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

OR

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

For the transition period from              to             

Commission file number: 1-32953

ATLAS PIPELINE HOLDINGS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant 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 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 HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

			PAGE
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements
		Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007 (Unaudited)	3
		Consolidated Statements of Operations for the Three Months Ended March 31, 2008 (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 Financial Statements (Unaudited)	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
	Item 4.	Controls and Procedures	54
PART II. OTHER INFORMATION
	Item 1A.	Risk Factors	54
	Item 6.	Exhibits	54
SIGNATURES			56

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	March 31, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	2,968		$	12,129
Accounts receivable - affiliates		6,752			2,839
Accounts receivable		192,229			147,360
Prepaid expenses and other		18,344			14,755
Total current assets		220,293			177,083
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		20,592			21,121
	$	2,943,017		$	2,877,514
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	26		$	34
Accounts payable		19,431			20,530
Accrued liabilities		40,509			43,658
Current portion of derivative liability		113,504			110,867
Accrued producer liabilities		104,757			80,698
Total current liabilities		278,227			255,787
Long-term derivative liability		154,595			118,646
Long-term debt, less current portion		1,314,365			1,254,392
Other long-term liabilities		644			—
Minority interest in Atlas Pipeline Partners, L.P.		1,105,755			1,154,571
Commitments and contingencies
Partners’ capital:
Common limited partners’ interests		90,251			101,785
Accumulated other comprehensive loss		(820	)		(7,667	)
Total partners’ capital		89,431			94,118
	$	2,943,017		$	2,877,514

See accompanying notes to consolidated financial statements

3

ATLAS PIPELINE HOLDINGS, 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		(86,750	)		(2,190	)
Total revenue and other loss, net		303,390			117,544
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		5,277			6,568
Compensation reimbursement – affiliates		1,129			630
Depreciation and amortization		25,825			6,534
Interest		20,822			6,846
Minority interest		2,090			—
Minority interest in Atlas Pipeline Partners, L.P.		(44,344	)		(1,149	)
Total costs and expenses		306,210			114,881
Net income (loss)	$	(2,820	)	$	2,663
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.10	)	$	0.13
Diluted	$	(0.10	)	$	0.13
Weighted average common limited partner units outstanding:
Basic		27,350			21,100
Diluted		27,350			21,123

See accompanying notes to consolidated financial statements

4

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED MARCH 31, 2008

(in thousands, except unit data)

(Unaudited)

	Common Limited Partners’ Capital				Accumulated Other Comprehensive Loss			Total Partners’ Capital
	Units	$
Balance at January 1, 2008	27,350,370	$	101,785		$	(7,667	)	$	94,118
Issuance of common units	—		(8	)		—			(8	)
Unissued common units under incentive plans	—		668			—			668
Distributions paid to common limited partners	—		(9,299	)		—			(9,299	)
Distribution equivalent rights paid on unissued units under incentive plans	—		(75	)		—			(75	)
Other comprehensive income	—		—			6,847			6,847
Net loss	—		(2,820	)		—			(2,820	)
Balance at March 31, 2008	27,350,370	$	90,251		$	(820	)	$	89,431

See accompanying notes to consolidated financial statements

5

ATLAS PIPELINE HOLDINGS, 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)	$	(2,820	)	$	2,663
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Minority interest in net income (loss) of Atlas Pipeline Partners, L.P		(44,344	)		(1,149	)
Distributions paid to minority interest limited partners in Atlas Pipeline Partners, L.P.		(30,958	)		(9,838	)
Depreciation and amortization		25,825			6,534
Non-cash loss on derivative value		74,814			2,277
Non-cash compensation expense (income)		(2,127	)		2,435
Amortization of deferred finance costs		709			558
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		(17,507	)		5,243
Accounts payable and accrued liabilities		22,157			(4,384	)
Accounts payable and accounts receivable – affiliates		(3,913	)		2,375
Net cash provided by operating activities		23,381			6,714
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition purchase price adjustment		1,281			—
Capital expenditures		(84,069	)		(16,629	)
Other		(251	)		86
Net cash used in investing activities		(83,039	)		(16,543	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Pipeline Partners, L.P. credit facility		75,000			60,500
Repayments under Atlas Pipeline Partners, L.P. credit facility		(15,000	)		(45,500	)
Distributions paid to common limited partners		(9,299	)		(5,275	)
Other		(204	)		(155	)
Net cash provided by financing activities		50,497			9,570
Net change in cash and cash equivalents		(9,161	)		(259	)
Cash and cash equivalents, beginning of period		12,129			2,198
Cash and cash equivalents, end of period	$	2,968		$	1,939

See accompanying notes to consolidated financial statements

6

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2008

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or the “Partnership”) is a publicly-traded Delaware limited partnership (NYSE: AHD). The Partnership’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or “General Partner”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”), which does not have an economic interest in the Partnership and is not entitled to receive any distributions from the Partnership, manages the operations and activities of the Partnership and owes a fiduciary duty to the Partnership’s common unitholders. At March 31, 2008, the Partnership had 27,350,370 common limited partnership units outstanding.

