in the Mid-Continent region is determined primarily by the fees earned from our transmission, gathering and processing operations. We either purchase natural gas from producers and move it into receipt points on our pipeline systems, and then sell the natural gas, or produced NGLs, if any, off of delivery points on our systems, or we transport natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with our FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation services are provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with our gathering and processing operations, we enter into the following types of contractual relationships with our producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. Our revenue is a function of the volume of natural gas that we gather and process and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for us to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs we gather and process, with the remainder being remitted to the producer. In this situation, we and the producer are directly dependent on the volume of the commodity and its value; we own a percentage of that commodity and are directly subject to its market value.

Keep-Whole Contracts. These contracts require us, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, we bear the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that we paid for the unprocessed natural gas. However, because the natural gas received by the Elk City/Sweetwater system, which has keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the natural gas can be bypassed around the Elk City and Sweetwater processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

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.

We face competition for natural gas transportation and in obtaining natural gas supplies for our 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, flexibility, and maintenance of high-quality customer relationships. Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and keep-whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas and NGLs. We believe 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, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe 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. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. A 10% change in the average price of NGLs, natural gas and condensate we process and sell would result in a change to our consolidated income (loss) for the twelve-month period ending September 30, 2008 of approximately $7.9 million.

Results of Operations

The following table illustrates selected volumetric information related to our operating segments for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Operating data⁽¹⁾:
Appalachia:
Average throughput volumes – mcfd		71,876		63,909		66,888		61,473
Average transportation rate per mcf	$	1.32	$	1.19	$	1.36	$	1.35
Mid-Continent:
Velma system:
Gathered gas volume – mcfd		63,757		62,113		62,531		61,641
Processed gas volume – mcfd		61,968		58,296		60,555		58,881
Residue gas volume – mcfd		49,502		45,724		47,487		46,042
NGL volume – bpd		6,215		6,598		6,386		6,536
Condensate volume – bpd		254		205		222		209
Elk City/Sweetwater system:
Gathered gas volume – mcfd		299,450		284,461		298,724		270,957
Processed gas volume – mcfd		231,152		136,101		224,521		134,169
Residue gas volume – mcfd		211,368		123,275		206,011		121,661
NGL volume – bpd		9,782		6,049		9,351		6,016
Condensate volume – bpd		143		59		228		125
Chaney Dell system⁽²⁾:
Gathered gas volume – mcfd		255,649		—		255,649		—
Processed gas volume – mcfd		249,982		—		249,982		—
Residue gas volume – mcfd		222,508		—		222,508		—
NGL volume – bpd		12,678		—		12,678		—
Condensate volume – bpd		564		—		564		—
Midkiff/Benedum system⁽²⁾:
Gathered gas volume – mcfd		150,061		—		150,061		—
Processed gas volume – mcfd		106,601		—		106,601		—
Residue gas volume – mcfd		93,859		—		93,859		—
NGL volume – bpd		20,702		—		20,702		—
Condensate volume – bpd		1,754		—		1,754		—
NOARK system:
Average Ozark Gas Transmission throughput volume – mcfd		325,652		226,962		311,562		236,331

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

(2)	Volumetric data for the Chaney Dell system and Midkiff/Benedum system for the three and nine months ended September 30, 2007 represents volumes recorded for the 66-day period from July 27, 2007, the date of acquisition, through September 30, 2007.

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

Revenue. Natural gas and liquids revenue was $229.9 million for the three months ended September 30, 2007, an increase of $129.9 million from $100.0 million for the three months ended September 30, 2006. The increase was primarily attributable to revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, of $131.3 million. Processed natural gas volume on the Chaney Dell system was 250.0 MMcfd for the period from July 27, 2007, the date of acquisition, to September 30, 2007, while the Midkiff/Benedum system had processed natural gas volume of 106.6 MMcfd for the same period. Processed natural gas volume on the Elk City/Sweetwater system averaged 231.2 MMcfd for the three months ended September 30, 2007, an increase of 69.8% from the comparable prior year period. Processed natural gas volume averaged 62.0 MMcfd on the Velma system for the three months ended September 30, 2007, an increase of 6.3% from the comparable prior year period.

