Edgar Filing: ATLAS PIPELINE PARTNERS LP

Atlas Pipeline Partners, L.P.

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, 2008

¨	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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in rule 12b-2 of the Exchange Act.


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

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

The number of common units of the registrant outstanding on November 3, 2008 was 45,942,808.

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, 2008 and December 31, 2007 (Unaudited)	3

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (Unaudited)	4

	Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2008 (Unaudited)	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (Unaudited)	6

	Notes to Consolidated Financial Statements (Unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	56

PART II. OTHER INFORMATION

Item 1A.	Risk Factors	57

Item 6.	Exhibits	58

SIGNATURES		59

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	September 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	43,813		$	11,980
Accounts receivable – affiliates		—			3,334
Accounts receivable		131,793			147,360
Prepaid expenses and other		17,778			14,749

Total current assets		193,384			177,423
Property, plant and equipment, net		1,956,243			1,748,661
Intangible assets, net		200,036			219,203
Goodwill		676,860			709,283
Minority interest		2,275			2,163
Other assets, net		27,964			20,881

	$	3,056,762		$	2,877,614

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	8		$	34
Accounts payable - affiliates		6,087			—
Accounts payable		69,504			20,530
Accrued liabilities		49,518			43,487
Current portion of derivative liability		90,585			110,867
Accrued producer liabilities		75,941			80,698

Total current liabilities		291,643			255,616
Long-term derivative liability		133,102			118,646
Long-term debt, less current portion		1,426,490			1,229,392
Other long-term liability		616			—
Commitments and contingencies
Partners’ capital:
Preferred limited partner’s interests		38,231			37,076
Common limited partners’ interests		1,246,909			1,269,521
General partner’s interest		33,004			29,413
Accumulated other comprehensive loss		(113,233	)		(62,050	)

Total partners’ capital		1,204,911			1,273,960

	$	3,056,762		$	2,877,614

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,
	2008			2007			2008			2007
Revenue:
Natural gas and liquids	$	404,182		$	229,891		$	1,209,587		$	436,859
Transportation, compression and other fees – affiliates		11,916			8,495			32,496			24,673
Transportation, compression and other fees – third parties		12,153			12,948			39,724			33,374
Other income (loss), net		153,875			(9,034	)		(247,140	)		(39,654	)

Total revenue and other income (loss), net		582,126			242,300			1,034,667			455,252

Costs and expenses:
Natural gas and liquids		316,917			174,727			943,561			349,639
Plant operating		16,652			9,108			46,418			18,153
Transportation and compression		4,768			3,555			12,881			9,877
General and administrative		(2,946	)		36,424			10,055			48,735
Compensation reimbursement – affiliates		1,175			1,392			3,694			2,820
Depreciation and amortization		22,550			16,176			74,571			29,381
Interest		21,846			24,040			61,612			38,126
Minority interest		2,591			1,376			7,793			1,376

Total costs and expenses		383,553			266,798			1,160,585			498,107

Net income (loss)		198,573			(24,498	)		(125,918	)		(42,855	)
Preferred unit dividend effect		—			—			—			(3,756	)
Preferred unit dividends		(650	)		—			(1,437	)		—
Preferred unit imputed dividend cost		—			(624	)		(505	)		(1,858	)

Net income (loss) attributable to common limited partners and the general partner	$	197,923		$	(25,122	)	$	(127,860	)	$	(48,469	)

Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	$	117,203		$	(28,242	)	$	(216,960	)	$	(58,854	)
General partner’s interest		80,720			3,120			89,100			10,385

Net income (loss) attributable to common limited partners and the general partner	$	197,923		$	(25,122	)	$	(127,860	)	$	(48,469	)

Net income (loss) attributable to common limited partners per unit:
Basic	$	2.55		$	(0.90	)	$	(5.25	)	$	(3.05	)

Diluted	$	2.43		$	(0.90	)	$	(5.25	)	$	(3.05	)

Weighted average common limited partner units outstanding:
Basic		45,937			31,449			41,360			19,270

Diluted		48,187			31,449			41,360			19,270

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, 2008

(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, 2008	40,000	38,758,581	$	37,076		$	1,269,521		$	29,413		$	(62,050	)	$	1,273,960
Issuance of common units	—	7,140,000		—			256,961			—			—			256,961
Preferred unit dividends	—	—		(787	)		—			—			—			(787	)
Capital contribution	—	—		—			—			5,452			—			5,452
Unissued common units under incentive plans	—	—		—			(14,274	)		—			—			(14,274	)
Issuance of units under incentive plans	—	44,227		—			—			—			—			—
Distributions paid to common limited partners and the general partner	—	—		—			(116,596	)		(22,291	)		—			(138,887	)
Distribution equivalent rights paid on unissued units under incentive plans	—	—		—			(413	)		—			—			(413	)
Other comprehensive loss	—	—		—			—			—			(51,183	)		(51,183	)
Net income (loss)	—	—		1,942			(148,290	)		20,430			—			(125,918	)

Balance at September 30, 2008	40,000	45,942,808	$	38,231		$	1,246,909		$	33,004		$	(113,233	)	$	1,204,911

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,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(125,918	)	$	(42,855	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		74,571			29,381
Non-cash loss (gain) on derivative value, net		(57,009	)		39,256
Non-cash compensation expense (income)		(14,274	)		36,096
Amortization of deferred finance costs		3,650			6,690
Minority interest		7,793			16,143
Net distributions paid to minority interest holders		(7,905	)		—
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		9,302			(62,980	)
Accounts payable and accounts liabilities		37,289			44,223
Accounts payable and accounts receivable – affiliates		9,421			3,747

Net cash provided by (used in) operating activities		(63,080	)		69,701

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		31,429			(1,873,703	)
Capital expenditures		(246,394	)		(76,428	)
Other		1,095			(561	)

Net cash used in investing activities		(213,870	)		(1,950,692	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of debt		244,854			817,549
Repayment of debt		(122,847	)		—
Borrowings under credit facility		576,000			197,500
Repayments under credit facility		(506,000	)		(202,000	)
Net proceeds from issuance of common limited partner units		256,961			1,115,275
General partner capital contributions		5,452			23,076
Distributions paid to common limited partners and the general partner		(139,674	)		(46,590	)
Other		(5,963	)		(806	)

Net cash provided by financing activities		308,783			1,904,004

Net change in cash and cash equivalents		31,833			23,013
Cash and cash equivalents, beginning of period		11,980			1,795

Cash and cash equivalents, end of period	$	43,813		$	24,808

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(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 5,754,253 limited partner units in the Partnership. At September 30, 2008, the Partnership had 45,942,808 common limited partnership units, including the 5,754,253 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) which owns a 64.4% ownership interest in AHD at September 30, 2008, also owns 1,112,000 common limited partnership units, representing a 2.3% ownership interest in the Partnership, and a 48.3% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN). 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, 2007, 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, 2007. The results of operations for the three and nine month periods ended September 30, 2008 may not necessarily be indicative of the results of operations for the full year ending December 31, 2008. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2007.

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.

The consolidated financial statements also include the operations of Chaney Dell natural gas gathering system and processing plants located in Oklahoma (“Chaney Dell system”) and the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (“Midkiff/Benedum system”). In July 2007, the Partnership acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell system and its 72.8% undivided joint venture interest in the Midkiff/Benedum system (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% interest and Anadarko has a 5% interest in each. The Partnership consolidates 100% of these joint ventures. The Partnership reflects Anadarko’s 5% 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.

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 expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including the fair value of derivative instruments, the probability of forecasted transactions and stock compensation, all of which could affect the reported amounts of certain assets and liabilities. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2008 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 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 (loss) 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 13).

In March 2004, the Financial Accounting Standards Board (“FASB”) ratified the Emerging Issue Task Force (“EITF”) consensus on EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF No. 03-6”), which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitles the holder of those securities to participate in dividends and earnings of the entity when, and if, the entity declares dividends on its common stock. In quarterly accounting periods where net income does not exceed the Partnership’s aggregate cash distributions to its partners, EITF No. 03-6 does not have any impact on the Partnership’s net income per common limited partner unit calculation as net income (loss) is allocated to its partners with a priority allocation to actual incentive distributions paid to the general partner for the quarterly period, with the remaining net income (loss) allocated with respect to relative ownership interests. However, EITF No. 03-6 provides that if the Partnership has net income which exceeds the aggregate cash distributions to its partners during a quarterly period, it is required to present net income per common unit as if all of the earnings for the quarterly period were distributed in a manner consistent with the partnership agreement, regardless of whether those earnings would actually be distributed during a quarterly period from an economic probability standpoint. The allocation of net income for net income per common limited partner unit purposes under EITF No. 3-06 will result in an increased allocation of net income to the general partner’s incentive distributions and a reduction of net income allocated to common limited partners. The following is a reconciliation of net income (loss) allocated to the general partner and common limited partners for purposes of calculating net income (loss) per common limited partner unit (in thousands, except per unit data):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income (loss)	$	198,573		$	(24,498	)	$	(125,918	)	$	(42,855	)
Preferred unit dividend effect		—			—			—			(3,756	)
Preferred unit dividends		(650	)		—			(1,437	)		—
Preferred unit imputed dividend cost		—			(624	)		(505	)		(1,858	)

Net income (loss) attributable to common limited partners and the general partner		197,923			(25,122	)		(127,860	)		(48,469	)

Less:
General partner’s actual cash incentive distributions declared		8,238			3,700			23,472			11,592
Additional net income attributable to the general partner’s incentive distributions under EITF 03-6		70,078			—			70,078			—
General partner’s 2% ownership interest		2,404			(580	)		(4,450	)		(1,207	)

Net income (loss) attributable to the general partner’s ownership interests		80,720			3,120			89,100			10,385

Net income (loss) attributable to the common limited partners	$	117,203		$	(28,242	)	$	(216,960	)	$	(58,854	)

While the Partnership’s net income (loss) is allocated to the general partner and common limited partners in accordance with the provisions of EITF 03-6, the Partnership’s net income (loss) for partners’ capital purposes is allocated to the general partner and the common limited partners in accordance with their respective ownership interests after giving effect to any special income allocations, including actual incentive distributions declared to the general partner for the respective quarter. On January 1, 2009, the Partnership will adopt EITF No. 07-4, “Application of the Two-Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships.” The Partnership expects the adoption of EITF No. 07-4 will impact its presentation of earnings per unit (see Note 2, “Recently Issued Accounting Standards”).

