Edgar Filing: ATLAS PIPELINE PARTNERS LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

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 March 31, 2008 and December 31, 2007 (Unaudited)	3

	Consolidated Statements of Operations for the Three Months Ended March 31, 2008 and 2007 (Unaudited)	4

	Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2008 (Unaudited)	5

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	46

PART II.	OTHER INFORMATION

Item 1A.	Risk Factors	47

Item 6.	Exhibits	47

SIGNATURES		48

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	March 31, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	2,555		$	11,980
Accounts receivable – affiliates		7,323			3,334
Accounts receivable		192,229			147,360
Prepaid expenses and other		18,278			14,749

Total current assets		220,385			177,423

Property, plant and equipment, net		1,812,029			1,748,661

Intangible assets, net		212,815			219,203

Goodwill		676,802			709,283

Minority interest		486			2,163

Other assets, net		20,382			20,881

	$	2,942,899		$	2,877,614

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	26		$	34
Accounts payable		19,431			20,530
Accrued liabilities		40,246			43,487
Current portion of derivative liability		113,504			110,867
Accrued producer liabilities		104,757			80,698

Total current liabilities		277,964			255,616

Long-term derivative liability		154,595			118,646

Long-term debt, less current portion		1,289,365			1,229,392

Other long-term liability		644			—

Commitments and contingencies

Partners’ capital:
Preferred limited partner’s interests		37,718			37,076
Common limited partners’ interests		1,178,189			1,269,521
General partner’s interest		30,246			29,413
Accumulated other comprehensive loss		(25,822	)		(62,050	)

Total partners’ capital		1,220,331			1,273,960

	$	2,942,899		$	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 March 31,
	2008			2007
Revenue:
Natural gas and liquids	$	366,119		$	102,176
Transportation, compression and other fees – affiliates		9,159			7,720
Transportation, compression and other fees – third parties		14,862			9,838
Other loss, net		(86,754	)		(2,197	)

Total revenue and other loss, net		303,386			117,537

Costs and expenses:
Natural gas and liquids		276,664			87,810
Plant operating		14,935			4,530
Transportation and compression		3,812			3,112
General and administrative		4,370			5,703
Compensation reimbursement – affiliates		1,129			630
Depreciation and amortization		25,825			6,534
Interest		20,381			6,759
Minority interest		2,090			—

Total costs and expenses		349,206			115,078


Net income (loss)		(45,820	)		2,459
Preferred unit dividend effect		(137	)		—
Preferred unit imputed dividend cost		(505	)		(499	)

Net income (loss) attributable to common limited partners and the general partner	$	(46,462	)	$	1,960

Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(52,387	)	$	(1,884	)
General partner’s interest		5,925			3,844

Net income (loss) attributable to common limited partners and the general partner	$	(46,462	)	$	1,960

Net loss attributable to common limited partners per unit:
Basic	$	(1.35	)	$	(0.14	)

Diluted	$	(1.35	)	$	(0.14	)

Weighted average common limited partner units outstanding:
Basic		38,763			13,080

Diluted		38,763			13,080

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED MARCH 31, 2008

(in thousands, except unit data)

(Unaudited)


	Number of Limited Partner Units		Preferred Limited Partner		Common Limited Partners			General Partner			Accumulated Other Comprehensive Gain (Loss)			Total Partners’ Capital
	Preferred	Common	Preferred Limited Partner		Common Limited Partners			General Partner			Accumulated Other Comprehensive Gain (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	—	—		—		16			—			—			16
Unissued common units under incentive plans	—	—		—		(2,795	)		—			—			(2,795	)
Issuance of units under incentive plans	—	11,358		—		—			—			—			—
Distributions paid to common limited partners and the general partner	—	—		—		(36,051	)		(5,092	)		—			(41,143	)
Distribution equivalent rights paid on unissued units under incentive plans	—	—		—		(115	)		—			—			(115	)
Other comprehensive income	—	—		—		—			—			36,228			36,228
Net income (loss)	—	—		642		(52,387	)		5,925			—			(45,820	)

Balance at March 31, 2008	40,000	38,769,939	$	37,718	$	1,178,189		$	30,246		$	(25,822	)	$	1,220,331

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Three Months Ended March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(45,820	)	$	2,459
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		25,825			6,534
Non-cash loss on derivative value		74,814			2,277
Non-cash compensation expense (income)		(2,795	)		1,781
Amortization of deferred finance costs		679			534
Minority interest		2,090			—
Net distributions paid to minority interest holders		(413	)		—
Gain on asset sales and dispositions		(132	)		—
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(17,447	)		5,254
Accounts payable and accrued liabilities		22,066			(4,168	)
Accounts payable and accounts receivable – affiliates		(3,989	)		2,616

Net cash provided by operating activities		54,878			17,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition purchase price adjustment		1,281			—
Capital expenditures		(84,069	)		(16,629	)
Other		(251	)		94

Net cash used in investing activities		(83,039	)		(16,535	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		75,000			60,500
Repayments under credit facility		(15,000	)		(45,500	)
Distributions paid to common limited partners and the general partner		(41,143	)		(15,442	)
Other		(121	)		(266	)

Net cash provided by (used in) financing activities		18,736			(708	)


Net change in cash and cash equivalents		(9,425	)		44
Cash and cash equivalents, beginning of period		11,980			1,795