Transportation, compression and other fee revenue increased to $21.4 million for the three months ended September 30, 2007 compared with $13.7 million for the prior year period. This $7.7 million increase was primarily due to an increase of $3.6 million from the transportation revenues associated with the NOARK system, a $1.7 million increase from the Appalachia system and $1.5 million of contributions from the Chaney Dell and Midkiff/Benedum systems. For the NOARK system, average Ozark Gas Transmission volume was 325.7 MMcfd for the three months ended September 30, 2007, an increase of 43.5% from the prior year comparable period. The Appalachia system’s average throughput volume was 71.9 MMcfd for the three months ended September 30, 2007 as compared with 63.9 MMcfd for the three months ended September 30, 2006, an increase of 8.0 MMcfd or 12.5%. The Appalachia system’s average transportation rate was $1.32 per Mcf for the three months ended September 30, 2007 compared with $1.19 per Mcf for the prior year period, an increase of $0.13 per Mcf, as a result of higher realized natural gas prices. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system and the acquisition of a natural gas processing plant in August 2007, which has a capacity of 10.0 MMcfd and was acquired for $6.1 million.

Other income (loss), including the impact of non-cash gains and losses recognized on derivatives, was a loss of $9.0 million for the three months ended September 30, 2007, a decrease of $15.9 million from the prior year comparable period. This decrease was due primarily to a $15.1 million unfavorable movement in derivative gains and losses compared with the prior year as a result of commodity price movements and their unfavorable impact on derivative contracts we have for future periods. We enter into derivative instruments solely to hedge our 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”. The unfavorable movement in other income (loss) between the three months ended September 30, 2007 and 2006 was also due principally to the absence in the current quarter of a $2.7 million gain recognized during the three months ended September 30, 2006 resulting from the sale of certain gathering pipelines within the Velma system for cash proceeds of $7.5 million.

Costs and Expenses. Natural gas and liquids cost of goods sold of $174.7 million and plant operating expenses of $9.1 million for the three months ended September 30, 2007 represented increases of $85.0 million and $5.2 million, respectively, from the comparable prior year amounts due primarily to contribution from the Chaney Dell and Midkiff/Benedum acquisitions. Transportation and compression expenses increased $0.9 million to $3.6 million for the three months ended September 30, 2007 due to higher NOARK and Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections.

General and administrative expenses, including amounts reimbursed to affiliates, increased $32.4 million to $37.8 million for the three months ended September 30, 2007 compared with $5.4 million for the prior year comparable period. This increase was mainly due to a $30.2 million increase in non-cash compensation expense related to vesting of phantom and common unit awards and higher costs associated with

managing our business, including management time related to acquisition and capital raising opportunities. The increase in non-cash compensation expense was due to an increase in common unit awards estimated by management to be issued under incentive compensation agreements to certain key employees as a result of the acquisition of the Chaney Dell and Midkiff/Benedum systems. The ultimate number of common units estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain Partnership assets for the year ended December 31, 2008. The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. Management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance.

Depreciation and amortization increased to $16.2 million for the three months ended September 30, 2007 compared with $6.2 million for the three months ended September 30, 2006 due primarily to the depreciation associated with our Chaney Dell and Midkiff/Benedum acquired assets and our expansion capital expenditures incurred between the periods, including the Sweetwater processing facility.

Interest expense increased to $24.0 million for the three months ended September 30, 2007 as compared with $5.7 million for the comparable prior year period. This $18.3 million increase was primarily due to interest associated with the $830.0 million term loan issued in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems and a $5.1 million increase in the amortization of deferred finance costs principally due to $5.0 million of accelerated amortization associated with the replacement of our previous credit facility with a new credit facility in July 2007 (see “—Term Loan and Credit Facility”).

Minority interest expense of $1.4 million for the three months ended September 30, 2007 represents Anadarko’s 5% ownership interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems.