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2008	2007	2008	2007
Weighted average number of common limited partner units – basic	45,937	31,449	41,360	19,270
Add: effect of dilutive unit incentive awards⁽¹⁾	984	—	—	—
Add: effect of dilutive convertible preferred limited partner units⁽¹⁾	1,266	—	—	6

Weighted average number of common limited partner units – diluted	48,187	31,449	41,360	19,270

⁽¹⁾

For the three months ended September 30, 2007, approximately 619,000 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 nine months ended September 30, 2008 and 2007, approximately 984,000 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 three months ended September 30, 2007 and the nine months ended September 30, 2008 and 2007, potential common limited partner units issuable upon conversion of the Partnership’s 40,000, $1,000 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, which are accounted for as cash flow hedges. 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,
	2008			2007			2008			2007
Net income (loss)	$	198,573		$	(24,498	)	$	(125,918	)	$	(42,855	)
Preferred unit dividend effect		—			—			—			(3,756	)
Preferred unit dividends		(650	)		—			(1,437	)		—
Preferred unit imputed dividend cost		—			(624	)		(505	)		(1,858	)

Net income (loss) attributable to common limited partners and the general partner		197,923			(25,122	)		(127,860	)		(48,469	)

Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as hedges		11,894			(38,072	)		(97,515	)		(56,193	)
Add: adjustment for realized losses reclassified to net income (loss)		10,026			12,850			46,332			23,548

Total other comprehensive income (loss)		21,920			(25,222	)		(51,183	)		(32,645	)

Comprehensive income (loss)	$	219,843		$	(50,344	)	$	(179,043	)	$	(81,114	)

Revenue Recognition

Revenue in the Partnership’s Appalachia segment is principally 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 natural gas produced from the wells, or $0.35 to $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 natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, 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 FERC-regulated transmission pipeline is recognized at the time 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 purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of the Partnership’s keep-whole contracts is minimized.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from 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, 2008 and December 31, 2007 of $85.5 million and $86.8 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 6.3% and 8.1% for the three months ended September 30, 2008 and 2007, respectively, and 6.4% and 8.0% for the nine months ended September 30, 2008 and 2007, respectively. The amount of interest capitalized was $2.0 million and $0.8 million for the three months ended September 30, 2008 and 2007, respectively, and $6.3 million and $1.8 million for the nine months ended September 30, 2008 and 2007, respectively.

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, 2008 and December 31, 2007 (in thousands):


	September 30, 2008			December 31, 2007			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts	$	12,810		$	12,810		8
Customer relationships		222,572			222,572		7-20

	$	235,382		$	235,382

Accumulated Amortization:
Customer contracts	$	(5,409	)	$	(4,215	)
Customer relationships		(29,937	)		(11,964	)

	$	(35,346	)	$	(16,179	)

Net Carrying Amount:
Customer contracts	$	7,401		$	8,595
Customer relationships		192,635			210,608

	$	200,036		$	219,203

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 $6.4 million and $0.6 million for the three months ended September 30, 2008 and 2007, respectively, and $19.2 million and $1.8 million for the nine months ended September 30, 2008 and 2007, respectively. Amortization expense related to intangible assets is estimated to be $25.6 million for each of the next five calendar years commencing in 2009.

Goodwill

At September 30, 2008 and December 31, 2007, the Partnership had $676.9 million and $709.3 million, respectively, 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, 2008 and 2007 were as follows (in thousands):


	Nine Months Ended September 30,
	2008			2007
Balance, beginning of period	$	709,283		$	63,441
Post-closing purchase price adjustment with seller and purchase price allocation adjustment –Chaney Dell and Midkiff/Benedum systems acquisition		(2,217	)		—
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		(30,206	)		—

Balance, end of period	$	676,860		$	63,441

The Partnership has adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by adjusting the estimated amounts allocated to goodwill, intangible assets and property, plant and equipment. Also, in April 2008, the Partnership received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition (see Note 8).

The Partnership tests its goodwill for impairment at each year end by comparing reporting unit 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, 2007 resulted in no impairment and no impairment indicators have been noted as of September 30, 2008. The Partnership will continue to evaluate its goodwill at least annually and if impairment indicators arise, will reflect the impairment of goodwill, if any, within the consolidated statement of operations for the period in which the impairment is indicated.

Recently Adopted Accounting Standards

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment to FASB Statement No. 115” (“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 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. The Partnership adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments.

non-financial assets, non-financial liabilities or any non-recurring fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Partnership adopted SFAS No. 157 at January 1, 2008 with respect to its derivative instruments, which are measured at fair value within its financial statements. The provisions of SFAS No. 157 have not been applied to its non-financial assets and non-financial liabilities. See Note 10 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Partnership’s financial instruments.

Recently Issued Accounting Standards

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Partnership will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles. SFAS No. 162 is effective beginning November 15, 2008. The Partnership currently does not expect the adoption of SFAS No. 162 to have an impact on its financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Partnership will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP FAS 142-3 to have a material impact on its financial position and results of operations.

In March 2008, the FASB ratified the EITF 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, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF 07-4 also considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive

distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Partnership expects the adoption of EITF No. 07-4 will impact its presentation of net income (loss) per common limited partner unit as the Partnership currently presents net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see Note 2, “Net Income (Loss) Per Common Unit”). Under the guidance of EITF 07-4, management of the Partnership believes that the partnership agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings will no longer be allocated to the incentive distribution rights upon adoption of EITF No. 07-4 effective January 1, 2009.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Partnership is currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding its derivative instruments.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Partnership will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 160 will have a material impact on its financial position and results of operations.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141(R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Partnership will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 141(R) will have a material impact on its financial position and results of operations.

NOTE 3 – COMMON UNIT EQUITY OFFERINGS

In June 2008, the Partnership sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Partnership sold 1,112,000 common units to Atlas America and 278,000 common units to AHD in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. The Partnership also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in the Partnership. The Partnership utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see Note 9).

In July 2007, the Partnership sold 25,568,175 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 25,568,175 common units sold by the Partnership, 3,835,227 common units were purchased by AHD for $168.8 million. The Partnership also received a capital contribution from AHD of $23.1 million 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% ownership interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 8).

NOTE 4 – PREFERRED UNIT EQUITY OFFERING

In March 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 in May 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 in March 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. In April 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 in March 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing May 8, 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’s preferred limited partner units were convertible into approximately 930,233 common limited partner units, subject to limitations within the agreement between the parties, as of September 30, 2008, with an estimated fair value of approximately $23.7 million based upon the market value of the Partnership’s common units as of that date.

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 $53.22. If not converted into common units or redeemed prior to May 2010, the preferred units will automatically be converted into Partnership common units in accordance with the agreement. 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 (see Note 11) to Sunlight Capital. The Partnership recorded the senior unsecured notes as long-term debt and a preferred unit dividend within partners’ capital on the Partnership’s consolidated balance sheet and, during the nine months ended September 30, 2007, reduced net income attributable to common limited partners and the general partner by $3.8 million of this amount, which was 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 in March 2006 and was amortized in full as of March 2007. As a result of the amended agreement, the Partnership recognized an imputed dividend cost of $2.5 million that was amortized during the year commencing March 2007 and was based upon the present value of the net proceeds received using the 6.5% stated yield. During the nine months ending September 30, 2008, the Partnership amortized the remaining $0.5 million of this imputed dividend cost, which is presented as an additional adjustment of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations. Amortization of the imputed dividend cost was $0.6 million and $1.9 million for the three and nine months ended September 30, 2007, respectively, based on the $2.5 million imputed cost during the year commencing March 2007.

Sunlight Capital was entitled to receive the dividends on the preferred units pro rata from the March 2008 commencement date. The Partnership recognized $0.7 million and $1.4 million of preferred dividend cost for the three and nine months ended September 30, 2008, respectively, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations. The preferred dividend cost recognized by the Partnership for the respective periods is associated with the preferred dividends earned during those periods and paid on the scheduled date of the Partnership’s quarterly cash distribution for the respective period (see Note 5). The $0.7 million of preferred unit dividend cost recognized for the three months ended September 30, 2008 is based upon the preferred unit dividend to be paid on November 14, 2008.

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 to its common unitholders and the General Partner. If common unit 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. Common unit and General Partner distributions declared by the Partnership for the period from January 1, 2007 through September 30, 2008 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, 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
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498
February 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092
May 15, 2008	March 31, 2008	$	0.94	$	36,450	$	7,891
August 14, 2008	June 30, 2008	$	0.96	$	44,096	$	9,308

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. AHD also agreed that the resulting allocation of incentive distribution rights back to the Partnership would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

On October 27, 2008, the Partnership declared a cash distribution of $0.96 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2008. The $53.4 million distribution, including $9.3 million to the General Partner after the allocation of $5.0 million of its incentive distribution rights back to the Partnership, will be paid on November 14, 2008 to unitholders of record at the close of business on November 10, 2008.

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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


	September 30, 2008			December 31, 2007			Estimated Useful Lives In Years
Pipelines, processing and compression facilities	$	1,880,146		$	1,633,454		15 – 40
Rights of way		172,016			168,359		20 – 40
Buildings		8,968			8,919		40
Furniture and equipment		8,654			7,235		3 – 7
Other		16,222			13,307		3 – 10

		2,086,006			1,831,274
Less – accumulated depreciation		(129,763	)		(82,613	)

	$	1,956,243		$	1,748,661

In July 2007, the Partnership acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 8). During the fourth quarter of 2007 and first quarter of 2008, the Partnership adjusted its preliminary purchase price allocation by adjusting the estimated amounts allocated to goodwill and property, plant, and equipment.

During the nine months ended September 30, 2008, the Partnership recognized charges totaling $8.0 million within depreciation and amortization expense with respect to a write-off of costs related to a pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with a contractual arrangement.