Cash and cash equivalents, end of period	$	2,555		$	1,839

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 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 5,476,253 limited partner units in the Partnership. At March 31, 2008, the Partnership had 38,769,939 common limited partnership units, including the 5,476,253 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 64.0% ownership interest in AHD at March 31, 2008, also owns a 49.4% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded partnership (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 month period ended March 31, 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, stock compensation and the purchase price allocation for the acquisition of Chaney Dell and Midkiff/Benedum systems, all of which could affect the reported amounts for property, plant and equipment, goodwill, and other intangible assets, and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 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 in an amount equal to the general partner’s incentive distributions, in accordance with the partnership agreement, and the remaining net income or loss allocated with respect to the general partner’s and limited partners’ ownership interests. Diluted net income attributable to common limited partners per unit is calculated by dividing net income (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). 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 March 31,
	2008	2007
Weighted average number of common limited partner units – basic	38,763	13,080
Add: effect of dilutive unit incentive awards⁽¹⁾	—	—

Weighted average number of common limited partner units – diluted	38,763	13,080

⁽¹⁾	For the three months ended March 31, 2008 and 2007, approximately 978,000 and 245,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

For the periods presented in the table above, potential common limited partner units issuable upon conversion of the Partnership’s 40,000 $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 Loss

Comprehensive 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 loss (in thousands):


	Three Months Ended March 31,
	2008			2007
Net income (loss)	$	(45,820	)	$	2,459
Preferred unit dividend effect		(137	)		—
Preferred unit imputed dividend cost		(505	)		(499	)

Net (loss) income attributable to common limited partners and the general partner		(46,462	)		1,960

Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		18,585			(8,668	)
Add: adjustment for realized losses reclassified to net income (loss)		17,643			3,047

Total other comprehensive income (loss)		36,228			(5,621	)

Comprehensive loss	$	(10,234	)	$	(3,661	)

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 or $0.40 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantially all natural gas gathering revenue in the Appalachia segment is derived from these agreements. Fees for transportation services provided to independent third parties whose wells are connected to the Partnership’s Appalachia gathering systems are at separately negotiated prices.

The Partnership’s Mid-Continent segment revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, the Partnership purchases 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 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 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 March 31, 2008 and December 31, 2007 of $99.3 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 6.9% and 8.0% for the three months ended March 31, 2008 and 2007, respectively, and the amount of interest capitalized was $2.0 million and $0.5 million for the three months ended March 31, 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 March 31, 2008 and December 31, 2007 (in thousands):


	March 31, 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	$	(4,613	)	$	(4,215	)
Customer relationships		(17,954	)		(11,964	)

	$	(22,567	)	$	(16,179	)

Net Carrying Amount:
Customer contracts	$	8,197		$	8,595
Customer relationships		204,618			210,608

	$	212,815		$	219,203

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 March 31, 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 2008.

Goodwill

At March 31, 2008 and December 31, 2007, the Partnership had $676.8 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 three months ended March 31, 2008 and 2007 were as follows (in thousands):


	Three Months Ended March 31,
	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		(2,275	)
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		(30,206	)		—

Balance, end of period	$	676,802		$	63,441

During the fourth quarter 2007 and first quarter of 2008, the Partnership adjusted its preliminary purchase price allocation 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. At March 31, 2008, based upon the reimbursement of the sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on its consolidated balance sheet (see Notes 8 and 16). Due to the recent date of the Chaney Dell and Midkiff/Benedum acquisition, the purchase price allocation is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate this allocation. Other items could further adjust amounts allocated to goodwill in future periods, although no such items are currently anticipated by management.

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 March 31, 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 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. 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.

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. 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 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 No. 07-4 requires the calculation of a Master Limited Partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 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 does not believe the adoption of EITF No. 07-4 will have any impact on its financial position or results of operations. The Partnership’s net earnings per limited partner unit calculated under the requirements of EITF No. 03-6 would not have differed under the requirements of EITF No. 07-4.

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 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 an 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 an impact on its financial position and results of operations.

NOTE 3 – COMMON UNIT EQUITY OFFERING

In July 2007, the Partnership sold 25.6 million common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25.6 million common units sold by the Partnership, 3.8 million 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

On March 13, 2006, the Partnership entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. The Partnership also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to the Partnership’s right under the agreement to require Sunlight Capital to purchase such additional units. The preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for the Partnership’s common units. 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 on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for common unit distributions after March 13, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of the Partnership’s common units as of the date of the notice of conversion. The Partnership may elect to pay cash rather than issue common units in satisfaction of a conversion request. The Partnership has the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.22. 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 three months ended June 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 on March 13, 2006 and was amortized in full as of March 12, 2007. As a result of the amended agreement, the Partnership recognized an imputed dividend cost of $2.5 million that was amortized during the year commencing March 13, 2007 and was based upon the present value of the net proceeds received using the 6.5% stated yield. For the three months ending March 31, 2008, the Partnership amortized the remaining $0.5 million of this imputed dividend cost, which is presented as a reduction of net loss to determine net loss attributable to common limited partners and the general partner on its consolidated statements of operations. Amortization of the imputed dividend cost was $0.5 million for the three months ended March 31, 2007, based on the $2.4 million imputed cost during the initial year after the unit issuance.

Sunlight Capital is entitled to receive the dividends on the preferred units pro rata from the March 13, 2008 commencement date through March 31, 2008. The Partnership recognized $0.1 million of preferred dividend cost, which is presented as a reduction of net loss to determine net loss attributable to common limited partners and the general partner on its consolidated statements of operations for dividends earned during the period and to be paid on May 15, 2008, the date of the Partnership’s quarterly cash distribution (see Note 5). If converted to common units, the preferred equity amount converted will be reclassified to common unit equity within partners’ capital on the Partnership’s consolidated balance sheet.

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 March 31, 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

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 April 22, 2008, the Partnership declared a cash distribution of $0.94 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2008. The $44.3 million distribution, including $7.9 million to the General Partner after the allocation of $3.8 million of its incentive distribution rights back to the Partnership, will be paid on May 15, 2008 to unitholders of record at the close of business on May 7, 2008.