During June 2006, we identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during the third and fourth quarters of 2005 and first quarter of 2006, we recorded an adjustment of $1.2 million during the second quarter of 2006 to increase natural gas and liquids cost of goods sold. If the $1.2 million adjustment had been recorded when the inaccuracies arose, reported net income would have been reduced by approximately 2.7%, 8.3% and 1.4% for the third quarter of 2005, fourth quarter of 2005, and first quarter of 2006, respectively. Our management believes that the impact of these adjustments is immaterial to our current and prior financial statements.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Revenue. Natural gas and liquids revenue was $436.9 million for the nine months ended September 30, 2007, an increase of $140.8 million from $296.1 million for the nine months ended September 30, 2006. The increase was primarily attributable to revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, of $131.3 million and an increase of $27.6 million from the Elk City/Sweetwater system due primarily to an increase in volumes, which includes processing volumes from the newly constructed Sweetwater gas plant. This increase was partially offset by a decrease of $20.8 million from the NOARK system due primarily to lower natural gas sales volumes on its gathering systems. Processed natural gas volume on the Chaney Dell system was 250.0 MMcfd for the period from July 27, 2007, the date of acquisition, to September 30, 2007, while the Midkiff/Benedum system had processed natural gas volume of 106.6 MMcfd for the same period. Processed natural gas volume on the Elk City/Sweetwater system averaged 224.5 MMcfd for the nine months ended September 30, 2007, an increase of 67.3% from the comparable prior year period. Processed natural gas volume averaged 60.6 MMcfd on the Velma system for the nine months ended September 30, 2007, an increase of 2.8% from the comparable prior year period.

Transportation, compression and other fee revenue increased to $58.0 million for the nine months ended September 30, 2007 compared with $43.5 million for the prior year period. This $14.5 million increase was

primarily due to an increase of $8.6 million from the transportation revenues associated with the NOARK system, an increase of $2.3 million associated with the Elk City/Sweetwater system, a $2.2 million increase from the Appalachia system and $1.5 million of contributions from the Chaney Dell and Midkiff/Benedum systems. For the NOARK system, average Ozark Gas Transmission volume was 311.6 MMcfd for the nine months ended September 30, 2007, an increase of 31.8% from the prior year comparable period. The Appalachia system’s average throughput volume was 66.9 MMcfd for the nine months ended September 30, 2007 as compared with 61.5 MMcfd for the nine months ended September 30, 2006, an increase of 5.4 MMcfd or 8.8%. The Appalachia system’s average transportation rate was $1.36 per Mcf for the nine months ended September 30, 2007 compared with $1.35 per Mcf for the prior year period, an increase of $0.01 per Mcf. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system.

Other income (loss), including the impact of non-cash gains and losses recognized on derivatives, was a loss of $39.7 million for the nine months ended September 30, 2007, a decrease of $47.9 million from the prior year comparable period. This decrease was due primarily to a $46.9 million unfavorable movement in derivative gains and losses compared with the prior year as a result of commodity price movements and their unfavorable impact on derivative contracts we have for future periods and the impact of derivative contracts entered into during June 2007 to hedge the projected production volume of the Chaney Dell and Midkiff/Benedum systems. The production volume of these systems, which we did not acquire until after we entered into the derivative contracts, was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, we recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in our consolidated statements of operations. Upon closing of the acquisition in July 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133. We designated these instruments as cash flow hedges and we will evaluate these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. We recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the nine months ended September 30, 2007. We enter into derivative instruments solely to hedge our 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. Natural gas and liquids cost of goods sold of $349.6 million and plant operating expenses of $18.2 million for the nine months ended September 30, 2007 represented increases of $97.1 million and $7.1 million, respectively, from the comparable prior year amounts due primarily to contribution from the Chaney Dell and Midkiff/Benedum acquisitions and an increase in gathered and processed natural gas volumes on the Elk City/Sweetwater system, which includes contributions from the Sweetwater processing facility, partially offset by a decrease in NOARK gathering system natural gas purchases. Transportation and compression expenses increased $2.3 million to $9.9 million for the nine months ended September 30, 2007 due to higher NOARK and Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections.

General and administrative expenses, including amounts reimbursed to affiliates, increased $36.2 million to $51.6 million for the nine months ended September 30, 2007 compared with $15.4 million for the prior year comparable period. This increase was mainly due to a $32.0 million increase in non-cash compensation expense related to vesting of phantom and common unit awards previously mentioned and higher costs associated with managing our business, including management time related to acquisition and capital raising opportunities.

Depreciation and amortization increased to $29.4 million for the nine months ended September 30, 2007 compared with $16.7 million for the nine months ended September 30, 2006 due primarily to the depreciation associated with our Chaney Dell and Midkiff/Benedum acquired assets and our expansion capital expenditures incurred between the periods, including the Sweetwater processing facility.

Interest expense increased to $38.1 million for the nine months ended September 30, 2007 as compared with $18.2 million for the comparable prior year period. This $19.9 million increase was primarily due to interest associated with the $830.0 million term loan issued in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems and a $5.1 million increase in the amortization of deferred finance costs principally due to $5.0 million of accelerated amortization associated with the replacement of our previous credit facility with a new credit facility in July 2007 (see “—Term Loan and Credit Facility”).