The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which owns:

• a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

• all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), Atlas Pipeline GP agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter; and

• 5,476,253 common units of APL, representing approximately 14.1% of the 38,769,939 outstanding common limited partnership units of APL.

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

Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), owns 100% of Atlas Pipeline Holdings GP, the general partner of the Partnership, and a 64.0% ownership interest in the Partnership at March 31, 2008. In addition to its ownership interest in the Partnership, Atlas America also had a 49.4% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN) focused on the development of natural gas and oil in the Appalachian basin. Substantially all of the natural gas APL 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

7

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 General Partner, APL, the Operating Partnership and the Operating Partnership’s subsidiaries. APL’s limited partner equity interests owned by third-parties at March 31, 2008 and December 31, 2007 are reflected as minority interest in APL on the Partnership’s consolidated balance sheets. All material intercompany transactions have been eliminated.

The consolidated financial statements also include the operations of APL’s Chaney Dell natural gas gathering system and processing plants located in Oklahoma (“Chaney Dell system”) and APL’s Midkiff/Benedum natural gas gathering system and processing plants located in Texas (“Midkiff/Benedum system”). In July 2007, APL 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 9). The transaction was effected by the formation of two joint venture companies which own the respective systems, of which APL has a 95% interest and Anadarko has a 5% interest in each. APL 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 APL’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 costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including the fair value of APL’s derivative instruments, the probability of forecasted transactions, the Partnership’s and APL’s stock compensation and the purchase price allocation for APL’s 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.

8

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) per unit is computed by dividing net income (loss) attributable to common limited partners by the weighted average number of common limited partner units outstanding during the period. Diluted net income (loss) 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 or unit option awards, as calculated by the treasury stock method. Phantom units and unit options consist of common units issuable under the terms of the Partnership’s long-term incentive plan (see Note 14). The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) per unit with those used to compute diluted net income (loss) per unit (in thousands):

	Three Months Ended March 31,
	2008	2007
Weighted average number of common limited partner units – basic	27,350	21,100
Add: effect of dilutive unit incentive awards(1)	—	23
Weighted average number of common limited partner units – diluted	27,350	21,123

⁽¹⁾ For the three months ended March 31, 2008 approximately 585,000 phantom units were excluded from the computation of diluted net income (loss) per unit because the inclusion of such units would have been anti-dilutive.

Minority Interest in Atlas Pipeline Partners, L.P.

The minority interest in APL on the Partnership’s consolidated financial statements reflect the outside ownership interests in APL, which was 84.5% at both March 31, 2008 and December 31, 2007. The minority interests in APL in the Partnership’s consolidated statements of operations is calculated quarterly by multiplying (i) the weighted average APL common limited partner units outstanding held by non-affiliated third parties by (ii) the consolidated net income (loss) per APL common limited partner unit for the respective quarter. The net income (loss) per APL common limited partner unit is calculated by dividing the net income (loss) allocated to common limited partners, after the allocation of net income (loss) to the Partnership as general partner in accordance with the terms of the APL partnership agreement, by the total weighted average APL common limited partner units outstanding. The Partnership’s general partner interest in the net income (loss) of APL is based upon its 2% general partner ownership interest and incentive distributions, with a priority allocation of APL’s net income (loss) in an amount equal to the incentive distributions (see Note 6), in accordance with the APL partnership agreement, and the remaining APL net income (loss) allocated with respect to the general partner’s and APL’s limited partners’ ownership interests. The minority interest in APL liability on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL consolidated net income (loss) to the minority interest in APL and the contributed capital of minority interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the minority interest owners.

9

A portion of the funding raised by APL was contributed by the Partnership through the purchase of 3.8 million APL common limited partner units for $168.8 million. Pursuant to Securities and Exchange Commission Staff Accounting Bulletin (“SAB”) No. 51, “Accounting for Sales of Stock by a Subsidiary”, the Partnership recorded a premium of $34.3 million as a reduction of its limited partners’ capital with a corresponding increase in minority interest in APL, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the purchase of the common units. The Partnership’s ownership percentage in APL, including its 2% interest as General Partner, increased at that time to 15.9% from 14.3% as a result of the transaction.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Partnership include only changes in the fair value of unsettled APL derivative contracts which are accounted for as cash flow hedges (see Note 10). The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):

	Three Months Ended March 31,
	2008			2007
Net income (loss)	$	(2,820	)	$	2,663
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		18,585			(8,668	)
Changes in minority interest related to items in other comprehensive income (loss)		(29,381	)		(31,473	)
Add: adjustment for realized losses reclassified to net income (loss)		17,643			3,047
Total other comprehensive income (loss)		6,847			(37,094	)
Comprehensive income (loss)	$	4,027		$	(34,431	)

Revenue Recognition

Revenue in APL’s Appalachia segment is principally recognized at the time the natural gas is transported through the gathering systems. Under the terms of APL’s natural gas gathering agreements with Atlas Energy and its affiliates, APL 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 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 APL’s Appalachia gathering systems are at separately negotiated prices.