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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


	March 31, 2008			December 31, 2007			Estimated Useful Lives In Years
Pipelines, processing and compression facilities	$	1,708,670		$	1,633,454		15 – 40
Rights of way		169,453			168,359		20 – 40
Buildings		8,983			8,919		40
Furniture and equipment		7,788			7,235		3 – 7
Other		15,162			13,307		3 – 10

		1,910,056			1,831,274
Less – accumulated depreciation		(98,027	)		(82,613	)

	$	1,812,029		$	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. Due to the recent date of acquisition, the purchase price allocation is based upon estimated values determined by the Partnership, which are subject to adjustment and could change as it continues to evaluate this allocation. Other items could further adjust amounts allocated to goodwill and property, plant and equipment in future periods, although no such items are currently anticipated by management.

During the three months ended March 31, 2008, the Partnership recognized a charge of $4.0 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. The Partnership also has $4.0 million recorded within prepaid expenses and other on its consolidated balance sheet at March 31, 2008 with regard to a vendor deposit for the manufacture of pipeline which will expire on June 1, 2008 if minimum purchase requirements are not met.

NOTE 7 – OTHER ASSETS

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


	March 31, 2008		December 31, 2007
Deferred finance costs, net of accumulated amortization of $12,031 and $11,352 at March 31, 2008 and December 31, 2007, respectively	$	17,535	$	18,227
Security deposits		2,744		2,498
Other		103		156

	$	20,382	$	20,881

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (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 has reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending 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 an $830.0 million senior secured term loan which matures in July 2014 and a $300.0 million 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 preliminary purchase price allocation as of March 31, 2008, 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		613,362

Total assets acquired		1,854,470
Accounts payable and accrued liabilities		(1,499	)

Net cash paid for acquisition	$	1,852,971

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. At March 31, 2008, based upon the reimbursement of sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with its acquisition and recorded $30.2 million within accounts receivable on its consolidated balance sheet. Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate this allocation. Other items could further adjust the amounts allocated to goodwill, although no such items are currently anticipated by management. 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 months ended March 31, 2008 and 2007, respectively, as if the acquisition discussed above, the equity offering in July 2007 (see Note 3), the issuance of an $830.0 million term loan, its new $300 million senior secured credit facility and respective borrowings under these facilities (see Note 11), and the April 2007 issuance of senior notes (see Note 4) 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 March 31,
	2008			2007
Total revenue and other loss, net	$	303,386		$	261,168
Net loss	$	(45,820	)	$	(9,358	)
Net loss attributable to common limited partners and the general partner	$	(46,462	)	$	(13,598	)
Net loss attributable to common limited partners per unit:
Basic	$	(1.35	)	$	(0.44	)

Diluted	$	(1.35	)	$	(0.43	)

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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

The Partnership formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching derivative contracts to the forecasted transactions. The Partnership assesses, 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 immediately within other income (loss) in its consolidated statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassifies 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 are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss) in its consolidated statements of operations as they occur.

During January 2008, the Partnership entered into interest rate derivative contracts designated as cash flow hedges and having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, the Partnership will pay a weighted average interest rate of 2.88%, plus the applicable margin as defined under the terms of its credit facility (see Note 11), and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of the Partnership’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement began on January 31, 2008 and expires on January 31, 2010.

Derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At March 31, 2008 and December 31, 2007, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $268.1 million and $229.5 million, respectively. Of the $25.8 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at March 31, 2008, if the fair values of the instruments remain at current market values, the Partnership will reclassify $9.6 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $8.2 million of losses to natural gas and liquids revenue and $1.4 million of losses to interest expense. Aggregate losses of $16.2 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of $15.4 million to natural gas and liquids revenue and $0.8 million 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.

In connection with the Chaney Dell and Midkiff/Benedum acquisition, the Partnership reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and 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) (see Note 8). At March 31, 2008, the Partnership has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, the Partnership will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production the Partnership may have.

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


	Three Months Ended March 31,
	2008			2007
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(17,643	)	$	(3,047	)
Loss from change in market value of non-qualifying derivatives⁽²⁾		(71,196	)		(1,302	)
Loss from change in market value of ineffective portion of qualifying derivatives⁽²⁾		(5,660	)		(975	)
Loss from cash settlement of non-qualifying derivatives⁽²⁾		(11,925	)		—

(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.

As of March 31, 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 Liability⁽¹⁾
					(in thousands)
January 2008 - January 2010	$	200,000,000	Pay 2.88%—Receive LIBOR	2008	$	(973	)
				2009		(1,161	)
				2010		(15	)

					$	(2,149	)

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	23,940,000	$	0.697	$	(13,911	)
2009	8,568,000	$	0.746		(4,574	)

				$	(18,485	)

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	3,517,200	240,141,888	$	60.00	$	359		Puts purchased
2008	3,517,200	240,141,888	$	79.08		(69,908	)	Calls sold
2009	5,184,000	354,533,760	$	60.00		3,999		Puts purchased
2009	5,184,000	354,533,760	$	78.88		(101,264	)	Calls sold
2010	3,127,500	213,088,050	$	61.08		5,325		Puts purchased
2010	3,127,500	213,088,050	$	81.09		(58,437	)	Calls sold
2011	606,000	34,869,240	$	70.59		3,057		Puts purchased
2011	606,000	34,869,240	$	95.56		(7,655	)	Calls sold
2012	450,000	25,893,000	$	70.80		2,636		Puts purchased
2012	450,000	25,893,000	$	97.10		(5,719	)	Calls sold