Minority interest expense of $1.4 million for the nine months ended September 30, 2007 represents Anadarko’s 5% ownership interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. Minority interest expense of $0.1 million for the nine months ended September 30, 2006 represents Southwestern’s 25% ownership interest in the net income of NOARK through May 2, 2006, the date which we acquired this remaining ownership interest.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to our common unitholders and general partner. In general, we expect to fund:

•

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

•

expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings; and

•

debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units.

At September 30, 2007, we had $33.5 million outstanding under our new $300.0 senior secured credit facility and $7.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $259.4 million of remaining committed capacity under the new credit facility, subject to covenant limitations (see “—Term Loan and Credit Facility”). In addition to the availability under the credit facility, we have a universal shelf registration statement on file with the Securities and Exchange Commission, which allows us to issue equity or debt securities (see “—Shelf Registration Statement”), of which $352.1 million remains available at September 30, 2007. At September 30, 2007, we had a working capital deficit of $19.2 million compared with $1.2 million working capital surplus at December 31, 2006. This decrease was primarily due to an increase in the current portion of our net hedge liability between periods, which is the result of changes in commodity prices after we entered into the hedges. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, unitholder distributions, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cashflow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings and the issuance of additional limited partner units.

Cash Flows – Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Net cash provided by operating activities of $86.9 million for the nine months ended September 30, 2007 represented an increase of $47.0 million from $39.9 million for the comparable prior year period. The

increase was derived principally from a $41.4 million favorable movement in derivative non-cash gains and losses, a $32.0 million increase in non-cash compensation expense, a $16.0 million increase in minority interest, a $12.7 million increase in depreciation and amortization, a $6.4 million increase in cash flow from working capital changes and a $5.0 million increase in amortization of deferred finance costs. These amounts were partially offset by a decrease in net income of $69.0 million. The movement in derivative non-cash gains and losses resulted from commodity price movements and their unfavorable impact on derivative contracts we have for future periods and the impact of derivative contracts entered into during June 2007 to hedge the projected production volume of the Chaney Dell and Midkiff/Benedum systems. The increase in non-cash compensation expense was due to an increase in common unit awards estimated by management to be issued under incentive compensation agreements to certain key employees as a result of the acquisition of the Chaney Dell and Midkiff/Benedum systems. The increase in minority interest and depreciation and amortization resulted from our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007.

Net cash used in investing activities was $1,967.9 million for the nine months ended September 30, 2007, an increase of $1,883.8 million from $84.1 million for the comparable prior year period. This increase was principally due to the $1,873.7 million of net cash paid for acquisition for the nine months ended September 30, 2007 compared with the $30.0 million for the prior year comparable period. Net cash paid for acquisition for the nine months ended September 30, 2007 represents the net amount paid for our acquisition of the Chaney Dell and Midkiff/Benedum systems, while the net cash paid for the prior year comparable period represents the amount paid for our acquisition of the remaining 25% ownership interest in the NOARK system. Also affecting the change in net cash used in investing activities was a $31.9 million increase in capital expenditures and a $7.6 million decrease in cash proceeds received from the sale of assets. The decrease in cash proceeds received from the sale of assets resulted from the sale of certain gathering pipelines within the Velma system during the nine months ended September 30, 2006. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities was $1,904.0 million for the nine months ended September 30, 2007, an increase of $1,886.1 million from $17.9 million of net cash provided by financing activities for the comparable prior year period. This increase was principally due to a $1,095.6 million increase in net proceeds from the issuance of our common units, a $789.5 million increase in net proceeds from the issuance of long-term debt, a $39.0 million favorable impact regarding repayments of long-term debt, and a $21.9 million increase in capital contributions. These amounts were partially offset by a $39.9 million decrease in net proceeds from the issuance of our cumulative convertible preferred units, an $8.5 million increase in preferred unit distributions paid, and an $8.5 million net increase in borrowings under our revolving credit facility. The increase in net proceeds from the issuance of our common units, net proceeds from the issuance of our long-term debt, and capital contributions resulted from transactions undertaken during July 2007 to finance our acquisition of the Chaney Dell and Midkiff/Benedum systems.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our 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 our existing operations.