APL’s Mid-Continent segment revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’s regulated transmission pipeline is recognized at the time the transportation service is provided.

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Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for APL 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, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL 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 APL’s keep-whole contracts is minimized.

APL accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from APL’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). APL 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 the Partnership’s consolidated balance sheets.

Capitalized Interest

APL capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by APL was 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

APL has recorded intangible assets with finite lives in connection with certain consummated acquisitions (see Note 9). 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

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Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL 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 APL’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 APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition. 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, APL had $676.8 million and $709.3 million of goodwill recorded in connection with consummated acquisitions (see Note 9). 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, APL 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, APL 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, APL reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on the Partnership’s consolidated balance sheet (see Notes 9 and 17). 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 APL 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 APL management.

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APL 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 APL’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 APL’s assumptions and, if required, recognition of an impairment loss. APL’s test of goodwill at December 31, 2007 resulted in no impairment and no impairment indicators have been noted as of March 31, 2008. APL will continue to evaluate its goodwill at least annually and if impairment indicators arise, and will reflect the impairment of goodwill, if any, within the Partnership’s 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 APL’s 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 11 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the APL’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. APL does not believe the adoption of EITF No. 07-4 will have any impact on its financial position or results of operations. APL’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.

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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133 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 APL’s 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—ATLAS PIPELINE HOLDINGS PUBLIC OFFERING

In July 2007, the Partnership sold 6.25 million common units through a private placement to investors at a negotiated purchase price of $27.00 per unit, yielding gross proceeds of approximately $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). The Partnership utilized the net proceeds from the sale to purchase 3.8 million common units of APL (see Note 4), which utilized the net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9).

NOTE 4—APL COMMON UNIT EQUITY OFFERING

In July 2007, APL 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 APL, 3.8 million

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common units were purchased by the Partnership for $168.8 million. APL also received a capital contribution from the Partnership of $23.1 million for the Partnership to maintain its 2.0% general partner interest in APL. The Partnership funded this capital contribution, underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million. APL 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 9).

NOTE 5—APL PREFERRED UNIT EQUITY OFFERING

On March 13, 2006, APL 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. APL also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to its right under the agreement to require Sunlight Capital to purchase such additional units. The APL 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 APL’s common units. In April 2007, APL and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of APL’s 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 APL 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 APL’s common units as of the date of the notice of conversion. APL may elect to pay cash rather than issue common units in satisfaction of a conversion request. APL 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 APL common units or redeemed prior to May 2010, the APL preferred units will automatically be converted into its common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 (see Note 12) to Sunlight Capital. The Partnership recorded the APL senior unsecured notes as long-term debt and a preferred unit dividend within minority interest in APL on its consolidated balance sheet and, during the three months ended June 30, 2007, reduced minority interest in APL by $3.8 million of this amount, which was the portion deemed to be attributable to the concessions of APL’s common limited partners and its general partner to its preferred unitholder, on its consolidated statements of operations.

APL’s preferred units are reflected on the Partnership’s consolidated balance sheet as minority interest in APL. In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 68, “Increasing Rate Preferred Stock,” APL’s 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, APL 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, APL amortized the remaining $0.5 million of this imputed dividend cost, which is presented within minority interest in APL in the Partnership’s 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. APL recognized $0.1 million of preferred dividend cost, which is presented within minority interest in APL in the Partnership’s consolidated statements of operations for dividends earned during the period and to be paid on May 15, 2008, the date of APL’s quarterly cash distribution (see Note 6). If converted to APL common units, the preferred equity amount converted will be reclassified to common limited partners’ equity within minority interest in APL on the Partnership’s consolidated balance sheet.

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NOTE 6—CASH DISTRIBUTIONS

Partnership Cash Distributions

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 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
				(in thousands)
February 19, 2007	December 31, 2006	$	0.25	$	5,275
May 18, 2007	March 31, 2007	$	0.25	$	5,275
August 17, 2007	June 30, 2007	$	0.26	$	5,486
November 19, 2007	September 30, 2007	$	0.32	$	8,752
February 19, 2008	December 31, 2007	$	0.34	$	9,299

On April 22, 2008, the Partnership declared a cash distribution of $0.43 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2008. The $11.8 million distribution will be paid on May 20, 2008 to unitholders of record at the close of business on May 7, 2008.