NOTE 7 – OTHER ASSETS

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


	September 30, 2008		December 31, 2007
Deferred finance costs, net of accumulated amortization of $15,002 and $11,352 at September 30, 2008 and December 31, 2007, respectively	$	25,921	$	18,227
Security deposits		1,841		2,498
Other		202		156

	$	27,964	$	20,881

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 11). In June 2008, the Partnership recorded $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of senior notes (see Note 11). In July 2007, the Partnership recorded $5.0 million of accelerated amortization of deferred financing costs associated with the replacement of its previous credit facility with a new facility (see Note 11).

NOTE 8 – ACQUISITIONS

Chaney Dell and Midkiff/Benedum

In July 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 “Anadarko 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 Anadarko Assets.

In connection with this acquisition, the Partnership reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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. 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. AHD also agreed that the resulting allocation of incentive distribution rights back to the Partnership would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see Note 5). The Partnership funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings from its senior secured revolving credit facility that matures in July 2013 (see Note 11).

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 the acquisition, based on their fair values at the date of the acquisition (in thousands):


Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets – customer relationships		205,312
Goodwill		613,420

Total assets acquired		1,854,528
Accounts payable and accrued liabilities		(1,499	)

Net cash paid for acquisition	$	1,853,029

The Partnership recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. In April 2008, the Partnership received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition. 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.

The following data presents pro forma revenue and net income (loss) for the Partnership for the three and nine months ended September 30, 2008 and 2007 as if the acquisition discussed above, the equity offering in July 2007 (see Note 3), proceeds of $830.0 million from a senior unsecured term loan (see Note 11), borrowings under its senior secured revolving credit facility (see Note 11), and the April 2007 issuances of senior notes (see Notes 4 and 11) had occurred on January 1, 2007. 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 this acquisition and these 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,
	2008		2007			2008			2007
Total revenue and other income (loss), net	$	582,186	$	242,300		$	1,034,667		$	776,484
Net income (loss)	$	198,573	$	(19,417	)	$	(125,918	)	$	(33,066	)
Net income (loss) attributable to common limited partners and the general partner	$	197,923	$	(20,051	)	$	(127,860	)	$	(38,675	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	2.55	$	(0.60	)	$	(5.25	)	$	(1.27	)

Diluted	$	2.43	$	(0.60	)	$	(5.25	)	$	(1.27	)

NOTE 9 – DERIVATIVE INSTRUMENTS

The Partnership uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. 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. It also enters into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold or interest payments on the underlying debt instrument is due. Under 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. Commodity-based 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.

The Partnership applies the provisions of SFAS No. 133 to its derivative instruments. 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 derivative contracts to the forecasted transactions. Under SFAS No. 133, the Partnership can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership 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 within other income (loss) in its consolidated statements of operations. For derivatives previously qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassified the

portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within its consolidated statements of operations as the underlying transactions were 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.

On July 1, 2008, the Partnership elected to discontinue hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss) in its consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions effect earnings.

During June and July 2008, the Partnership made net payments of $264.0 million related to the early termination of crude oil derivative contracts that were entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. These derivative contracts were put into place simultaneously with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and nine months ended September 30, 2008, the Partnership recognized the following derivative activity related to the termination of these derivative instruments (amounts in thousands):


	Early Termination of Derivative Contracts
	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Net cash derivative expense included within other income (loss), net on the Partnership’s consolidated statements of operations	$	(70,258	)	$	—	$	(186,068	)	$	—
Net cash derivative expense included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations		(1,258	)		—		(1,573	)		—
Net non-cash derivative income (expense) included within other income (loss), net on the Partnership’s consolidated statements of operations		6,488			—		(39,857	)		—
Net non-cash derivative expense included within natural gas and liquids on the Partnership’s consolidated statements of operations		(19,514	)		—		(19,514	)		—

In addition, $63.3 million will be reclassified from accumulated other comprehensive loss within partner’s capital on the Partnership’s consolidated balance sheet and recognized as non-cash derivative expenses during the period beginning on October 1, 2008 and ending on December 31, 2009, the remaining period for which the derivatives were originally scheduled to be settled, as a result of the early termination of certain derivatives that were classified as cash flow hedges in accordance with SFAS No. 133 at the date of termination.

At September 30, 2008, the Partnership had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million, which were designated as cash flow hedges. Under the terms of these agreements, the Partnership will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 11), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of the Partnership’s floating rate debt under the term loan and revolving credit facility to fixed-rate debt. The interest rate swap agreements are effective as of September 30, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At September 30, 2008 and December 31, 2007, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $223.7 million and $229.5 million, respectively. Of the $113.2 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at September 30, 2008, if the fair values of the instruments remain at current market values, the Partnership will reclassify $57.5 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $58.1 million of losses to natural gas and liquids revenue and $0.6 million of gains to interest expense. Aggregate losses of $55.7 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of $56.0 million of losses to natural gas and liquids revenue and $0.3 million of gains to interest expense. 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 Anadarko Assets to be acquired as required under the financing agreements. The production volume of the Anadarko 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 Anadarko 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 year ended December 31, 2007. Upon closing of the acquisition in July 2007, the production volume of the Anadarko Assets acquired was considered “probable forecasted production” under SFAS No. 133. The Partnership designated many of these instruments as cash flow hedges and evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

The following table summarizes the Partnership’s cumulative derivative activity for the periods indicated (amounts in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(27,419	)	$	(12,850	)	$	(78,214	)	$	(23,548	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		(190,013	)		(15,595	)		17,919			(35,731	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		(44,997	)		7,164			(41,271	)		(3,526	)
Loss from cash settlement of non-qualifying derivatives⁽²⁾		(84,207	)		(3,037	)		(280,696	)		(3,037	)
Loss from cash settlement of interest rate derivatives⁽³⁾		(673	)		—			(867	)		—

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

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

⁽³⁾	Included within interest expense on the Partnership’s consolidated statements of operations.

As of September 30, 2008, the Partnership had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Asset/(Liability)⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2008	$	413
				2009		238
				2010		65

					$	716

April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2008	$	365
				2009		(339	)
				2010		197

					$	223

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2008	7,434,000	$	0.697	$	(3,642	)
2009	8,568,000	$	0.746		(3,607	)

				$	(7,249	)

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)⁽³⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2008	536,400	29,972,124	$	70.16	$	110		Puts purchased
2008	126,000	11,219,040	$	127.55		(3,531	)	Puts sold⁽⁴⁾
2008	126,000	11,219,040	$	140.00		65		Calls purchased⁽⁴⁾
2008	473,400	25,764,984	$	80.13		(10,104	)	Calls sold
2009	1,584,000	85,038,534	$	80.00		2,372		Puts purchased
2009	304,200	27,085,968	$	126.05		(9,082	)	Puts sold⁽⁴⁾
2009	304,200	27,085,968	$	143.00		1,026		Calls purchased⁽⁴⁾
2009	2,121,600	114,072,336	$	81.01		(51,161	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(90,981	)	Calls sold
2010	714,000	45,415,440	$	120.00		8,966		Calls purchased⁽⁴⁾
2011	606,000	32,578,560	$	95.56		(13,597	)	Calls sold
2011	252,000	13,547,520	$	120.00		3,462		Calls purchased⁽⁴⁾
2012	450,000	24,192,000	$	97.10		(9,981	)	Calls sold
2012	180,000	9,676,800	$	120.00		2,629		Calls purchased⁽⁴⁾

					$	(169,807	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾		(in thousands)
2008	1,371,000	$	8.823	$	1,722
2009	5,724,000	$	8.611		2,667
2010	4,560,000	$	8.526		(269	)
2011	2,160,000	$	8.270		(583	)
2012	1,560,000	$	8.250		(251	)

				$	3,286

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	1,371,000	$	(0.744	)	$	2,042
2009	5,724,000	$	(0.558	)		1,599
2010	4,560,000	$	(0.622	)		732
2011	2,160,000	$	(0.664	)		217
2012	1,560,000	$	(0.601	)		97

					$	4,687

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	4,065,000	$	8.274	⁽⁶⁾	$	(5,622	)
2009	15,564,000	$	8.680			(8,329	)
2010	8,940,000	$	8.580			196
2011	2,160,000	$	8.270			583
2012	1,560,000	$	8.250			251

					$	(12,921	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	4,065,000	$	(1.114	)	$	(6,761	)
2009	15,564,000	$	(0.654	)		(5,362	)
2010	8,940,000	$	(0.600	)		(2,118	)
2011	2,160,000	$	(0.700	)		(50	)
2012	1,560,000	$	(0.610	)		(49	)

					$	(14,340	)

Ethane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)		Option Type
2008	7,560,000	$	0.7885	$	399	Puts purchased
2009	16,254,000	$	0.6928		196	Puts purchased

				$	595

Propane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)		Option Type
2008	8,946,000	$	1.4752	$	174	Puts purchased
2009	23,310,000	$	1.3935		368	Puts purchased

				$	542

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2008	14,100	$	60.569	$	(563	)
2009	33,000	$	62.700		(1,305	)

				$	(1,868	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)⁽³⁾			Option Type
	(barrels)	(per barrel)		(in thousands)			Option Type
2008	69,000	$	68.000	$	10		Puts purchased
2008	69,000	$	78.055		(1,589	)	Calls sold
2009	168,000	$	90.000		253		Puts purchased
2009	306,000	$	80.017		(13,525	)	Calls sold
2010	234,000	$	83.027		(9,382	)	Calls sold
2011	72,000	$	87.296		(1,938	)	Calls sold
2012	48,000	$	83.944		(1,380	)	Calls sold

				$	(27,551	)

	Total net liability			$	(223,687	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

⁽²⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾

Puts sold and calls purchased in 2008 and 2009 represent costless collars entered into by the Partnership as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased for 2010 through 2012 to offset positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

⁽⁵⁾	Mmbtu represents million British Thermal Units.

⁽⁶⁾	Includes the Partnership’s premium received from its sale of an option for it to sell 234,000 mmbtu of natural gas for the year ended December 31, 2008 at $18.00 per mmbtu.