The following table summarizes 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,
	2007		2006		2007		2006
Maintenance capital expenditures	$	2,328	$	843	$	3,800	$	2,921
Expansion capital expenditures		47,937		25,088		89,860		58,822

Total	$	50,265	$	25,931	$	93,660	$	61,743

Expansion capital expenditures increased to $47.9 million and $89.9 million for the three and nine months ended September 30, 2007, respectively, due principally to expansions of the Appalachia, Velma and Elk City/Sweetwater gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in our service areas. Maintenance capital expenditures for the three and nine months ended September 30, 2007 increased to $2.3 million and $3.8 million, respectively, compared with the prior year comparable period due to fluctuations in the timing of scheduled maintenance activity. As of September 30, 2007, we are committed to expend approximately $91.3 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Partnership Distributions

Our partnership agreement requires that we distribute 100% of available cash to our common unitholders and our general partner within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

Our general partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds 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 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.

Available cash is initially distributed 98% to our common limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, our general partner, holder of all of our incentive distribution rights, has agreed to allocate up to $5.0 million of incentive distribution rights per quarter back to us through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. The general partner’s incentive distributions declared for the three and nine months ended September 30, 2007, after the allocation of $4.9 million of its incentive distribution rights to us for the third quarter 2007 distribution, were $3.7 million and $11.6 million, respectively.

Common Equity Offerings

In July 2007, we sold 25.6 million common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25.6 million common units sold, 3.8 million were purchased by AHD for $168.8 million. We also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in us.

We utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see “—Significant Acquisitions”).

The common units we sold in the July 2007 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulates that we will (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. If we do not meet the aforementioned deadline for the common units to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.25% of the gross proceeds from the private placement, or approximately $2.8 million, for the first 30-day period after March 2, 2008, increasing by an additional 0.25% per 30-day period thereafter, up to a maximum of 1.0% of the gross proceeds of the private placement per 30-day period. On October 10, 2007, we filed a registration statement with the Securities and Exchange Commission for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously.

In May 2006, we sold 500,000 common units to Wachovia Securities, which then offered the common units to public investors. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. We utilized the net proceeds from the sale to partially repay borrowings under our credit facility made in connection with our acquisition of the remaining 25% ownership interest in NOARK.

Shelf Registration Statement

We have an effective shelf registration statement with the Securities and Exchange Commission that permits us to periodically issue equity and debt securities for a total value of up to $500 million. As of September 30, 2007, $352.1 million remains available for issuance under the shelf registration statement. However, the amount, type and timing of any offerings will depend upon, among other things, our funding requirements, prevailing market conditions, and compliance with our credit facility covenants.

Private Placement of Convertible Preferred Units

On March 13, 2006, we entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. We also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to our right under the agreement to require Sunlight Capital to purchase such additional units. The preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date our common units. On April 18, 2007, we and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of the preferred units were amended to entitle them to receive dividends of 6.5% per annum commencing on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for common unit distributions after March 13, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of our common units as of the date of the notice of conversion. We may elect to pay cash rather than issue common units in satisfaction of a conversion request. We have the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.82. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, we issued $8.5 million of 8.125% senior unsecured notes due 2015 (the “Notes”) to Sunlight Capital. We recorded the Notes as long-term debt and a preferred unit dividend within partners’ capital. We have also reduced net income attributable to common limited partners and the general partner by $3.8 million of the $8.5 million preferred unit dividend, which is the portion deemed to be attributable to the concessions of the common limited partners and the general partner to the preferred unitholder, on our consolidated statements of operations.

The net proceeds from the initial issuance of the preferred units were used to fund a portion of our capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system. The proceeds from the issuance of the additional 10,000 preferred units were used to reduce indebtedness under our credit facility incurred in connection with the acquisition of the remaining 25% ownership interest in NOARK.

Term Loan and Credit Facility

We have a credit facility comprised of an $830.0 million senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. Borrowings under the credit facility bear interest, at our 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). The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2007 was 8.5%, and the weighted average interest rate on the outstanding term loan borrowings at September 30, 2007 was 8.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.1 million was outstanding at September 30, 2007. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of our property and that of our subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of our consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are in compliance with these covenants as of September 30, 2007. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt or equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days.

The events which constitute an event of default for our credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against us in excess of a specified amount, and a change of control of our General Partner. The credit facility requires us to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. The first measurement period of these covenants is December 31, 2007.