APL Cash Distributions

APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by APL for the period from January 1, 2007 through March 31, 2008 were as follows:

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
				(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

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In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), the Partnership, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. The Partnership also agreed that the resulting allocation of incentive distribution rights back to APL would be after the Partnership 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 (“IDR Adjustment Agreement”).

On April 22, 2008, APL 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 Partnership for its general partner interest after the allocation of $3.8 million of its incentive distribution rights back to APL, will be paid on May 15, 2008 to unitholders of record at the close of business on May 7, 2008.

NOTE 7—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, APL acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 9). During the fourth quarter of 2007 and first quarter of 2008, APL 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 APL, which are subject to adjustment and could change as APL 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 APL 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 APL’s write-off of costs related to its pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s 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 APL’s vendor deposit for the manufacture of pipeline which will expire on June 1, 2008 if minimum purchase requirements are not met.

NOTE 8—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 $12,214 and $11,505 at March 31, 2008 and December 31, 2007, respectively	$	17,745	$	18,468
Security deposits		2,744		2,498
Other		103		155
	$	20,592	$	21,121

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Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12).

NOTE 9—ACQUISITIONS

APL’s Chaney Dell and Midkiff/Benedum Acquisition

In July 2007, APL 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 APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

In connection with this acquisition, APL 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. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. The Partnership purchased 3.8 million of the 25.6 million common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6.25 million of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). APL also received a capital contribution from the Partnership of $23.1 million in order for the Partnership to maintain its 2.0% general partner interest in APL. The Partnership funded this capital contribution, underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 12). The Partnership, which holds all of the incentive distribution rights of APL as General Partner, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. The Partnership also agreed that the resulting allocation of incentive distribution rights back to APL would be after the Partnership 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 6). APL 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 12).

APL’s 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

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APL 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, APL 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, APL reduced goodwill recognized in connection with its acquisition and recorded $30.2 million within accounts receivable on the Partnership’s 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 APL continues to evaluate this allocation. Other items could further adjust the amounts allocated to goodwill, although no such items are currently anticipated by APL 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 APL’s acquisition discussed above, the Partnership’s equity offering in July 2007 (see Note 3), APL’s equity offering in July 2007 (see Note 4), APL’s issuance of an $830.0 million term loan, its new $300.0 million senior secured credit facility and respective borrowings under these facilities (see Note 12) and APL’s April 2007 issuance of senior notes (see Note 5) 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 APL and the Partnership had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per unit data):

	Three Months Ended March 31,
	2008			2007
Total revenue and other loss, net	$	303,390		$	261,175
Net loss	$	(2,820	)	$	(298	)
Net loss attributable to common limited partners per unit:
Basic	$	(0.10	)	$	(0.01	)
Diluted	$	(0.10	)	$	(0.01	)

NOTE 10—DERIVATIVE INSTRUMENTS

APL uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. APL also

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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, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not 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”).

APL formally documents 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. APL 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, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by APL through the utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations. For APL’s 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 APL’s 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.

During January 2008, APL 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, APL 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 12), 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 APL’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.

APL’s 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 $0.8 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 $0.3 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $260,000 of losses to natural gas and liquids revenue and $40,000 of losses to interest expense. Aggregate losses of $0.5 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of $489,000 to natural gas and liquids revenue and $25,000 to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

On June 3, 2007, APL signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see Note 9). In connection with certain additional agreements entered into to finance this transaction, APL 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, APL 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

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Anadarko Assets to be acquired was not considered “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, APL recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in the Partnership’s 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. APL 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 its Chaney Dell and Midkiff/Benedum acquisition, APL 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 9). At March 31, 2008, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL 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 APL may have.

The following table summarizes APL’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, APL 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	)

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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

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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 APL’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.

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NOTE 11—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.

APL uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 10). All of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and crude oil options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. APL’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 APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’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 APL’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	)

APL’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 APL’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	)

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(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 12—DEBT

Total debt consists of the following (in thousands):

	March 31, 2008			December 31, 2007
Revolving credit facility	$	25,000		$	25,000
APL revolving credit facility		165,000			105,000
APL term loan		830,000			830,000
APL senior notes		294,365			294,392
Other APL debt		26			34
		1,314,391			1,254,426
Less current maturities		(26	)		(34	)
Total long term debt	$	1,314,365		$	1,254,392

Atlas Pipeline Holdings Credit Facility

The Partnership, with Atlas Pipeline GP as guarantor, has a $50.0 million revolving credit facility with a syndicate of banks. At March 31, 2008, the Partnership has $25.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution to APL to maintain its 2.0% general partner interest, underwriter fees and other transaction costs related to its July 2007 private placement of common units (see Note 3). The Partnership’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at March 31, 2008 was 5.0%. Borrowings under the Partnership’s credit facility are secured by a first-priority lien on a security interest in all of the Partnership’s assets, including a pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and the Partnership’s other subsidiaries (excluding APL and its subsidiaries). The Partnership’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to the Partnership’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of the Partnership’s property or assets, including the sale or transfer of interests in its subsidiaries. The Partnership is in compliance with these covenants as of March 31, 2008.