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

The Partnership uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 9). All of the Partnership’s derivative contracts are defined as Level 2, with the exception of the Partnership’s NGL fixed price swaps and crude oil options. The Partnership’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. The Partnership’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for the Partnerships NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for the Partnership’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined at Level 3. In accordance with SFAS No. 157, the following table represents the Partnership’s assets and liabilities recorded at fair value as of September 30, 2008 (in thousands):


	Level 1		Level 2			Level 3			Total
Commodity–based derivatives	$	—	$	(21,154	)	$	(203,472	)	$	(224,626	)
Interest rate swap–based derivatives		—		939			—			939

Total	$	—	$	(20,215	)	$	(203,472	)	$	(223,687	)

The Partnership’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of the Partnership’s Level 3 derivative instruments as of September 30, 2008 (in thousands):


	NGL Fixed Price Swaps			Crude Oil Sales Options (assoc. with NGL Volume)			Crude Oil Sales Options			Total
Balance – December 31, 2007	$	(33,624	)	$	(24,740	)	$	(145,418	)	$	(203,782	)
New options contracts		—			262			7,134			7,396
Cash settlements from unrealized gain (loss)⁽¹⁾		(168	)		1,871			254,511			256,214
Cash settlements from other comprehensive income⁽¹⁾		27,057			10,664			83,645			121,366
Net change in unrealized gain (loss)⁽²⁾		8,173			19,831			(219,637	)		(191,633	)
Deferred option premium recognition		—			228			403			631
Net change in other comprehensive loss		(8,687	)		(35,667	)		(149,310	)		(193,664	)

Balance – September 30, 2008	$	(7,249	)	$	(27,551	)	$	(168,672	)	$	(203,472	)

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

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

NOTE 11 – DEBT

Total debt consists of the following (in thousands):


	September 30, 2008			December 31, 2007
Revolving credit facility	$	175,000		$	105,000
Term loan		707,180			830,000
8.125 % Senior notes – due 2015		294,310			294,392
8.75% Senior notes – due 2018		250,000			—
Other debt		8			34

Total debt		1,426,498			1,229,426
Less current maturities		(8	)		(34	)

Total long term debt	$	1,426,490		$	1,229,392

Term Loan and Credit Facility

At September 30, 2008, the Partnership had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. 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, 2008 was 4.9%, and the weighted average interest rate on the outstanding term loan borrowings at September 30, 2008 was 6.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $8.1 million was outstanding at September 30, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet.

In June 2008, the Partnership entered into an amendment to its revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to the Partnership’s early termination of certain derivative contracts (see Note 9) in calculating its Consolidated EBITDA. Pursuant to this amendment, in June 2008, the Partnership repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—Senior Notes”). Additionally, pursuant to this amendment, in June 2008 the Partnership’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.

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, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt 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. In connection with the new credit facility, the Partnership agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, the Partnership and the underwriting bank agreed to extend the agreement through June 30, 2008. In June 2008, the Partnership and the underwriting bank agreed to extend the agreement through November 30, 2008 and amend the underwriting fee to be 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

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 2.75 to 1.0. 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. As of September 30, 2008, the Partnership’s ratio of funded debt to EBITDA was 4.9 to 1.0 and its interest coverage ratio was 3.6 to 1.0.

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, 2008, the Partnership had $250.0 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”) and $293.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”; collectively, the “Senior Notes”). The Partnership’s 8.125% Senior Notes are presented combined with $0.8 million of unamortized premium received as of September 30, 2008. The 8.75% Senior Notes were issued on June 27, 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $244.9 million, after underwriting commissions and other transaction costs. Interest on the Senior Notes in the aggregate 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. Prior to June 15, 2011, the Partnership may redeem up to 35% of the aggregate principal amount of the 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. A similar redemption option exists prior to December 15, 2008 with respect to the 8.125% Senior Notes. The Senior Notes in the aggregate 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.

Indentures governing the Senior Notes in the aggregate contain 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, 2008.

In connection with the issuance of the 8.75% Senior Notes, the Partnership entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If the Partnership does not meet the aforementioned deadline, the 8.75% Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the Partnership has caused the exchange offer to be consummated.

NOTE 12 – 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, 2008, the Partnership is committed to expend approximately $153.9 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 13 – 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 its 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, 2008.

A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, 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, 2008, 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, 2008, 55,103 units will vest within the following twelve months. All units outstanding under the LTIP at September 30, 2008 include DERs granted to the participants by the Committee. The amounts paid with respect to LTIP DERs were $0.1 million and $0.2 million for the three month periods ended September 30, 2008 and 2007, respectively, and $0.4 million and $0.5 million for the nine month periods ended September 30, 2008 and 2007, 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,
	2008			2007			2008			2007
Outstanding, beginning of period		149,923			184,162			129,746			159,067
Granted⁽¹⁾		—			—			54,296			25,095
Matured⁽²⁾		(10,860	)		(38,401	)		(44,229	)		(38,401	)
Forfeited		(1,000	)		(1,000	)		(1,750	)		(1,000	)

Outstanding, end of period⁽³⁾		138,063			144,761			138,063			144,761

Non-cash compensation expense recognized (in thousands)	$	600		$	592		$	1,783		$	2,466

⁽¹⁾

The weighted average prices 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, were $44.43 and $50.09 for awards granted for the nine months ended September 30, 2008 and 2007, respectively. There were no awards granted for the three months ended September 30, 2008 and 2007, respectively.

⁽²⁾

The intrinsic values for phantom unit awards exercised during the three and nine months ended September 30, 2008 were approximately $0.4 million and $1.8 million, respectively. The intrinsic value for phantom unit awards exercised during both the three and nine months ended September 30, 2007 was approximately $2.0 million.

⁽³⁾	The aggregate intrinsic value for phantom unit awards outstanding as of September 30, 2008 was $3.5 million.

At September 30, 2008, the Partnership had approximately $2.7 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 were entitled to receive common units of the Partnership upon the vesting of the awards, which was 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, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of common units estimated to be issued under the incentive compensation agreements will be determined principally by the financial performance of certain Partnership assets for the year ended December 31, 2008 and the market value of the Partnership’s common units at December 31, 2008. The incentive compensation agreements also dictate that no individual covered under the agreements shall receive an amount of common units in excess of one percent of the outstanding common units of the Partnership at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of the Partnership shall be paid in cash.

The Partnership recognized a reduction of compensation expense of $13.3 million and expense of $31.2 million for the three months ended September 30, 2008 and 2007, respectively, and a reduction of expense of $16.1 million and expense of $33.6 million for the nine months ended September 30, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the three and nine months ended September 30, 2008 were principally attributable to changes in the Partnership’s common unit market price, which is utilized in the estimation of the non-cash compensation expense for these awards, at September 30, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through September 30, 2008. The vesting period for such awards concluded on September 30, 2007. 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 and the movement in the market value of the Partnership’s common

units. Based upon management’s estimate of the probable outcome of the performance targets at September 30, 2008, 924,978 common unit awards are ultimately expected to be issued under these agreements during the year ended December 31, 2009, which represents the total 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 14 – 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 $1.2 million and $1.4 million for the three months ended September 30, 2008 and 2007, respectively, and $3.7 million and $2.8 million for the nine months ended September 30, 2008 and 2007, respectively, for compensation and benefits related to their executive officers. For the three months ended September 30, 2008 and 2007, direct reimbursements were $20.8 million and $6.2 million, respectively, and $42.3 million and $18.5 million for the nine months ended September 30, 2008 and 2007, 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 15 – SEGMENT INFORMATION

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Mid-Continent
Revenue:
Natural gas and liquids	$	403,064		$	229,511		$	1,206,386		$	436,479
Transportation, compression and other fees		11,769			12,793			38,772			33,183
Other income (loss), net		153,802			(9,133	)		(247,413	)		(39,918	)

Total revenue and other income (loss), net		568,635			233,171			997,745			429,744

Costs and expenses:
Natural gas and liquids		316,365			174,471			942,022			349,383
Plant operating		16,652			9,108			46,418			18,153
Transportation and compression		1,885			1,943			5,039			5,443
General and administrative		(4,494	)		34,806			5,013			43,506
Depreciation and amortization		20,873			14,992			69,968			26,007
Minority interest		2,591			1,376			7,793			1,376

Total costs and expenses		353,872			236,696			1,076,253			443,868

Segment profit (loss)	$	214,763		$	(3,525	)	$	(78,508	)	$	(14,124	)

Appalachia
Revenue:
Natural gas and liquids	$	1,118		$	380		$	3,201		$	380
Transportation, compression and other fees – affiliates		11,916			8,494			32,496			24,673
Transportation, compression and other fees – third parties		384			156			952			191
Other income		73			99			273			264

Total revenue and other income		13,491			9,129			36,922			25,508

Costs and expenses:
Natural gas and liquids		552			256			1,539			256
Transportation and compression		2,883			1,612			7,842			4,434
General and administrative		1,361			1,505			4,368			4,025
Depreciation and amortization		1,677			1,184			4,603			3,374

Total costs and expenses		6,473			4,557			18,352			12,089

Segment profit	$	7,018		$	4,572		$	18,570		$	13,419

Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent	$	214,763		$	(3,525	)	$	(78,508	)	$	(14,124	)
Appalachia		7,018			4,572			18,570			13,419

Total segment profit (loss)		221,781			1,047			(59,938	)		(705	)
Corporate general and administrative expenses		(1,362	)		(1,505	)		(4,368	)		(4,024	)
Interest expense⁽¹⁾		(21,846	)		(24,040	)		(61,612	)		(38,126	)

Net income (loss)	$	198,573		$	(24,498	)	$	(125,918	)	$	(42,855	)

Capital Expenditures:
Mid-Continent	$	73,490		$	25,353		$	207,862		$	61,449
Appalachia		15,634			9,191			38,532			14,979

	$	89,124		$	34,544		$	246,394		$	76,428

⁽¹⁾	The Partnership notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.