					$	(227,607	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2008	4,113,000	$	8.804	$	(6,161	)
2009	5,724,000	$	8.611		(6,491	)
2010	4,560,000	$	8.526		(2,570	)
2011	2,160,000	$	8.270		(1,064	)
2012	1,560,000	$	8.250		(733	)

				$	(17,019	)

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	4,113,000	$	(0.732	)	$	592
2009	5,724,000	$	(0.558	)		1,674
2010	4,560,000	$	(0.622	)		763
2011	2,160,000	$	(0.664	)		196
2012	1,560,000	$	(0.601	)		81

					$	3,306

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	12,195,000	$	8.978	⁽⁵⁾	$	16,358
2009	15,564,000	$	8.680			16,570
2010	8,940,000	$	8.580			5,277
2011	2,160,000	$	8.270			1,064
2012	1,560,000	$	8.250			733

					$	40,002

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	12,195,000	$	(1.114	)	$	(2,732	)
2009	15,564,000	$	(0.654	)		(8,222	)
2010	8,940,000	$	(0.600	)		(4,227	)
2011	2,160,000	$	(0.700	)		(221	)
2012	1,560,000	$	(0.610	)		(55	)

					$	(15,457	)

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2008	45,300	$	59.664	$	(1,821	)
2009	33,000	$	62.700		(1,103	)

				$	(2,924	)

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	204,900	$	60.000	$	(31	)	Puts purchased
2008	204,900	$	78.128		(9,481	)	Calls sold
2009	306,000	$	60.000		735		Puts purchased
2009	306,000	$	80.017		(11,235	)	Calls sold
2010	234,000	$	61.795		816		Puts purchased
2010	234,000	$	83.027		(6,956	)	Calls sold
2011	30,000	$	60.000		296		Puts purchased
2011	30,000	$	74.500		(1,211	)	Calls sold
2012	30,000	$	60.000		209		Puts purchased
2012	30,000	$	73.900		(908	)	Calls sold

				$	(27,766	)

			Total net liability	$	(268,099	)

⁽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⁾	Mmbtu represents million British Thermal Units.

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

NOTE 10 – 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 March 31, 2008 (in thousands):


	Level 1		Level 2			Level 3			Total
Commodity–based derivatives	$	—	$	7,907		$	(273,857	)	$	(265,950	)
Interest rate swap–based derivatives		—		(2,149	)		—			(2,149	)

Total	$	—	$	5,758		$	(273,857	)	$	(268,099	)

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 March 31, 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	)
Cash settlements from unrealized gain⁽¹⁾		804			2,025			9,847			12,676
Cash settlements from other comprehensive income (loss)⁽¹⁾		13,300			1,139			(139	)		14,300
Net change in unrealized gain (loss) ⁽² ⁾		(98	)		92			(87,936	)		(87,942	)
Net change in other comprehensive income (loss)		1,133			(6,282	)		(3,960	)		(9,109	)

Balance – March 31, 2008	$	(18,485	)	$	(27,766	)	$	(227,607	)	$	(273,857	)

(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):


	March 31, 2008			December 31, 2007
Revolving credit facility	$	165,000		$	105,000
Term loan		830,000			830,000
Senior notes		294,365			294,392
Other debt		26			34

Total debt		1,289,391			1,229,426
Less current maturities		(26	)		(34	)

Total long term debt	$	1,289,365		$	1,229,392

Term Loan and Credit Facility

In connection with the Partnership’s July 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 8), it entered into a new credit facility, comprised of an $830.0 million senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. Borrowings under the credit

facility bear interest, at 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 March 31, 2008 was 4.9%, and the weighted average interest rate on the outstanding term loan borrowings at March 31, 2008 was 5.5%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $14.0 million was outstanding at March 31, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnership’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of its consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on the Partnership’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. The Partnership is in compliance with these covenants as of March 31, 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.

The events which constitute an event of default for the Partnership’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against the Partnership in excess of a specified amount, and a change of control of the Partnership’s General Partner. The credit facility requires the Partnership to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of March 31, 2008, the Partnership’s ratio of funded debt to EBITDA was 4.6 to 1.0 and its interest coverage ratio was 3.4 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 March 31, 2008, the Partnership has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, prior to December 15, 2008, the Partnership may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Partnership at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under its Credit Facility.

The indenture governing the Senior Notes contains covenants, including limitations of the Partnership’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Partnership is in compliance with these covenants as of March 31, 2008.

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 March 31, 2008, the Partnership is committed to expend approximately $163.8 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 March 31, 2008.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the Committee, cash equivalent to the fair market value of a common unit. In addition, the Committee may grant a participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase the Partnership’s common limited partner units at an exercise price determined by the Committee at its discretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of the General Partner, the Committee will determine the vesting period for phantom units and the exercise period for options. Through March 31, 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 March 31, 2008, 69,519 units will vest within the following twelve months. All units outstanding under the LTIP at March 31, 2008 include DERs granted to the participants by the Committee. The amounts paid with respect to DERs were $0.1 million for both the three month periods ended March 31, 2008 and 2007. 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 March 31,
	2008			2007
Outstanding, beginning of period		129,746			159,067
Granted⁽¹⁾		53,951			24,792
Matured		(11,860	)		—
Forfeited		(750	)		—

Outstanding, end of period		171,087			183,859

Non-cash compensation expense recognized (in thousands)	$	486		$	901

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $44.44 and $50.10 for awards granted for the three months ended March 31, 2008 and 2007, respectively.