Senior Notes

At September 30, 2007, we have $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, prior to December 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us 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 we do not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under our credit facility. On April 18, 2007, we issued Sunlight Capital $8.5 million of our Senior Notes in consideration of its consent to the amendment of our preferred units agreement.

The indenture governing the Senior Notes contains covenants, including limitations of our 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. We are in compliance with these covenants as of September 30, 2007.

NOARK Notes

On May 2, 2006, we acquired the remaining 25% equity ownership interest in NOARK from Southwestern. Prior to this acquisition, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $39.0 million in principal amount outstanding of 7.15% notes due in 2018, which was presented as debt on our consolidated balance sheet, to be allocated severally 100% to Southwestern. In connection with the acquisition of the 25% equity ownership interest in NOARK, Southwestern acquired NOARK Pipeline Finance, L.L.C. and agreed to retain the obligation for the outstanding NOARK notes, with the result that neither we nor NOARK have any further liability with respect to such notes.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make 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 revenues and expenses during the reporting period. Although we believe our estimates are reasonable, actual results could differ from those estimates. 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, 2006, and there have been no material changes to these policies through September 30, 2007.

New Accounting Standards

In September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings, as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2007. We have previously followed the requirements of EITF No. 03-6 in calculating our net earnings per limited partner unit and will apply the requirements of EITF No. 07-4 as it pertains to MLPs upon its adoption during the quarter ended March 31, 2008.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. SFAS No. 159 offers various options in electing to apply its provisions, and at this time we have not made any decisions with regards to its application to our financial position or results of operations. We are currently evaluating whether SFAS No. 159 will have an impact on our financial position and results of operations.

In December 2006, the FASB issued FASB Staff Position EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“EITF 00-19-2”). EITF 00-19-2 provides guidance related to the accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”). EITF 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. We adopted EITF 00-19-2 on January 1, 2007. We reviewed the penalty terms in the registration rights agreement related to its private placement entered into on July 27, 2007 (see “—Common Equity Offerings”), pursuant to the guidance in the EITF, and determined that the probability of payment is remote under SFAS No. 5 based upon our status of current related filings. As a result, the application of EITF 00-19-2 did not have an effect on our financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. This statement does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating whether SFAS No. 157 will have an impact on our financial position and results of operations.

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. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and 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 market risk sensitive instruments were entered into for purposes other than trading.

General

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

We 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 manage these risks through regular operating and financing activities and periodical use of derivative financial 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, 2007. Only the potential impact of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At September 30, 2007, we had a $300.0 million senior secured revolving credit facility ($33.5 million outstanding) to fund the expansion of our existing gathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. We also had an $830.0 million senior secured term loan outstanding at September 30, 2007, of which the net proceeds were utilized to partially finance our acquisition of control of the Chaney Dell and Midkiff/Benedum systems. The weighted average interest rate for the revolving credit facility borrowings was 8.5% at September 30, 2007, and the weighted average interest rate for the term loan borrowings was 8.0% at September 30, 2007. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our interest expense by $8.6 million.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on our current portfolio of natural gas supply contracts, we have long condensate, NGL, and natural gas positions. A 10% change in the average price of NGLs, natural gas and condensate we process and sell would result in a change to our consolidated income (loss) for the twelve-month period ending September 30, 2008 of approximately $7.9 million.

We enter into financial swap and option instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying commodity, we will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which we determine through utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations.

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassify them to natural gas and liquids revenue within our consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within other income (loss) in our consolidated statements of operations as they occur. At September 30, 2007 and December 31, 2006, we reflected net derivative liabilities on our consolidated balance sheets of $92.0 million and $20.1 million, respectively. Of the $54.7 million of net loss in accumulated other comprehensive loss within partners’ capital on our consolidated balance sheet at September 30, 2007, if the fair values of the instruments remain at current market values, we will reclassify $35.1 million of losses to natural gas and liquids revenue in our consolidated statements of operations over the next twelve month period as these contracts expire, and $19.6 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes.