	September 30, 2008		December 31, 2007
Balance sheet
Total assets:
Mid-Continent	$	2,881,521	$	2,813,049
Appalachia		106,806		43,860
Corporate other		68,435		20,705

	$	3,056,762	$	2,877,614

Goodwill:
Mid-Continent	$	674,555	$	706,978
Appalachia		2,305		2,305

	$	676,860	$	709,283

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,
	2008		2007		2008		2007
Natural gas and liquids:
Natural gas	$	154,932	$	76,895	$	483,237	$	161,004
NGLs		219,486		133,425		629,212		240,253
Condensate		15,747		10,208		50,751		14,941
Other ⁽¹⁾		14,017		9,363		46,387		20,661

Total	$	404,182	$	229,891	$	1,209,587	$	436,859

Transportation, compression and other fees:
Affiliates	$	11,916	$	8,494	$	32,496	$	24,673
Third Parties		12,153		12,949		39,724		33,374

Total	$	24,069	$	21,443	$	72,220	$	58,047

⁽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 2007. 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 and Permian Basins and the Golden Trend 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, southern Kansas and southeastern Missouri. Our business is conducted in the midstream segment of the natural gas industry through two reportable 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 (“Ozark Gas Transmission”) that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 400 MMcfd;

•

eight active 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, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing and treating plants or Ozark Gas Transmission, as well as third party pipelines.

Through our Appalachian operations, we own and operate 1,600 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. 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.

Recent Events

In June 2008, we sold 5,750,000 common units in a public offering at a price to the public of $37.52, resulting in approximately $206.6 million of net proceeds. Also in June 2008, we sold 278,000 common units to Atlas Pipeline Holdings, L.P., the parent of our general partner (NYSE: AHD – “AHD”), and 1,112,000 common units to Atlas America, the parent of AHD’s general partner, in a private placement at a net price of $36.02, resulting in approximately $50.1 million of net proceeds. In addition, we received approximately $5.4 million from our general partner to maintain its aggregate 2% general partner interest in us.

The net proceeds from the public and private placement offerings of our common units were utilized to fund the early termination of a majority of our crude oil derivative contracts that we entered into as proxy hedges for the prices we receive for the ethane and propane portion of our NGL equity volume. These hedges, which related to production periods ranging from the end of second quarter of 2008 through the fourth quarter of 2009, were put in place simultaneously with our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 (see “Recent Acquisition”) and had become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. We estimate that we incurred a charge during the second quarter 2008 of approximately $10.6 million due to the decline in the price correlation of crude oil and

ethane and propane. We terminated these derivative contracts during June and July 2008 at an aggregate net cost of approximately $264.0 million. Our net loss for the nine months ended September 30, 2008 includes a $187.6 million cash derivative expense resulting from the aggregate net payments of $264.0 million to unwind a portion of these derivative contracts.

In June 2008, we issued $250.0 million of 10-year, 8.75% senior unsecured notes (the “8.75% Notes”) in a private placement transaction. The sale of the 8.75% Senior Notes generated net proceeds of approximately $244.9 million, which was utilized to repay indebtedness under our senior secured term loan and revolving credit facility.

In June 2008, we obtained $80.0 million of increased commitments to our senior secured revolving credit facility, increasing our aggregate lender commitments to $380.0 million. In connection with this and the previously mentioned transactions, we also amended our senior secured credit facility to, among other things, exclude from the calculation of Consolidated EBITDA the costs associated with the termination of hedging agreements to the extent such costs are financed with or paid out of the net proceeds of an equity offering. In addition, consistent with several other recent energy master limited partnership agreements, our general partner’s managing board and conflicts committee approved an amendment to our limited partnership agreement which will allow the cash expenditure to terminate derivative contracts to not reduce distributable cash flow.

Acquisitions

From the date of our initial public offering in January 2000 through June 2008, we have completed seven acquisitions at an aggregate cost of approximately $2.4 billion. Most recently, in July 2007, we acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 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 “Anadarko 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 Anadarko Assets.

We funded the purchase price, in part, 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. Our general partner also agreed that the resulting allocation of incentive distribution rights back to us would be after the general partner receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see “—Partnership Distributions”). We funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings under our senior secured revolving credit facility that matures in July 2013 (see “—Term Loan and Credit Facility”).

In connection with this acquisition, we reached an agreement with Pioneer Natural Resources Company (“Pioneer” – NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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.

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 gross sales price for natural gas subject, in most cases, to a minimum of $0.35 to $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since our inception in January 2000, our Appalachian system transportation fee has exceeded this minimum generally. The balance of the Appalachian system natural gas we transport is for third-party operators generally under fixed-fee contracts.

Our Mid-Continent segment revenue consists of the fees earned from our transmission, gathering and processing operations. Under certain agreements, we 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. Under other agreements, 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 service is 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 purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of our 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 are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. 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, based on estimated unhedged market prices of $0.78, $6.77 and $65.00 for NGLs, natural gas and condensate, respectively, would result in a change to our gross margin for the twelve-month period ending September 30, 2009 of approximately $18.4 million.

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

Results of Operations

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2008	2007	2008	2007
Operating data⁽¹⁾:
Appalachia:
Average throughput volume – mcfd	91,829	71,876	84,007	66,888
Mid-Continent:
Velma system:
Gathered gas volume – mcfd	64,386	63,757	64,103	62,531
Processed gas volume – mcfd	60,902	61,968	60,972	60,555
Residue gas volume – mcfd	48,300	49,502	48,158	47,487
NGL volume – bpd	6,595	6,215	6,758	6,386
Condensate volume – bpd	308	254	286	222
Elk City/Sweetwater system:
Gathered gas volume – mcfd	279,145	299,450	292,307	298,724
Processed gas volume – mcfd	243,409	231,152	236,520	224,521
Residue gas volume – mcfd	219,945	211,368	213,668	206,011
NGL volume – bpd	11,486	9,782	10,874	9,351
Condensate volume – bpd	251	143	299	228
Chaney Dell system⁽²⁾:
Gathered gas volume – mcfd	300,467	255,649	278,906	255,649
Processed gas volume – mcfd	234,529	249,982	246,365	249,982
Residue gas volume – mcfd	250,994	222,508	238,264	222,508
NGL volume – bpd	14,128	12,678	13,299	12,678
Condensate volume – bpd	759	564	774	564
Midkiff/Benedum system⁽²⁾:
Gathered gas volume – mcfd	143,224	150,061	145,300	150,061
Processed gas volume – mcfd	136,656	144,280	138,178	144,280
Residue gas volume – mcfd	84,372	93,859	92,352	93,859
NGL volume – bpd	18,920	20,702	20,029	20,702
Condensate volume – bpd	1,573	1,754	1,288	1,754
NOARK system:
Average Ozark Gas Transmission throughput volume – mcfd	445,708	325,652	412,634	311,562

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

(2)	The Chaney Dell and Midkiff/Benedum systems were acquired on July 27, 2007.

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Revenue. Natural gas and liquids revenue was $404.2 million for the three months ended September 30, 2008, an increase of $174.3 million from $229.9 million for the three months ended September 30, 2007. The increase was primarily attributable to higher revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which we acquired in late July 2007, of $115.9 million and an increase of $17.4 million and $37.9 million from the Velma and Elk City/Sweetwater systems, respectively, due principally to higher commodity prices and an increase in volumes. Processed natural gas volume on the Chaney Dell system was 234.5 MMcfd for the three months ended September 30, 2008, while the Midkiff/Benedum system had processed natural gas volume of 136.7 MMcfd for the same period. Processed natural gas volume averaged 60.9 MMcfd on the Velma system for the three months ended September 30, 2008, a decrease of 1.7% from the comparable prior year period. However, the Velma system increased its NGL production volume by 6.1% when compared to the prior year comparable quarter to 6,595 bpd for the three months ended September 30, 2008, representing an increase in production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 243.4 MMcfd for the three months ended September 30, 2008, an increase of 5.3% from the comparable prior year period. NGL production volume for the Elk City/Sweetwater system was 11,486 bpd, an increase of 17.4% from the prior year

comparable period, as production efficiency of the processing plants has increased. We enter into derivative instruments principally to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected cash flows attributable to changes in market prices. See further discussion of the derivatives under Note 9 under Item 1, “Financial Statements”.

Transportation, compression and other fee revenue increased to $24.1 million for the three months ended September 30, 2008 compared with $21.4 million for the prior year comparable period. This $2.7 million increase was primarily due to higher throughput volume on our Appalachia system and an increase in the average transportation rate. The Appalachia system’s average throughput volume was 91.8 MMcfd for the three months ended September 30, 2008 as compared with 71.9 MMcfd for the three months ended September 30, 2007, an increase of 27.8%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system, the acquisition of the McKean processing plant and gathering system in central Pennsylvania for $6.1 million in August 2007, and the acquisition of the Vinland processing plant and gathering system in northeastern Tennessee for $9.1 million in February 2008. For the NOARK system, average Ozark Gas Transmission volume was 445.7 MMcfd for the three months ended September 30, 2008, an increase of 36.9% from the prior year comparable period, due to an increase in throughput capacity to 400.0 MMcfd near the completion of the third quarter 2007 and higher customer demand.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was income of $153.9 million for the three months ended September 30, 2008, a favorable movement of $162.9 million from the prior year comparable period. This favorable movement was primarily due to a $243.4 million favorable movement in non-cash mark-to-market adjustments, partially offset by a $70.3 million net cash derivative expense related to the early termination of a portion of our crude oil derivative contracts (see “Recent Events”) and an unfavorable movement of $17.4 million related to non-qualified derivative cash settlements. The $243.4 million favorable movement in non-cash mark-to-market adjustments was due principally to a decrease in forward crude oil market prices from June 30, 2008 to September 30, 2008 and their favorable mark-to-market impact on certain non-qualified derivative contracts we have for production volumes in future periods. Average forward crude oil market prices, which are the basis for adjusting the fair value of our crude oil derivative contracts, at September 30, 2008 were $102.50 per barrel, a decrease of $37.76 from average forward crude oil market prices at June 30, 2008 of $140.26 per barrel. We enter into derivative instruments principally 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 Note 9 under Item 1, “Financial Statements”.