The events which constitute an event of default under 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, a change of control of Atlas America, the Partnership’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. The Partnership’s credit facility requires it to maintain a combined leverage ratio, defined as the ratio of the sum of (i) the Partnership’s funded debt (as defined in its credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility) of not more than 5.5 to 1.0. In addition, the Partnership’s credit facility requires it to maintain a funded debt (as defined in its credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in its credit facility) of not less than 3.0 to 1.0. The Partnership’s credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable with respect to the last fiscal quarter in such period by APL to the Partnership in respect of the Partnership’s general partner interest, limited partner interest and incentive distribution rights in APL and (ii) the Partnership’s consolidated net income (as defined in its credit facility and as adjusted as provided in its credit facility). As of March 31, 2008, the Partnership’s combined leverage ratio was 4.7 to 1.0, its funded debt to EBITDA was 0.7 to 1.0, and its interest coverage ratio was 28.0 to 1.0.

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The Partnership may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from us to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.

APL Term Loan and Credit Facility

In connection with APL’s July 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), APL 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 APL credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on APL’s 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 APL 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 APL credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by 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 APL credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is in compliance with these covenants as of March 31, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the APL 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 credit facility, APL 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, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

The events which constitute an event of default for APL’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires it 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, APL’s ratio of funded debt to EBITDA was 4.6 to 1.0 and its interest coverage ratio was 3.4 to 1.0.

APL 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.

APL Senior Notes

At March 31, 2008, APL 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 APL Senior Notes is payable semi-annually in arrears on

26

June 15 and December 15. The APL 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, APL may redeem up to 35% of the aggregate principal amount of the APL Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

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

NOTE 13—COMMITMENTS AND CONTINGENCIES

APL 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, APL is committed to expend approximately $163.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 14—STOCK COMPENSATION

The Partnership and APL follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”), for their stock compensation. 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 Partnership’s Long-Term Incentive Plan

The Partnership has a Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The Partnership’s LTIP is administered by a committee (the “LTIP Committee”), appointed by the Partnership’s board. Under the Partnership’s LTIP, phantom units and/or unit options may be granted, at the discretion of the Partnership’s LTIP Committee, to all or designated Participants, at the discretion of the Partnership’s LTIP Committee. The Partnership’s LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At March 31, 2008, the Partnership had 1,440,475 phantom units and unit options outstanding under the Partnership’s LTIP, with 659,150 phantom units and unit options available for grant.

Partnership Phantom Units. A phantom unit entitles a Participant to receive a common unit of the Partnership upon vesting of the phantom unit or, at the discretion of the Partnership’s LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of the Partnership. In tandem with phantom unit grants, the Partnership’s LTIP 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 such phantom unit is outstanding. The Partnership’s LTIP Committee will determine the vesting period for phantom units. Through March 31, 2008, phantom units granted under the LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual

27

award settlement, as determined by the Partnership’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. Of the phantom units outstanding under the Partnership’s LTIP at March 31, 2008, 675 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at March 31, 2008 include DERs granted to the Participants by the Partnership’s LTIP Committee. The amount paid with respect to the Partnership’s LTIP DERs was $0.1 million for both the three months ended March 31, 2008 and 2007. This amount was recorded as a reduction of partners’ capital on the Partnership’s consolidated balance sheet.

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

	Three Months Ended March 31,
	2008		2007
Outstanding, beginning of period		220,825		220,492
Granted(1)		4,650		—
Unit adjustment		—		(492	)
Matured		—		—
Forfeited		—		—
Outstanding, end of period		225,475		220,000
Non-cash compensation expense recognized (in thousands)	$	366	$	345

⁽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 $32.28 for the three months ended March 31, 2008.

At March 31, 2008, the Partnership had approximately $3.3 million of unrecognized compensation expense related to unvested phantom units outstanding under its LTIP based upon the fair value of the awards.

Partnership Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit as determined by the Partnership’s LTIP Committee on the date of grant of the option. The Partnership’s LTIP Committee also shall determine how the exercise price may be paid by the Participant. The Partnership’s LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2008, unit options granted under the Partnership’s LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. 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 Partnership’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. There are no unit options outstanding under the Partnership’s LTIP at March 31, 2008 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:

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	Three Months Ended March 31,
	2008				2007
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		1,215,000	$	22.56		1,215,000	$	22.56
Granted		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56
Options exercisable, end of period		—		—		—		—
Non-cash compensation expense recognized (in thousands)	$	309			$	309

(1) The weighted average remaining contractual life for outstanding options at March 31, 2008 was 8.6 years.

(2) The aggregate intrinsic value of options outstanding at March 31, 2008 was approximately $5.8 million.