At March 31, 2008, the Partnership had approximately $4.1 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 compensation expense (income) of ($3.3) million and $0.9 million for the three months ended March 31, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized for these awards as a result of a decrease in our common unit market price at March 31, 2008 when compared with the December 31, 2007 price, which is utilized in the estimation of the non-cash compensation expense for these awards. 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 March 31, 2008, 928,939 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 $1.1 million and $0.6 million for the three months ended March 31, 2008 and 2007, respectively, for compensation and benefits related to their executive officers. For the three months ended March 31, 2008 and 2007, direct reimbursements were $9.4 million and $6.0 million, 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 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 March 31,
	2008			2007
Mid-Continent
Revenue:
Natural gas and liquids	$	365,159		$	102,176
Transportation, compression and other fees		14,615			9,819
Other loss, net		(86,865	)		(2,279	)

Total revenue and other loss, net		292,909			109,716

Costs and expenses:
Natural gas and liquids		276,182			87,810
Plant operating		14,935			4,530
Transportation and compression		1,498			1,720
General and administrative		2,530			3,894
Depreciation and amortization		24,443			5,460
Minority interest		2,090			—

Total costs and expenses		321,678			103,414

Segment profit (loss)	$	(28,769	)	$	6,302

Appalachia
Revenue:
Natural gas and liquids	$	960		$	—
Transportation, compression and other fees – affiliates		9,159			7,720
Transportation, compression and other fees – third parties		247			19
Other income		111			82

Total revenue and other income		10,477			7,821

Costs and expenses:
Natural gas and liquids		482			—
Transportation and compression		2,314			1,392
General and administrative		1,484			1,220
Depreciation and amortization		1,382			1,074

Total costs and expenses		5,662			3,686

Segment profit	$	4,815		$	4,135

Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent	$	(28,769	)	$	6,302
Appalachia		4,815			4,135

Total segment profit (loss)		(23,954	)		10,437
Corporate general and administrative expenses		(1,485	)		(1,219	)
Interest expense		(20,381	)		(6,759	)

Net income (loss)	$	(45,820	)	$	2,459

Capital Expenditures:
Mid-Continent	$	69,683		$	13,841
Appalachia		14,386			2,788

	$	84,069		$	16,629


	March 31, 2008		December 31, 2007
Balance sheet
Total assets:
Mid-Continent	$	2,873,378	$	2,813,049
Appalachia		50,213		43,860
Corporate other		19,308		20,705

	$	2,942,899	$	2,877,614

Goodwill:
Mid-Continent	$	674,497	$	706,978
Appalachia		2,305		2,305

	$	676,802	$	709,283

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


	Three Months Ended March 31,
	2008		2007
Natural gas and liquids:
Natural gas	$	139,783	$	46,763
NGLs		198,693		46,773
Condensate		12,680		2,588
Other ⁽¹⁾		14,963		6,052

Total	$	366,119	$	102,176

Transportation, compression and other fees:
Affiliates	$	9,159	$	7,720
Third parties		14,862		9,838

Total	$	24,021	$	17,558

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

NOTE 16 – SUBSEQUENT EVENTS

During April 2008, the Partnership entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, the Partnership will pay a weighted average interest rate of 3.14%, plus the applicable margin as defined under the terms of its credit facility (see Note 11) and will receive LIBOR plus the applicable margin, on the notional principal amount of $250.0 million. This derivative effectively converts $250.0 million of the Partnership’s floating rate debt under the term loan and revolving credit facility to fixed-rate debt. The interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

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. At March 31, 2008, based upon the recovery of the sales tax paid in April 2008, the Partnership has reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on its consolidated balance sheet.

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, Golden Trend and Permian Basins in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, we are a leading provider of natural gas processing and treatment services in Oklahoma and Texas. We also provide interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. Our business is conducted in the midstream segment of the natural gas industry through two 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 natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

•

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

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 Acquisition

From the date of our initial public offering in January 2000 through March 2008, we have completed seven acquisitions at an aggregate cost of approximately $2.4 billion, including:

•

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. 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 will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending 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. 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 an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see “—Term Loan and Credit Facility”).

Subsequent Events

During April 2008, we entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, we will pay a weighted average interest rate of 3.14%, plus the applicable margin as defined under the terms of our credit facility (see Note 11 under Item 1, “Financial Statements”), and will receive LIBOR plus the applicable margin, on the notional principal amount of $250.0 million. This derivative effectively converts $250.0 million of our floating rate debt under the term loan and revolving credit facility to fixed-rate debt. The interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

In April 2008, we received a $30.2 million cash reimbursement for sales tax initially paid on our 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. At March 31, 2008, based upon the recovery of the sales tax paid in April 2008, we have reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on our consolidated balance sheet.

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 or $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 would result in a change to our gross margin for the twelve-month period ending March 31, 2009 of approximately $1.7 million.

Results of Operations

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


	Three Months Ended March 31,
	2008	2007
Operating data⁽¹⁾:
Appalachia:
Average throughput volumes (mcfd)	75,632	62,532
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)	62,400	61,017
Processed gas volume (mcfd)	59,867	58,508
Residue gas volume (mcfd)	47,138	45,689
NGL volume (bpd)	6,688	6,247
Condensate volume (bpd)	254	200
Elk City/Sweetwater system:
Gathered gas volume (mcfd)	305,377	287,892
Processed gas volume (mcfd)	236,403	207,253
Residue gas volume (mcfd)	213,130	190,940
NGL volume (bpd)	10,677	8,515
Condensate volume (bpd)	363	322
Chaney Dell system:
Gathered gas volume (mcfd)	251,487	—
Processed gas volume (mcfd)	247,861	—
Residue gas volume (mcfd)	220,194	—
NGL volume (bpd)	12,401	—
Condensate volume (bpd)	707	—
Midkiff/Benedum system:
Gathered gas volume (mcfd)	142,542	—
Processed gas volume (mcfd)	136,654	—
Residue gas volume (mcfd)	96,612	—
NGL volume (bpd)	20,349	—
Condensate volume (bpd)	720	—
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)	390,293	286,891