Costs and Expenses. Natural gas and liquids cost of goods sold of $316.9 million and plant operating expenses of $16.7 million for the three months ended September 30, 2008 represent increases of $142.2 million and $7.6 million, respectively, from the comparable prior year amounts due primarily to a full quarter’s contribution from the Chaney Dell and Midkiff/Benedum systems, which were acquired in late July 2007, higher overall commodity prices and an increase in production volume on the Velma and Elk City/Sweetwater systems. Transportation and compression expenses increased $1.2 million to $4.8 million for the three months ended September 30, 2008 due principally to an increase in Appalachia system operating and maintenance costs as a result of increased capacity, additional well connections and operating costs of the McKean processing plant and gathering system acquired in August 2007 and the Vinland processing plant and gathering system acquired in February 2008.

General and administrative expense (income), including amounts reimbursed to affiliates, decreased $39.6 million to income of $1.8 million for the three months ended September 30, 2008 compared with expense of $37.8 million for the prior year comparable period. This decrease was primarily related to a $44.5 million decrease in non-cash compensation expense, partially offset by higher costs of managing our operations, including the Chaney Dell and Midkiff/Benedum systems acquired in late July 2007 and acquisition and capital raising activities. The decrease in non-cash compensation expense was principally attributable to a $13.3 million mark-to-market gain recognized for certain common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year and is based upon the financial performance of our acquired assets. The

mark-to-market gain was the result of a significant change in our common unit market price at September 30, 2008 when compared with the June 30, 2008 price, which is utilized in the estimate of the non-cash compensation expense for these awards. Non-cash compensation expense of $31.8 million for the three months ended September 30, 2007 included $31.2 million recognized in connection with these common unit awards as a result of the effect the Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards.

Depreciation and amortization increased to $22.6 million for the three months ended September 30, 2008 compared with $16.2 million for the three months ended September 30, 2007 due primarily to the depreciation associated with our Chaney Dell and Midkiff/Benedum acquired assets and our expansion capital expenditures incurred subsequent to September 30, 2007.

Interest expense decreased to $21.8 million for the three months ended September 30, 2008 as compared with $24.0 million for the comparable prior year period. This $2.2 million decrease was primarily due to a $4.6 million decrease in amortization expense related to deferred financing costs and a $3.3 million decrease in interest expense associated with the term loan issued in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Term Loan and Credit Facility”), partially offset by a $5.5 million increase in interest expense related to our additional senior notes issued during June 2008 (see “—Senior Notes”). In June 2008, we issued $250.0 million of 10-year 8.75% senior unsecured notes in a private placement transaction, of which we utilized $122.8 million to repay a portion of the indebtedness under our senior secured term loan. Interest expense for the three months ended September 30, 2007 included $5.0 million of accelerated amortization associated with the replacement of our previous credit facility with a new credit facility in July 2007.

Minority interest expense increased to $2.6 million for the three months ended September 30, 2008 compared with $1.4 million for the comparable prior year period. This increase was primarily due to the increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. The minority interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Revenue. Natural gas and liquids revenue was $1,209.6 million for the nine months ended September 30, 2008, an increase of $772.7 million from $436.9 million for the nine months ended September 30, 2007. The increase was primarily attributable to an increase in revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which we acquired in July 2007, of $620.3 million and an increase from the Velma and Elk City/Sweetwater systems of $57.7 million and $85.1 million, respectively, due principally to higher commodity prices and an increase in volumes. Processed natural gas volume on the Chaney Dell system was 246.4 MMcfd for the nine months ended September 30, 2008, while the Midkiff/Benedum system had processed natural gas volume of 138.2 MMcfd for the same period. Processed natural gas volume averaged 61.0 MMcfd on the Velma system for the nine months ended September 30, 2008, an increase of 0.7% from the comparable prior year period. However, the Velma system increased its NGL production volume by 5.8% when compared to the prior year comparable quarter to 6,758 bpd for the nine months ended September 30, 2008, representing an increase in production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 236.5 MMcfd for the nine months ended September 30, 2008, an increase of 5.3% from the comparable prior year period. NGL production volume for the Elk City/Sweetwater system was 10,874 bpd, an increase of 16.3% from the prior year comparable period, as production efficiency of the processing plants has increased. We enter into derivative instruments principally to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected cash flows attributable to changes in market prices. See further discussion of the derivatives under Note 9 under Item 1, “Financial Statements”.

Transportation, compression and other fee revenue increased to $72.2 million for the nine months ended September 30, 2008 compared with $58.0 million for the prior year comparable period. This $14.2 million increase was primarily due to an $8.6 million increase from the Appalachia system, due to higher throughput volume and a higher average transportation rate, and $6.6 million of increased contributions from the Chaney Dell and Midkiff/Benedum systems. The Appalachia system’s average throughput volume was 84.0 MMcfd for the nine months ended September 30, 2008 as compared with 66.9 MMcfd for the nine months ended September 30, 2007, an increase of 25.6%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system, the acquisition of the McKean and Vinland processing plants and gathering systems. For the NOARK system, average Ozark Gas Transmission volume was 412.6 MMcfd for the nine months ended September 30, 2008, an increase of 101.0 MMcfd or 32.4% from the prior year comparable period due to an increase in throughput capacity to 400.0 MMcfd during the third quarter 2007 and higher customer demand.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a loss of $247.1 million for the nine months ended September 30, 2008, an unfavorable movement of $207.4 million from the prior year comparable period. This unfavorable movement was due primarily to a net cash loss of $186.1 million and a non-cash derivative loss of $39.9 million related to the early termination of a portion of our crude oil derivative contracts (see “—Recent Events”), and an unfavorable movement of $51.7 million related to non-qualified derivative cash settlements. These amounts were partially offset by a $62.6 million favorable movement in non-cash mark-to-market adjustments. We enter into derivative instruments principally 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 Note 9 under Item 1, “Financial Statements”.

Costs and Expenses. Natural gas and liquids cost of goods sold of $943.6 million and plant operating expenses of $46.4 million for the nine months ended September 30, 2008 represented increases of $594.0 million and $28.2 million, respectively, from the comparable prior year amounts due primarily to a full period’s contribution from the Chaney Dell and Midkiff/Benedum systems, higher overall commodity prices and an increase in production volume on the Velma and Elk City/Sweetwater systems. Transportation and compression expenses increased $3.0 million to $12.9 million for the nine months ended September 30, 2008 due to an increase in Appalachia system operating and maintenance costs as a result of increased capacity, additional well connections and operating costs of the McKean and Vinland processing plants and gathering systems.

General and administrative expense, including amounts reimbursed to affiliates, decreased $37.9 million to $13.7 million for the nine months ended September 30, 2008 compared with $51.6 million for the prior year comparable period. The decrease was primarily related to a $50.4 million decrease in non-cash compensation expense, partially offset by higher costs of managing our operations, including the Chaney Dell and Midkiff/Benedum systems acquired in July 2007 and acquisition and capital raising activities. The decrease in non-cash compensation expense was principally attributable to a $49.7 million mark-to-market gain recognized for certain common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year and is based upon the financial performance of our acquired assets. The mark-to-market gain was the result of a significant change in our common unit market price at September 30, 2008 when compared with the December 31, 2007 price, which is utilized in the estimate of the non-cash compensation expense for these awards. Non-cash compensation expense of $36.1 million for the nine months ended September 30, 2007 included $33.6 million recognized in connection with these common unit awards as a result of the effect the Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards.

Depreciation and amortization increased to $74.6 million for the nine months ended September 30, 2008 compared with $29.4 million for the nine months ended September 30, 2007 due primarily to the depreciation associated with our Chaney Dell and Midkiff/Benedum acquired assets, our expansion capital expenditures incurred subsequent to September 30, 2007 and an $8.0 million write-off of costs related to a pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with a contractual arrangement.

Interest expense increased to $61.6 million for the nine months ended September 30, 2008 as compared with $38.1 million for the comparable prior year period. This $23.5 million increase was primarily due to $21.6 million of interest associated with the term loan issued in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Term Loan and Credit Facility”) and a $5.8 million increase in interest expense related to our additional senior notes issued during June 2008 (see “—Recent Events”).

Minority interest expense increased $6.4 million to $7.8 million for the nine months ended September 30, 2008 from $1.4 million for the comparable prior year period. This increase was primarily due to higher net income for the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. The minority interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

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:

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

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

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

We had $175.0 million outstanding under our $380.0 million senior secured credit facility at September 30, 2008 and $8.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $196.9 million of remaining committed capacity under the 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 $136.4 million remains available at September 30, 2008. At September 30, 2008, we had a working capital deficit of $98.3 million compared with a $78.2 million working capital deficit at December 31, 2007. This decrease in working capital was primarily due to a $49.0 million increase in accounts payable and a $15.6 million decrease in accounts receivable, partially offset by a $31.8 million increase in cash and cash equivalents and a $20.3 million decrease in the current portion of our hedge liability. 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, 2008 Compared to Nine Months Ended September 30, 2007

Net cash used in operating activities of $63.1 million for the nine months ended September 30, 2008 represented a decrease of $132.8 million from $69.7 million of net cash provided by operating activities for the comparable prior year period. The decrease was derived principally from a $203.8 million decrease in net income excluding non-cash charges, partially offset by a $71.0 million increase in cash flows from working capital changes. The decrease in net income excluding non-cash charges was principally due to the $187.6 million unfavorable cash impact from the early termination of certain derivative instruments during June and July 2008 (see “—Recent Events”). The non-cash charges which impacted net income include a $96.3 million increase in non-cash

derivative gains and a $50.4 million decrease in non-cash compensation expense, partially offset by a $45.2 million increase in depreciation and amortization expense. The movement in non-cash derivative gains and losses resulted from decreases in commodity prices during the nine months ended September 30, 2008 and their favorable impact on the fair value of derivative contracts we have for future periods. The increase in depreciation and amortization principally resulted from our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized during the nine months ended September 30, 2008 for certain common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year. The mark-to-market gain was the result of a decrease in our common unit market price at September 30, 2008 when compared with the December 31, 2007 price, which is utilized in the estimate of the non-cash compensation expense for these awards.