At March 31, 2008, the Partnership had approximately $2.8 million of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.

APL Long-Term Incentive Plan

APL has a Long-Term Incentive Plan (“APL 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 APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by the Partnership’s managing board. The APL LTIP 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 APL 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 APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant a participant a 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 APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP 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 Partnership, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through March 31, 2008, phantom units granted under the APL 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 APL LTIP 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 APL LTIP. Of the units outstanding under the APL LTIP at March 31, 2008, 69,519 units will vest within the following twelve months. All units outstanding under the APL LTIP at March 31, 2008 include DERs granted to the participants by the APL LTIP Committee. The amount paid with respect to APL LTIP DERs was $0.1 million for both the three-month periods ended March 31, 2008 and 2007. These amounts were recorded as reductions of minority interest in APL on the Partnership’s consolidated balance sheet.

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The following table sets forth the APL 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, APL had approximately $4.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Incentive Compensation Agreements

APL 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 APL 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 APL assets for the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s 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 APL 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 APL shall be paid in cash.

APL 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 APL’s 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. APL 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 APL’s common units. Based upon APL 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

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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. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

NOTE 15—RELATED PARTY TRANSACTIONS

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

APL’s partnership agreement provides that the Partnership will determine the costs and expenses that are allocable to APL in any reasonable manner determined by the Partnership at its sole discretion. APL reimbursed the Partnership and its affiliates $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 by APL to the Partnership were $9.4 million and $6.0 million, respectively, including certain costs that have been capitalized by APL. The Partnership believes that the method utilized in allocating costs to APL is reasonable.

Under an agreement between APL 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 APL’s gathering systems. APL 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 APL’s gathering systems, APL has various options to connect those wells to its gathering systems at its own cost.

NOTE 16—SEGMENT INFORMATION

The Partnership’s assets primarily consist of its ownership interests in APL. APL 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 APL manages its operations.

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The following summarizes APL’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		(2,388	)		(2,077	)
Interest expense		(20,822	)		(6,846	)
Minority interest in Atlas Pipeline Partners, L.P.		44,344			1,149
Net income (loss)	$	(2,820	)	$	2,663
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		19,426			20,605
	$	2,943,017		$	2,877,514
Goodwill:
Mid-Continent	$	674,497		$	706,978
Appalachia		2,305			2,305
	$	676,802		$	709,283

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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 and compression:
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 17—SUBSEQUENT EVENTS

During April 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, APL 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 12), and will receive LIBOR plus the applicable margin, on the notional principal amount of $250.0 million. This hedge effectively converts $250.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. APL’s interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

In April 2008, APL 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, APL has reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on the Partnership’s 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, “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

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

• a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

• all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), we, the holder of all the incentive distribution rights in APL, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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.; and

• 5,476,253 common units of APL, representing approximately 14.1% of the outstanding common units of APL, or a 13.5% limited partner interest in APL.

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

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

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

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

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

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These amounts are partially offset by our July 2007 agreement to allocate up to $5.0 million of incentive distributions per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

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

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

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

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

Financial Presentation

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

Atlas Pipeline Partners, L.P.

APL is a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL”. APL’s principal business objective is to generate cash for distribution to its unitholders. APL is 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, APL is a leading provider of natural gas processing services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

Through its Mid-Continent operations, APL owns and operates:

• 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 APL’s natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, APL owns and operates 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

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between APL and Atlas America, Inc. and its affiliates, a publicly traded company (NASDAQ: ATLS – “Atlas America”) and holder of a 64.0% ownership interest in us, 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), APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also party to natural gas gathering agreements with Atlas America and Atlas Energy under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

From the date of APL’s initial public offering in January 2000 through March 2008, it has completed seven acquisitions at an aggregate purchase price of approximately $2.4 billion, including:

• In July 2007, APL 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 APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. In connection with this acquisition, APL 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. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. APL funded the purchase price, in part, from its 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, we purchased $168.8 million of these APL units, which was funded through our issuance of 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit (see “—Our Common Equity Offerings”). We, as general partner and holder all of APL’s incentive distribution rights, have also agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 “—APL’s Partnership Distributions”). APL 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 “—APL Term Loan and Credit Facility”).

Subsequent Events

During April 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, APL 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 12 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 APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. APL’s interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

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In April 2008, APL 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, APL has reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on our consolidated balance sheet.

Contractual Revenue Arrangements

APL’s principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect its revenue are:

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

• the transportation and processing fees APL receives which, in turn, depends upon the price of the natural gas and NGLs it transports and processes, 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 APL’s Appalachian region, substantially all of the natural gas it transports is for Atlas Energy under percentage-of-proceeds (“POP”) contracts, as described below, in which APL earns 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 APL’s inception in January 2000, its Appalachian system transportation fee has exceeded this minimum generally. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

APL’s Mid-Continent segment revenue consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’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 APL’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. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for APL 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, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL 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

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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 APL’s keep-whole contracts is minimized.