On June 3, 2007, we signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see “—Significant Acquisitions”). In connection with agreements entered into with respect to our new credit facility, term loan and private placement of common units, we agreed as a condition precedent to closing that we would hedge 80% of our projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, we entered into derivative instruments to hedge 80% of the projected production of the Assets to be acquired as required under the financing agreements. The production volume of the Assets was not considered to be “probable forecasted

production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the Assets had not yet been completed. Accordingly, we recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in our consolidated statements of operations. We recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the nine months ended September 30, 2007. Upon closing of the acquisition in July 2007, the production volume of the Assets was considered “probable forecasted production” under SFAS No. 133. We designated these instruments as cash flow hedges and we will evaluate these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

Ineffective hedge gains or losses are recorded within other income (loss) in our consolidated statements of operations while the hedge contracts are open and may increase or decrease until settlement of the contract. The following table summarizes our derivative activity for the periods indicated:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(12,850	)	$	(4,896	)	$	(23,548	)	$	(10,518	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		(15,595	)		3,166			(35,731	)		3,166
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		7,164			508			(3,526	)		1,445
Loss from cash settlement of non-qualifying derivatives⁽²⁾		(3,037	)		—			(3,037	)		—

(1)	Included within natural gas and liquids revenue on our consolidated statements of operations.

(2)	Included within other income (loss) on our consolidated statements of operations.

A portion of our future natural gas, NGL and condensate sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to natural gas and liquids revenue within our consolidated statements of operations.

As of September 30, 2007, we had the following NGLs, natural gas, and crude oil volumes hedged, including derivatives that do not qualify for hedge accounting:

Natural Gas Liquids Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽¹⁾
	(gallons)	(per gallon)		(in thousands)
2007	42,651,000	$	0.893	$	(10,739	)
2008	61,362,000		0.706		(13,556	)
2009	8,568,000		0.746		(1,752	)

				$	(26,047	)

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽²⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2007	390,000	25,789,680	$	60.00	$	58		Puts purchased
2007	390,000	25,789,680		75.15		(2,513	)	Calls sold
2008	3,744,600	249,257,484		60.00		5,119		Puts purchased
2008	3,744,600	249,257,484		79.38		(15,961	)	Calls sold
2009	4,752,000	324,233,280		60.00		13,292		Puts purchased
2009	4,752,000	324,233,280		78.68		(22,694	)	Calls sold
2010	2,413,500	169,282,890		60.00		8,064		Puts purchased
2010	2,413,500	169,282,890		77.28		(12,643	)	Calls sold

					$	(27,278	)

Natural Gas Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾		(in thousands)
2007	1,449,000	$	8.197	$	1,736
2008	5,484,000		8.795		4,608
2009	5,724,000		8.611		1,958
2010	2,820,000		8.635		1,132

				$	9,434

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	1,449,000	$	(0.729	)	$	135
2008	5,484,000		(0.727	)		388
2009	5,724,000		(0.513	)		550
2010	2,820,000		(0.572	)		435

					$	1,508

Natural Gas Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	3,909,000	$	8.633	⁽⁴⁾	$	(6,819	)
2008	16,260,000		8.923	⁽⁵⁾		(16,293	)
2009	15,564,000		8.680			(6,402	)
2010	7,200,000		8.635			(2,891	)

					$	(32,405	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽²⁾
	(mmbtu)⁽³⁾	(per mmbtu)⁽³⁾			(in thousands)
2007	3,909,000	$	(1.048	)	$	161
2008	15,276,000		(1.186	)		(1,820	)
2009	14,820,000		(0.686	)		(5,485	)
2010	7,200,000		(0.560	)		(2,930	)

					$	(10,074	)

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽²⁾
	(barrels)	(per barrel)		(in thousands)
2007	17,600	$	56.477	$	(427	)
2008	65,400		59.424		(1,133	)
2009	33,000		62.700		(362	)

				$	(1,922	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	Average Strike Price	Fair Value Asset/(Liability)⁽²⁾			Option Type
	(barrels)	(per barrel)	(in thousands)
2007	189,300	60.000		(39	)	Puts purchased
2007	189,300	75.363		(998	)	Calls sold
2008	691,800	60.000		675		Puts purchased
2008	691,800	78.004		(3,266	)	Calls sold
2009	738,000	60.000		2,060		Puts purchased
2009	738,000	80.622		(3,038	)	Calls sold
2010	402,000	60.000		1,308		Puts purchased
2010	402,000	79.341		(1,804	)	Calls sold
2011	30,000	60.000		124		Puts purchased
2011	30,000	74.500		(193	)	Calls sold
2012	30,000	60.000		138		Puts purchased
2012	30,000	73.900		(211	)	Calls sold

			$	(5,244	)

	Total net liability		$	(92,028	)

⁽¹⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

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

⁽³⁾	Mmbtu represents million British Thermal Units.