Net cash used in investing activities was $213.9 million for the nine months ended September 30, 2008, a decrease of $1,736.8 million from $1,950.7 million for the comparable prior year period. This decrease was principally due to a $1,905.1 million decrease in net cash paid for acquisition, partially offset by a $170.0 million increase in capital expenditures. Net cash paid for acquisitions of $1,873.7 million in the prior year period represents the net amount paid for our acquisition of the Chaney Dell and Midkiff/Benedum systems. The $31.4 million of net cash paid for acquisition in the current period principally represents the reimbursement of state sales tax initially paid for our prior year acquisition of the Chaney Dell and Midkiff/Benedum systems. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities was $308.8 million for the nine months ended September 30, 2008, a decrease of $1,595.2 million from $1,904.0 million for the comparable prior year period. This decrease was principally due to a $858.3 million decrease from the net proceeds from the issuance of our common units, a $581.2 million decrease from the net proceeds from the issuance of long-term debt, a $122.8 million increase in repayments of long-term debt, and a $93.1 million increase in cash distributions to common limited partners and the general partner, partially offset by a $74.5 million increase in borrowings under our revolving credit facility. The decrease in net proceeds from the issuance of our common units and long-term debt were due to the prior year financing of 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:

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

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expansion capital expenditures to acquire complementary assets and to expand the capacity of 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,
	2008		2007		2008		2007
Maintenance capital expenditures	$	1,711	$	2,328	$	5,375	$	3,800
Expansion capital expenditures		87,413		32,216		241,019		72,628

Total	$	89,124	$	34,544	$	246,394	$	76,428

Expansion capital expenditures increased to $87.4 million and $241.0 million for the three and nine months ended September 30, 2008, respectively, due principally to the expansion of our gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in our service areas, including the construction of a 60 MMcfd expansion of our Sweetwater processing plant. The decrease in maintenance capital expenditures for the three months ended September 30, 2008 when compared with the prior year third quarter was due to changes in the timing of scheduled maintenance activity between periods. The increase in maintenance capital expenditures for the nine months ended September 30, 2008 when compared with the prior year comparable period was due to the maintenance capital requirements of the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and fluctuations in the timing of our scheduled maintenance activity. As of September 30, 2008, we are committed to expend approximately $153.9 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, 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 in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Acquisitions”). Our general partner also agreed that the resulting allocation of incentive distribution rights back to us would be after the general partner receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter. Of the $37.3 million of incentive distributions declared for the nine months ended September 30, 2008, the general partner received $23.5 million after the allocation of $13.8 million of its incentive distribution rights back to us.

Common Equity Offerings

In June 2008, we sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we sold 1,112,000 common units to Atlas America and 278,000 common units to AHD in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. We also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in us. We utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see “—Recent Events”).

In July 2007, we sold 25,568,175 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 25,568,175 common units sold, 3,835,227 common units 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 Chaney Dell and Midkiff/Benedum acquisitions (see “—Acquisitions”).

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, 2008, $136.4 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

In March 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 in May 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 in March 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for our common units. In April 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 in March 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing May 8, 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 $53.22. If not converted into common units or redeemed prior to May 2010, the preferred units will automatically be converted into our common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, we issued $8.5 million of our 8.125% senior unsecured notes due 2015 (see Note 4 under Item 1, “Financial Statements”) to Sunlight Capital. We recorded the senior unsecured notes issued as long-term debt and a preferred unit dividend within partners’ capital on our consolidated balance sheet and, during the nine months ended September 30, 2007, reduced net income (loss) attributable to common limited partners and the general partner by $3.8 million of this amount, which was 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.

Sunlight Capital is entitled to receive the dividends on the preferred units pro rata from the March 2008 commencement date. Dividends previously paid and those to be paid on the preferred units and the premium paid upon their redemption, if any, will be recognized as a reduction to our net income (loss) in determining net income (loss) attributable to common unitholders and the general partner. If converted to common units, the preferred equity amount converted will be reclassified to common unit equity within partners’ capital on our consolidated balance sheet.

Term Loan and Credit Facility

At September 30, 2008, we had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million 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 revolving credit facility borrowings at September 30, 2008 was 4.9%, and the weighted average interest rate on the outstanding term loan borrowings at September 30, 2008 was 6.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $8.1 million was outstanding at September 30, 2008. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet.

In June 2008, we entered into an amendment to our revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to our early termination of certain derivative contracts (see “—Recent Events”) in calculating our Consolidated EBITDA. Pursuant to this amendment, in June 2008, we repaid $122.8 million of our outstanding term loan and repaid $120.0 million of outstanding borrowings under the credit facility with proceeds from our issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—Senior Notes”). Additionally, pursuant to this amendment, in June 2008 our lenders increased their commitments for our revolving credit facility by $80.0 million to $380.0 million.

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 its 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, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt 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. In connection with the new credit facility, we agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, we and the underwriting bank agreed to extend the agreement through June 30, 2008. In June 2008, we and the underwriting bank agreed to extend the agreement through November 30, 2008 and amend the underwriting fee to be 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

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 2.75 to 1.0. 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. As of September 30, 2008, our ratio of funded debt to EBITDA was 4.9 to 1.0 and our interest coverage ratio was 3.6 to 1.0.

We are unable to borrow under our credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to our partnership agreement.

Senior Notes

At September 30, 2008, we had $250.0 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”) and $293.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”; collectively, the “Senior Notes”). Our 8.125% Senior Notes are presented combined

with $0.8 million of unamortized premium received as of September 30, 2008. The 8.75% Senior Notes were issued in June 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $244.9 million, after underwriting commissions and other transaction costs. Interest on the Senior Notes in the aggregate 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. Prior to June 15, 2011, we may redeem up to 35% of the aggregate principal amount of the 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. A similar redemption option exists prior to December 15, 2008 with respect to the 8.125% Senior Notes. The Senior Notes in the aggregate 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.

Indentures governing the Senior Notes in the aggregate contain 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, 2008.

In connection with the issuance of the 8.75% Senior Notes, we entered into a registration rights agreement, whereby we agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If we do not meet the aforementioned deadline, the 8.75% Senior Notes will be subject to additional interest, up to 1% per annum, until such time that we have caused the exchange offer to be consummated.

Off Balance Sheet Arrangements

As of September 30, 2008, our off balance sheet arrangements are limited to our letters of credit outstanding of $8.1 million and our commitments to expend approximately $153.9 million on capital projects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, stock compensation, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2007, and there have been no material changes to these policies through September 30, 2008.

Fair Value of Financial Instruments

We adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

We use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for our respective outstanding derivative contracts (see Note 9). All of our derivative contracts are defined as Level 2, with the exception of our NGL fixed price swaps and crude oil options. Our Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Our interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for our NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for our crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3.

Recently Adopted Accounting Standards

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment to FASB Statement No. 115” (“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 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. We adopted SFAS No. 159 at January 1, 2008, and have elected not to apply the fair value option to any of our financial instruments.

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. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-b, “Effective Date of FASB Statement No. 157”, which provides for a one-year deferral of the effective date of SFAS No. 157 with regard to an entity’s non-financial assets, non-financial liabilities or any non-recurring fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 157 at January 1, 2008 with respect to our derivative instruments, which are measured at fair value within our financial statements. The provisions of SFAS No. 157 have not been applied to our non-financial assets and non-financial liabilities. See “—Fair Value of Financial Instruments” for disclosures pertaining to the provisions of SFAS No. 157 with regard to our financial instruments.

Recently Issued Accounting Standards

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. We will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and we currently do not expect the adoption of FSP EITF 03-6-1 to have an impact on our financial position and results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles. SFAS No. 162 is effective beginning November 15, 2008. We currently do not expect the adoption of SFAS No. 162 to have a material impact on our financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. generally accepted accounting principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. We will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and we currently do not expect the adoption of FSP FAS 142-3 to have a material impact on our financial position and results of operations.

In March 2008, the FASB ratified the Emerging Issues Task Force (“EITF”) 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, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF 07-4 also considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. We expect the adoption of EITF No. 07-4 will impact our presentation of net income (loss) per common limited partner unit as we currently present net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see Note 2, “Net Income (Loss)

Per Common Unit”, under Item 1, “Financial Statements”). Under the guidance of EITF 07-4, our management believes that the partnership agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings will no longer be allocated to the incentive distribution rights upon adoption of EITF No. 07-4 effective January 1, 2009.

In March 2008, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. We are currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding our derivative instruments.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and we are currently evaluating whether SFAS No. 160 will have a material impact on our financial position and results of operations.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”, however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. We will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and we are currently evaluating whether SFAS No. 141(R) will have a material 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 natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our 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, 2008. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties to our commodity and interest-rate derivative contracts are banking institutions who also participate in our revolving credit facility. The creditworthiness of our counterparties is constantly monitored, and we are not aware of any inability on the part of our counterparties to perform under our contracts.

Interest Rate Risk. At September 30, 2008, we had a $380.0 million senior secured revolving credit facility ($175.0 million outstanding). We also had $707.2 million outstanding under our senior secured term loan at September 30, 2008. The weighted average interest rate for the revolving credit facility borrowings was 4.9% at September 30, 2008, and the weighted average interest rate for the term loan borrowings was 6.2% at September 30, 2008.

At September 30, 2008, we have interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, we will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of our revolving credit facility (see “—Term Loan and Credit Facility”), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of our floating rate debt under the term loan and revolving credit facility to fixed-rate debt. The interest rate swap agreements are effective as of September 30, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by $4.3 million.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. For gathering services, 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. A 10% change in the average price of NGLs, natural gas and condensate we process and sell, based on estimated unhedged market prices of $0.78, $6.77 and $65.00 for NGLs, natural gas and condensate, respectively, would result in a change to our gross margin for the twelve-month period ending September 30, 2009 of approximately $18.4 million.

We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price and interest rate risk management activities. 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. We also enter into financial swap instruments to hedge certain portions of our floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold or interest payments on the underlying debt instrument is due. Under 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. Commodity-based 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.