Recent Trends and Uncertainties

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

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

As a result of APL’s POP and keep-whole contracts, its 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.

APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. We closely monitor the risks associated with commodity price changes on APL’s 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 APL’s assets and operations from such price risks. APL does not realize the full impact of commodity price changes because some of its 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 APL processes and sells would result in a change to our gross margin, excluding the effect of minority interest in APL net income (loss), for the twelve-month period ending March 31, 2009 of approximately $1.7 million.

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Results of Operations

The following table illustrates selected volumetric information related to APL’s 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 APL’s Chaney Dell and Midkiff/Benedum systems, which APL acquired in July 2007, of $223.2 million, an increase of $21.4 million from APL’s Elk City/Sweetwater system due primarily to an increase in plant utilization at the Sweetwater processing plant, an increase of $17.0 million from APL’s Velma system due primarily to an increase in volumes, and an increase of $1.5 million from APL’s 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. APL enters into derivative instruments principally to hedge its 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 10 under Item 1, “Financial Statements”.

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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 APL’s NOARK system, a $1.7 million increase from APL’s Appalachia system, $2.4 million of contributions from APL’s Chaney Dell and Midkiff/Benedum systems, and a $1.0 million increase from the Elk City/Sweetwater system. For APL’s 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. APL’s 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 APL’s Appalachia system average daily throughput volume was principally due to new wells connected to its 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 comparable prior year 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 three months ended March 31, 2007, 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 APL has 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 APL’s 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 APL’s derivative contracts. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Note 10 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 APL’s Chaney Dell and Midkiff/Benedum acquisition and an increase in gathered and processed natural gas volumes on APL’s Elk City/Sweetwater system, which includes contributions from the Sweetwater processing facility and APL’s 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 APL’s 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 APL’s NOARK system operating and maintenance costs.

General and administrative expenses, including amounts reimbursed to affiliates, decreased $0.8 million to $6.4 million for the three months ended March 31, 2008 compared with $7.2 million for the comparable prior year 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 and APL’s 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 APL 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 APL’s 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.

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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 APL’s Chaney Dell and Midkiff/Benedum acquired assets and APL’s expansion capital expenditures incurred subsequent to March 31, 2007, a $4.0 million write-off of costs related to an APL pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

Interest expense increased to $20.8 million for the three months ended March 31, 2008 as compared with $6.8 million for the comparable prior year period. This $14.0 million increase was primarily due to interest associated with APL’s $830.0 million term loan issued in connection with its acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—APL Term Loan and Credit Facility”) and additional borrowings under APL’s credit facility to finance its 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 APL’s acquisition of control of the respective systems.

Minority interest in APL’s net income (loss), which represents the allocation of APL’s earnings to its non-affiliated limited partners, was income of $44.3 million for the three months ended March 31, 2008 as compared with income of $1.1 million for the comparable prior year period. This decrease was primarily due to a decrease in APL’s net income between periods.

Liquidity and Capital Resources

Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and borrowings under our credit facility. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through distributions received from APL and our capital contributions to APL through the retention of cash and borrowings under our credit facility.

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

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

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

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

At March 31, 2008, we had $25.0 million outstanding and $25.0 million of remaining committed capacity under our credit facility, subject to covenant limitations (see “— Our Credit Facility”). APL had $165.0 million of outstanding borrowings under its $300.0 million senior secured credit facility at March 31, 2008 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 its credit facility, subject to covenant limitations (see “—APL Term Loan and Credit Facility”). In addition to the availability under its credit facility, APL has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities (see “—APL Shelf Registration Statement”) of which $352.1 million remains available at March 31,

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2008. At March 31, 2008, we had a working capital deficit of $57.9 million compared with a working capital deficit of $78.7 million at December 31, 2007. This increase in working capital was primarily due to an increase in APL’s accounts receivable as a result of the receipt of a $30.2 million cash reimbursement in April 2008 for state sales tax paid in connection with the Chaney Dell and Midkiff/Benedum acquisition (see Notes 9 and 17 under Item 1, “Financial Statements”). We believe that we and APL 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 and APL are subject to business and operational risks that could adversely affect our cash flow. We and APL may supplement our cash generation with proceeds from financing activities, including borrowings under our and APL’s credit facilities 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 $23.4 million for the three months ended March 31, 2008 represented an increase of $16.7 million from $6.7 million for the comparable prior year period. The increase was derived principally from a $40.7 million increase in net income excluding non-cash items, partially offset by a $21.5 million increase in cash distributions to minority interests and a $2.5 million decrease in cash flow from working capital changes. This increase in net income excluding non-cash items was principally due to the contributions from APL’s Chaney Dell and Midkiff/Benedum systems, which it acquired in July 2007. The non-cash charges which impacted net income include a $72.5 million movement in APL’s non-cash derivative losses, a $19.3 million increase in depreciation and amortization, partially offset by a $43.2 million decrease in minority interest in APL’s net income and a $4.6 million decrease in non-cash compensation expense. The movement in APL’s non-cash derivative losses resulted from commodity price movements and their unfavorable impact on the fair value of derivative contracts APL has for future periods. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized during the first quarter 2008 for certain APL 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 APL’s 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. The increase in depreciation and amortization resulted from depreciation and amortization associated with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The decrease in the minority interests in APL’s net income was due to a decrease in APL’s net income between periods. The increase in cash distributions to minority interests is due mainly to increases in APL’s limited partner units outstanding and their cash distribution amount per common limited partner per unit.