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

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Revenue. Natural gas and liquids revenue was $366.1 million for the three months ended March 31, 2008, an increase of $263.9 million from $102.2 million for the three months ended March 31, 2007. The increase was primarily attributable to revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which we acquired in July 2007, of $223.2 million, an increase of $21.4 million from the Elk City/Sweetwater system due primarily to an increase in plant utilization at the Sweetwater processing plant, an increase of $17.0 million from the Velma system due primarily to an increase in volumes, and an increase of $1.5 million from the NOARK system due primarily to an increase in volumes. Processed natural gas volume on the Chaney Dell system was 247.9 MMcfd for the three months ended March 31, 2008, while the Midkiff/Benedum system had processed natural gas volume of 136.7 MMcfd for the same period. Processed natural gas volume on the Elk City/Sweetwater system averaged 236.4 MMcfd for the three months ended March 31, 2008, an increase of 14.1% from the comparable prior year period. Processed natural gas volume averaged 59.9 MMcfd on the Velma system for the three months ended March 31, 2008, an increase of 2.3% from the comparable prior year period. 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 $24.0 million for the three months ended March 31, 2008 compared with $17.6 million for the prior year comparable period. This $6.4 million increase was primarily due to an increase of $1.4 million from the transportation revenues associated with the NOARK system, $2.4 million of contributions from the Chaney Dell and Midkiff/Benedum systems, a $1.7 million increase from the Appalachia system and a $1.0 million increase associated with the Elk City/Sweetwater system. For the NOARK system, average Ozark Gas Transmission volume was 390.3 MMcfd for the three months ended March 31, 2008, an increase of 36.0% from the prior year comparable period. The Appalachia system’s average throughput volume was 75.6 MMcfd for the three months ended March 31, 2008 as compared with 62.5 MMcfd for the three months ended March 31, 2007, an increase of 13.1 MMcfd or 20.9%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system and the acquisition of a processing plant and gathering system in August 2007.

Other loss, net, including the impact of non-cash gains and losses recognized on derivatives, was $86.8 million for the three months ended March 31, 2008, an unfavorable movement of $84.6 million from the prior year comparable period. This unfavorable movement was due primarily to a $76.9 million non-cash derivative loss for the three months ended March 31, 2008 compared with a $2.3 million non-cash derivative loss for the prior year comparable period, an unfavorable movement of $74.6 million, and $11.9 million of cash settlements of non-qualified derivatives. The $74.6 million change in non-cash derivatives was the result of commodity price movements and their unfavorable impact on derivative contracts we have for production volumes in future periods. The $76.9 million of non-cash derivative losses during the current year period were principally the result of forward crude oil prices for the duration of our derivative contracts, increasing from an average price of $89.89 per barrel at December 31, 2007 to $96.94 per barrel at March 31, 2008, an increase of $7.05. Forward crude oil prices are the basis for adjusting the fair value of our derivative contracts. 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 $276.7 million and plant operating expenses of $14.9 million for the three months ended March 31, 2008 represented increases of $188.9 million and $10.4 million, respectively, from the comparable prior year amounts due primarily to the contribution from the Chaney Dell and Midkiff/Benedum acquisition and an increase in gathered and processed natural gas volumes on the Elk City/Sweetwater system, which includes contributions from the Sweetwater processing facility, and Velma system. Transportation and compression expenses increased $0.7 million to $3.8 million for the three months ended March 31, 2008 due to an increase of $0.9 million in the Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections partially offset by a decrease of $0.2 million in the NOARK system operating and maintenance costs.

General and administrative expenses, including amounts reimbursed to affiliates, decreased $0.8 million to $5.5 million for the three months ended March 31, 2008 compared with $6.3 million for the prior year comparable period. This decrease was primarily related to a $4.6 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. The decrease in non-cash compensation expense was principally attributable to a 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. The mark-to-market gain was the result of a decrease in our common unit market price at March 31, 2008 when compared with the December 31, 2007 price, which is utilized in the estimate of the non-cash compensation expense for these awards.

Depreciation and amortization increased to $25.8 million for the three months ended March 31, 2008 compared with $6.5 million for the three months ended March 31, 2007 due primarily to the depreciation associated with our Chaney Dell and Midkiff/Benedum acquired assets, our expansion capital expenditures incurred subsequent to March 31, 2007 and a $4.0 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 $20.4 million for the three months ended March 31, 2008 as compared with $6.8 million for the comparable prior year period. This $13.6 million increase was primarily due to interest associated with the $830.0 million term loan issued in connection with our acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Term Loan and Credit Facility”) and additional borrowings under the credit facility to finance our expansion capital expenditures.

Minority interest expense of $2.1 million for the three months ended March 31, 2008 represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems.