We apply the provisions of SFAS No. 133 to its derivative instruments. 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 derivative contracts to the forecasted transactions. Under SFAS No. 133, we can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, we will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by us through the utilization of market data, will be recognized within other income (loss) in our consolidated statements of operations. For derivatives previously qualifying as hedges, we recognized the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassified the portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions were 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.

On July 1, 2008, we elected to discontinue hedge accounting for our existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss) in our consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within partners’ capital on our consolidated balance sheet, will be reclassified to our consolidated statements of operations in the future at the time the originally hedged physical transactions effect earnings.

During June and July 2008, we made net payments of $264.0 million related to the early termination of crude oil derivative contracts that were entered into as proxy hedges for the prices received on the ethane and propane portion of our NGL equity volume. These derivative contracts were put into place simultaneously with our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and nine months ended September 30, 2008, we recognized the following derivative activity related to the termination of these derivative instruments (amounts in thousands):


	Early Termination of Derivative Contracts
	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Net cash derivative expense included within other income (loss), net on our consolidated statements of operations	$	(70,258	)	$	—	$	(186,068	)	$	—
Net cash derivative expense included within natural gas and liquids revenue on our consolidated statements of operations		(1,258	)		—		(1,573	)		—
Net non-cash derivative income (expense) included within other income (loss), net on our consolidated statements of operations		6,488			—		(39,857	)		—
Net non-cash derivative expense included within natural gas and liquids on our consolidated statements of operations		(19,514	)		—		(19,514	)		—

In addition, $63.3 million will be reclassified from accumulated other comprehensive loss within partner’s capital on our consolidated balance sheet and recognized as non-cash derivative expenses during the period beginning on October 1, 2008 and ending on December 31, 2009, the remaining period for which the derivatives were originally scheduled to be settled, as a result of the early termination of certain derivatives that were classified as cash flow hedges in accordance with SFAS No. 133 at the date of termination.

The following table summarizes our cumulative derivative activity for the periods indicated (amounts in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(27,419	)	(12,850	)	$	(78,214	)	$	(23,548	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		(190,013	)	(15,595	)		17,919			(35,731	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		(44,997	)	7,164			(41,271	)		(3,526	)
Loss from cash settlement of non-qualifying derivatives⁽²⁾		(84,207	)	(3,037	)		(280,696	)		(3,037	)
Loss from cash settlement of interest rate derivatives⁽³⁾		(673	)	—			(867	)		—

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

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

⁽³⁾	Included within interest expense on our consolidated statements of operations.

As of September 30, 2008, we had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Asset/(Liability)⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2008	$	413
				2009		238
				2010		65

					$	716

April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2008	$	365
				2009		(339	)
				2010		197

					$	223

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2008	7,434,000	$	0.697	$	(3,642	)
2009	8,568,000	$	0.746		(3,607	)

				$	(7,249	)

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)⁽³⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)			Option Type
2008	536,400	29,972,124	$	70.16	$	110		Puts purchased
2008	126,000	11,219,040	$	127.55		(3,531	)	Puts sold⁽⁴⁾
2008	126,000	11,219,040	$	140.00		65		Calls purchased⁽⁴⁾
2008	473,400	25,764,984	$	80.13		(10,104	)	Calls sold
2009	1,584,000	85,038,534	$	80.00		2,372		Puts purchased
2009	304,200	27,085,968	$	126.05		(9,082	)	Puts sold⁽⁴⁾
2009	304,200	27,085,968	$	143.00		1,026		Calls purchased⁽⁴⁾
2009	2,121,600	114,072,336	$	81.01		(51,161	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(90,981	)	Calls sold
2010	714,000	45,415,440	$	120.00		8,966		Calls purchased⁽⁴⁾
2011	606,000	32,578,560	$	95.56		(13,597	)	Calls sold
2011	252,000	13,547,520	$	120.00		3,462		Calls purchased⁽⁴⁾
2012	450,000	24,192,000	$	97.10		(9,981	)	Calls sold
2012	180,000	9,676,800	$	120.00		2,629		Calls purchased⁽⁴⁾

					$	(169,807	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾		(in thousands)
2008	1,371,000	$	8.823	$	1,722
2009	5,724,000	$	8.611		2,667
2010	4,560,000	$	8.526		(269	)
2011	2,160,000	$	8.270		(583	)
2012	1,560,000	$	8.250		(251	)

				$	3,286

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	1,371,000	$	(0.744	)	$	2,042
2009	5,724,000	$	(0.558	)		1,599
2010	4,560,000	$	(0.622	)		732
2011	2,160,000	$	(0.664	)		217
2012	1,560,000	$	(0.601	)		97

					$	4,687

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	4,065,000	$	8.274	⁽⁶⁾	$	(5,622	)
2009	15,564,000	$	8.680			(8,329	)
2010	8,940,000	$	8.580			196
2011	2,160,000	$	8.270			583
2012	1,560,000	$	8.250			251

					$	(12,921	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2008	4,065,000	$	(1.114	)	$	(6,761	)
2009	15,564,000	$	(0.654	)		(5,362	)
2010	8,940,000	$	(0.600	)		(2,118	)
2011	2,160,000	$	(0.700	)		(50	)
2012	1,560,000	$	(0.610	)		(49	)

					$	(14,340	)

Ethane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)		Option Type
2008	7,560,000	$	0.7885	$	399	Puts purchased
2009	16,254,000	$	0.6928		196	Puts purchased

				$	595

Propane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)		Option Type
2008	8,946,000	$	1.4752	$	174	Puts purchased
2009	23,310,000	$	1.3935		368	Puts purchased

				$	542

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2008	14,100	$	60.569	$	(563	)
2009	33,000	$	62.700		(1,305	)

				$	(1,868	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)⁽³⁾			Option Type
	(barrels)	(per barrel)		(in thousands)			Option Type
2008	69,000	$	68.000	$	10		Puts purchased
2008	69,000	$	78.055		(1,589	)	Calls sold
2009	168,000	$	90.000		253		Puts purchased
2009	306,000	$	80.017		(13,525	)	Calls sold
2010	234,000	$	83.027		(9,382	)	Calls sold
2011	72,000	$	87.296		(1,938	)	Calls sold
2012	48,000	$	83.944		(1,380	)	Calls sold

				$	(27,551	)

	Total net liability			$	(223,687	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

⁽²⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾

Puts sold and calls purchased in 2008 and 2009 represent costless collars entered into by us as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased for 2010 through 2012 to offset positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

⁽⁵⁾	Mmbtu represents million British Thermal Units.

⁽⁶⁾	Includes our premium received from our sale of an option for us to sell 234,000 mmbtu of natural gas for the year ended December 31, 2008 at $18.00 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 at September 30, 2008.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A.

RISK FACTORS

The risk factors set forth below should be read in conjunction with those appearing in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Due to the accounting of our derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions.

With the objective of enhancing the predictability of future revenues, from time to time we enter into natural gas, natural gas liquids and crude oil derivative contracts. We account for these derivative contracts by applying the provisions of SFAS No. 133. Due to the mark-to-market accounting treatment for these derivative contracts, we could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in our recognizing a non-cash loss in our consolidated statements of operations or through accumulated other comprehensive income (loss) and a consequent non-cash decrease in our partners’ capital between reporting periods. Any such decrease could be substantial. In addition, we may be required to make a cash payment upon the termination of any of these derivative contracts.

Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.

Our operations expose us to fluctuations in commodity prices. We utilize derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. We also have exposure to interest rate fluctuations as a result of variable rate debt under our term loan and revolving credit facility. We have entered into interest rate swap agreements to convert a portion of this variable rate debt to a fixed rate obligation, thereby reducing our exposure to market rate fluctuations.

We have entered into derivative transactions related to only a portion of our crude oil, natural gas and NGL volume and our variable rate debt. As a result, we will continue to have direct commodity price risk and interest rate risk with respect to the unhedged portion of these items. To the extent we hedge our commodity price and interest rate risk using certain derivative contracts, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

Even though our hedging activities are monitored by management, these activities could reduce our cash flow in some circumstances, including if the counterparty to the hedging contract defaults on its contract obligations, if there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received or, with regard to commodity derivatives, if production is less than expected. With respect to commodity derivative contracts, if the actual amount of production is lower than the amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our cash flow. In addition, we have entered into proxy hedges with respect to our NGLs, typically using crude oil derivative contracts, based upon the historical price correlation between crude oil and NGLs. Certain of these proxy hedges could become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. If these proxy hedges remain less effective, our settlement of the contracts could result in significant costs to us.

The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

ITEM 6.

EXHIBITS


Exhibit No.		Description

3.1		Certificate of Limited Partnership⁽¹⁾

3.2		Second Amended and Restated Agreement of Limited Partnership⁽²⁾

3.2(a)		Amendment No. 1 to Second Amendment and Restated Agreement of Limited Partnership⁽³⁾

3.2(b)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership⁽⁴⁾

3.2(c)		Amendment No. 3 to Second Amendment and Restated Agreement of Limited Partnership⁽⁵⁾

3.2(d)		Amendment No. 4 to Second Amendment and Restated Agreement of Limited Partnership⁽⁶⁾

3.3		Certificate of Designation of 6.5% Cumulative Convertible Preferred Units⁽⁷⁾

3.3(a)		Amended and Restated Certificate of Designation⁽⁸⁾

4.1		Common unit certificate⁽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 registration statement on Form S-1 on January 20, 2000.

⁽²⁾	Previously filed as an exhibit to registration statement on Form S-3 on April 2, 2004.

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

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

⁽⁵⁾	Previously filed as an exhibit to current report on Form 8-K on January 8, 2008.

⁽⁶⁾	Previously filed as an exhibit to current report on Form 8-K on June 16, 2008.

⁽⁷⁾	Previously filed as an exhibit to current report on Form 8-K on March 14, 2006.

⁽⁸⁾	Previously filed as an exhibit to current report on Form 8-K on April 19, 2007.

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 6, 2008	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 6, 2008	By:	/s/ MICHAEL L. STAINES
		Michael L. Staines
		President, Chief Operating Officer and Managing Board Member of the General Partner

Date: November 6, 2008	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer of the General Partner

Date: November 6, 2008	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer of the General Partner