⁽⁴⁾	Includes our premium received from our sale of an option for us to sell 1,200,000 mmbtu of natural gas at an average price of $17.00 per mmbtu for the year ended December 31, 2007.

⁽⁵⁾	Includes our premium received from our sale of an option for us to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

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 our 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 our disclosure controls and procedures are effective at the reasonable assurance level.

As of December 31, 2006, management concluded that our internal control over financial reporting was ineffective, based on our evaluation under the COSO framework, because it identified a material weakness with regard to our accounting for certain derivative instruments in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Specifically, we entered into a significant number of option instruments (a combination of puts purchased and calls sold that are commonly known as “costless collars”) in September 2006 to hedge our exposure to movements in commodity prices that were not appropriately valued within our consolidated financial statements under the provisions of SFAS No. 133. While the costless collars were valued appropriately with regard to their intrinsic value, we did not record a fair value for the time-value component of the derivative instruments. All of our other derivative instruments that were in effect during 2006 had been appropriately recorded within our consolidated financial statements as of December 31, 2006. This material weakness resulted in the amendment of our Form 10-Q as of September 30, 2006.

Subsequent to our discovery of the material weakness discussed above, in early 2007 we took steps to remediate the material weakness, including reviewing the accounting requirements necessary for compliance with SFAS No. 133 and establishing additional review procedures of accounting for derivative transactions by senior personnel within our organization. We believe these actions have strengthened our internal control over financial reporting and address the material weakness identified.

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 6.

EXHIBITS


Exhibit No.		Description
2.1		Amendment to Master Formation Agreement effective as of June 1, 2007 between the Partnership and Western Gas Resources, Inc.⁽¹⁾

2.2		Amendment to Master Formation Agreement effective as of June 1, 2007 among Western Gas Resources, Inc., Western Gas Resources—Westana, Inc. and Atlas Pipeline Partners, L.P.⁽¹⁾

3.1(a)		Second Amended and Restated Agreement of Limited Partnership⁽²⁾

3.1(b)		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership⁽³⁾

3.1(c)		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership⁽¹⁾


3.2		Certificate of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁴⁾

3.3		Amended and Restated Certificate of Designation of 6.5% Cumulative Convertible Preferred Units⁽⁵⁾

10.1		Operating Agreement of Atlas Pipeline Mid-Continent WestTex, LLC dated July 27, 2007⁽¹⁾

10.2		Operating Agreement of Atlas Pipeline Mid-Continent WestOk, LLC dated July 27, 2007⁽¹⁾

10.3		Registration Rights Agreement dated July 27, 2007 by and among the Partnership and the purchasers named therein⁽¹⁾

10.4		Revolving Credit and Term Loan Agreement dated July 27, 2007⁽¹⁾

10.5		Purchase Option Agreement between Atlas Pipeline Mid-Continent WestTex, LLC and Pioneer Natural Resources USA, Inc. dated July 27, 2007⁽¹⁾

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

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

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

32.1		Section 1350 Certification

32.2		Section 1350 Certification

⁽¹⁾	Previously filed as an exhibit to the Partnership’s current report on Form 8-K, filed on July 30, 2007 and incorporated herein by reference.

⁽²⁾	Previously filed as an exhibit to the Partnership’s registration statement on Form S-3, Registration No. 333-113523 and incorporated herein by reference.

⁽³⁾	Previously filed as an exhibit to the Partnership’s quarterly report on Form 10-Q for the quarter ended June 30, 2007.

⁽⁴⁾	Previously filed as an exhibit to the Partnership’s registration statement on Form S-1, Registration No. 333-85193 and incorporated herein by reference.

⁽⁵⁾	Previously filed as an exhibit to the Partnership’s current report on Form 8-K, filed on April 19, 2007 and incorporated herein by reference.

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 PARTNERS, L.P.

	By:	Atlas Pipeline Partners GP, LLC, its General Partner

Date: November 8, 2007	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman of the Managing Board of the General Partner Chief Executive Officer of the General Partner

Date: November 8, 2007	By:	/s/ MICHAEL L. STAINES
		Michael L. Staines
		President, Chief Operating Officer and Managing Board Member of the General Partner

Date: November 8, 2007	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer of the General Partner

Date: November 8, 2007	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer of the General Partner