Liquidity and Capital Resources

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

•

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

•

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

•

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

At March 31, 2008, we had $165.0 million outstanding under our $300.0 million senior secured credit facility and $14.0 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $121.0 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 $352.1 million remains available at March 31, 2008. At March 31, 2008, we had a working capital deficit of $57.6 million compared with a $78.2 million working capital deficit at December 31, 2007. This increase in working capital was primarily due to an increase in our accounts receivable as a result of the receipt of a $30.2 million reimbursement in April 2008 for state sales tax paid in connection with the Chaney Dell and Midkiff/Benedum acquisition (see Notes 8 and 16 under Item 1, “Financial Statements”). 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 – Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Net cash provided by operating activities of $54.9 million for the three months ended March 31, 2008 represented an increase of $37.6 million from $17.3 million for the comparable prior year period. The increase was derived principally from a $41.1 million increase in net income excluding non-cash charges, partially offset by a $3.1 million decrease in cash flows from working capital changes. This increase in net income excluding non-cash charges was principally due to the contributions from the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007. The non-cash charges which impacted net income include a $72.5 million movement in non-cash derivative losses, a $19.3 million increase in depreciation and amortization, and $2.1 million of minority interest expense, partially offset by a $4.6 million decrease in non-cash compensation expense. The movement in non-cash derivative losses resulted from commodity price movements and their unfavorable impact on the fair value of derivative contracts we have for future periods. The increase in depreciation and amortization and minority interest expense 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 first quarter 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 March 31, 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 $83.0 million for the three months ended March 31, 2008, an increase of $66.5 million from $16.5 million for the comparable prior year period. This increase was principally due to a $67.4 million increase in capital expenditures, partially offset by a receipt of $1.3 million in connection with a post-closing purchase price adjustment of 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 $18.7 million for the three months ended March 31, 2008, an increase of $19.4 million from net cash used in financing activities of $0.7 million for the comparable prior year period. This increase was principally due to a $45.0 million net increase in borrowings under our revolving credit facility. This amount was partially offset by a $25.7 million increase in cash distributions to common limited partners and the general partner.

Capital Requirements

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

•

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

•

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

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


	Three Months Ended March 31,
	2008		2007
Maintenance capital expenditures	$	1,619	$	772
Expansion capital expenditures		82,450		15,857

Total	$	84,069	$	16,629

Expansion capital expenditures increased to $82.5 million for the three months ended March 31, 2008 compared with $15.9 million for the prior year first quarter due principally to the construction of a 60 MMcfd expansion of our Sweetwater processing plant and the acquisition of a gathering system located in Tennessee with an approximate capacity of 20.0 MMcfd for $9.1 million. The increase in expansion capital expenditures also includes expansions of our existing gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in our service areas. Maintenance capital expenditures for the three months ended March 31, 2008 increased to $1.6 million compared with $0.8 million for the prior year first quarter 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 March 31, 2008, we are committed to expend approximately $163.8 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 “—Recent Acqusition”). 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 $10.8 million of incentive distributions declared for the three months ended March 31, 2008, the general partner received $7.0 million after the allocation of $3.8 million of its incentive distribution rights back to us.

Common Equity Offering

In July 2007, we sold 25.6 million common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25.6 million common units sold, 3.8 million common units were purchased by AHD for $168.8 million. We also received a capital contribution from AHD of $23.1 million 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 “—Recent Acquisition”).

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 March 31, 2008, $352.1 million remains available for issuance under the shelf registration statement. However, the amount, type and timing of any offerings will depend upon, among other things, our funding requirements, prevailing market conditions, and compliance with our credit facility covenants.

Private Placement of Convertible Preferred Units

On March 13, 2006, we entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. We also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to our right under the agreement to require Sunlight Capital to purchase such additional units. The preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date 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 on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for common unit distributions after March 13, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of our common units as of the date of the notice of conversion. We may elect to pay cash rather than issue common units in satisfaction of a conversion request. We have the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.22. 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 4under 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 three months ended June 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 our consolidated statements of operations.

Sunlight Capital is entitled to receive the dividends on the preferred units pro rata from the March 13, 2008 commencement date through March 31, 2008. Dividends 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 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

We have a credit facility comprised of an $830.0 million senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. Borrowings under the credit facility bear interest, at our option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at March 31, 2008 was 4.9%, and the weighted average interest rate on the outstanding term loan borrowings at March 31, 2008 was 5.5%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $14.0 million was outstanding at March 31, 2008. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of our property and that of our subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of our consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are in compliance with these covenants as of March 31, 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.

The events which constitute an event of default for our credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against us in excess of a specified amount, and a change of control of our general partner. The credit facility requires us to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of March 31, 2008, our ratio of funded debt to EBITDA was 4.6 to 1.0 and our interest coverage ratio was 3.4 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 March 31, 2008, we have $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, prior to December 15, 2008, we may redeem up to 35% of the aggregate principal amount of the

Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under our credit facility.

The indenture governing the Senior Notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. We are in compliance with these covenants as of March 31, 2008.

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, 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 March 31, 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.

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

We 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 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 No. 07-4 requires the calculation of a Master Limited Partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. We do not believe the adoption of EITF No. 07-4 will have any impact on our financial position or results of operations. Our net earnings per limited partner unit calculated under the requirements of EITF No. 03-6 would not have differed under the requirements of EITF No. 07-4.

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 an 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 an impact on our financial position and results of operations.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and 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 March 31, 2008. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At March 31, 2008, we had a $300.0 million senior secured revolving credit facility ($165.0 million outstanding). We also had an $830.0 million senior secured term loan outstanding at March 31, 2008. The weighted average interest rate for the revolving credit facility borrowings was 4.9% at March 31, 2008, and the weighted average interest rate for the term loan borrowings was 5.5% at March 31, 2008.

During January 2008, we entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, we will pay a weighted average interest rate of 2.88%, plus the applicable margin as defined under the terms of our credit facility, (see Note 11 under Item 1, “Financial Statements”), and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of our floating rate debt under the credit facility to fixed-rate debt. Realized gains and losses on the effective component of interest rate derivative contracts are reported within interest expense on our consolidated statements of operations. The interest rate swap agreement began on January 31, 2008 and expires on January 31, 2010. In April 2008, we entered into an additional $250.0 million of interest rate derivative contracts beginning on April 30, 2008 and expiring on April 30, 2010. Under the terms of this agreement, we will pay a weighted average interest rate of 3.14%, plus the applicable margin as defined under the terms of our credit facility, on the notional principal amount of $250.0 million.

Holding all other variables constant, including the effect of interest rate derivatives entered into subsequent to March 31, 2008, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by $5.5 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 would result in a change to our gross margin for the twelve-month period ending March 31, 2009 of approximately $1.7 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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the derivative contracts to the forecasted transactions. We 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 immediately within other income (loss) in our consolidated statements of operations. For derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassify 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 are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within other income (loss) in our consolidated statements of operations as they occur.

In connection with the Chaney Dell and Midkiff/Benedum acquisition, we reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008 and 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; see Note 8 under Item 1, “Financial Statements”). At March 31, 2008, we have received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, we will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and we will evaluate these derivative instruments to determine if they can be documented to match other forecasted production we may have.

As of March 31, 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 Liability⁽¹⁾
					(in thousands)
January 2008 - January 2010	$	200,000,000	Pay 2.88%—Receive LIBOR	2008	$	(973	)
				2009		(1,161	)
				2010		(15	)

					$	(2,149	)

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	23,940,000	$	0.697	$	(13,911	)
2009	8,568,000	$	0.746		(4,574	)

				$	(18,485	)

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	3,517,200	240,141,888	$	60.00	$	359		Puts purchased
2008	3,517,200	240,141,888	$	79.08		(69,908	)	Calls sold
2009	5,184,000	354,533,760	$	60.00		3,999		Puts purchased
2009	5,184,000	354,533,760	$	78.88		(101,264	)	Calls sold
2010	3,127,500	213,088,050	$	61.08		5,325		Puts purchased
2010	3,127,500	213,088,050	$	81.09		(58,437	)	Calls sold
2011	606,000	34,869,240	$	70.59		3,057		Puts purchased
2011	606,000	34,869,240	$	95.56		(7,655	)	Calls sold
2012	450,000	25,893,000	$	70.80		2,636		Puts purchased
2012	450,000	25,893,000	$	97.10		(5,719	)	Calls sold

					$	(227,607	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2008	4,113,000	$	8.804	$	(6,161	)
2009	5,724,000	$	8.611		(6,491	)
2010	4,560,000	$	8.526		(2,570	)
2011	2,160,000	$	8.270		(1,064	)
2012	1,560,000	$	8.250		(733	)

				$	(17,019	)

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	4,113,000	$	(0.732	)	$	592
2009	5,724,000	$	(0.558	)		1,674
2010	4,560,000	$	(0.622	)		763
2011	2,160,000	$	(0.664	)		196
2012	1,560,000	$	(0.601	)		81

					$	3,306

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	12,195,000	$	8.978	⁽⁵⁾	$	16,358
2009	15,564,000	$	8.680			16,570
2010	8,940,000	$	8.580			5,277
2011	2,160,000	$	8.270			1,064
2012	1,560,000	$	8.250			733

					$	40,002

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾			(in thousands)
2008	12,195,000	$	(1.114	)	$	(2,732	)
2009	15,564,000	$	(0.654	)		(8,222	)
2010	8,940,000	$	(0.600	)		(4,227	)
2011	2,160,000	$	(0.700	)		(221	)
2012	1,560,000	$	(0.610	)		(55	)

					$	(15,457	)

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2008	45,300	$	59.664	$	(1,821	)
2009	33,000	$	62.700		(1,103	)

				$	(2,924	)

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)
2008	204,900	$	60.000	$	(31	)	Puts purchased
2008	204,900	$	78.128		(9,481	)	Calls sold
2009	306,000	$	60.000		735		Puts purchased
2009	306,000	$	80.017		(11,235	)	Calls sold
2010	234,000	$	61.795		816		Puts purchased
2010	234,000	$	83.027		(6,956	)	Calls sold
2011	30,000	$	60.000		296		Puts purchased
2011	30,000	$	74.500		(1,211	)	Calls sold
2012	30,000	$	60.000		209		Puts purchased
2012	30,000	$	73.900		(908	)	Calls sold

				$	(27,766	)

			Total net liability	$	(268,099	)

⁽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⁾	Mmbtu represents million British Thermal Units.

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

ITEM 4.

CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at the reasonable assurance level at March 31, 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

There have been no material changes in our risk factors from those disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007.

ITEM 6.

EXHIBITS


Exhibit No.		Description
3.1		Certificate of Limited Partnership⁽³⁾

3.2		Second Amended and Restated Agreement of Limited Partnership⁽⁴⁾

3.2(a)		Amendment No. 1 to Second Amendment and Restated Agreement of Limited Partnership⁽⁵⁾

3.2(b)		Amendment No. 1 to Second Amendment and Restated Agreement of Limited Partnership⁽²⁾

3.3		Certificate of Designation of 6.5% Cumulative Convertible Preferred Units⁽⁶⁾

3.3(a)		Amended and Restated Certificate of Designation⁽⁷⁾

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 current report on Form 8-K on June 5, 2007.

⁽²⁾	Previously filed as an exhibit to current report on Form 8-K on July 30, 2007.

⁽³⁾	Previously filed as an exhibit to registration statement on Form S-1 on January 20, 2000.

⁽⁴⁾	Previously filed as an exhibit to registration statement on Form S-3 on April 2, 2004.

⁽⁵⁾	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2007.

⁽⁶⁾	Previously filed as an exhibit to current report on Form 8-K on March 14, 2006.

⁽⁷⁾	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: May 8, 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: May 8, 2008	By:	/s/ MICHAEL L. STAINES
		Michael L. Staines
		President, Chief Operating Officer and Managing Board Member of the General Partner

Date: May 8, 2008	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer of the General Partner

Date: May 8, 2008	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer of the General Partner