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 APL capital expenditures, partially offset by APL’s receipt of $1.3 million in connection with a post-closing purchase price adjustment of its 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 $50.5 million for the three months ended March 31, 2008, an increase of $40.9 million from $9.6 million of net cash provided by financing activities for the prior year comparable period. This increase was principally due to a $45.0 million net increase in APL’s borrowings under its revolving credit facility, and partially offset by a $4.0 million increase in distributions paid to our limited partners.

Capital Requirements

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

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

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

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

	Three Months Ended 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 APL’s 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 APL’s existing gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in APL’s 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 APL’s scheduled maintenance activity. As of March 31, 2008, APL is committed to expend approximately $163.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Our Credit Facility

We, with Atlas Pipeline GP as guarantor, have a $50.0 million revolving credit facility with a syndicate of banks. At March 31, 2008, we have $25.0 million outstanding under our revolving credit facility, which was utilized to fund our capital contribution to APL to maintain our 2.0% general partner interest, underwriter fees and other transaction costs related to our July 2007 private placement of common units (see “—Atlas Pipeline Partners, L.P.”). Our credit facility matures in April 2010 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on our outstanding credit facility borrowings at March 31, 2008 was 5.0%. Borrowings under our credit facility are secured by a first-priority lien on a security interest in all of our assets, including a pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and our other subsidiaries (excluding APL and its subsidiaries). Our 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 would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. We are in compliance with these covenants as of March 31, 2008.

The events which constitute an event of default under 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, a change of control of Atlas America, our general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. Our credit facility requires us to maintain a combined leverage ratio, defined

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as the ratio of the sum of (i) our funded debt (as defined in our credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility)) of not more than 5.5 to 1.0. In addition, our credit facility requires us to maintain a funded debt (as defined in our credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in our credit facility) of not less than 3.0 to 1.0. Our credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable by APL to us in respect of our general partner interest, limited partner interest and incentive distribution rights in APL with respect to the last fiscal quarter in such period, and (ii) our consolidated net income (as defined in our credit facility and as adjusted as provided in our credit facility). As of March 31, 2008, our combined leverage ratio was 4.7 to 1.0, our senior secured debt to EBITDA was 0.7 to 1.0, and our interest coverage ratio was 28.0 to 1.0.

We may borrow under our credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from us to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to our credit facility and (iii) for letters of credit.

Our Partnership Distributions

The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

• provide for the proper conduct of our business;

• comply with applicable law, any of our debt instruments or other agreements; or

• provide funds for distributions to our unitholders for any one or more of the next four quarters.

These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

APL’s Partnership Distributions

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

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APL’s general partner is granted discretion by APL’s partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, 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 APL’s general partner determines its quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, we, as sole owner of APL’s general partner, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”). We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 by APL 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 APL.

Our Common Equity Offering

In July 2007, we sold 6.25 million common units through a private placement to investors at a negotiated purchase price of $27.00 per unit, yielding gross proceeds of approximately $168.8 million (or net proceeds of $167.0 million, after underwriter’s fees and other transaction costs). We utilized the net proceeds from the sale to purchase 3.8 million common units of APL (see “—APL Common Equity Offerings”), which utilized those net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems.

APL Common Equity Offering

In July 2007, APL 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 APL, 3.8 million common units were purchased by us for $168.8 million. APL also received a capital contribution from us of $23.1 million for us to maintain our 2.0% general partner interest in APL. We funded this capital contribution and underwriting fees and other transaction costs related to our private placement of common units through borrowings under our revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the Chaney Dell and Midkiff/Benedum acquisitions (see “—Atlas Pipeline Partners, L.P.”).

APL Shelf Registration Statement

APL has an effective shelf registration statement with the Securities and Exchange Commission that permits it 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, APL’s funding requirements, prevailing market conditions, and compliance with its credit facility covenants.

APL Private Placement of Convertible Preferred Units

On March 13, 2006, APL 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

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gross proceeds of $30.0 million. APL also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to its right under the agreement to require Sunlight Capital to purchase such additional units. The APL 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 APL’s common units. In April 2007, APL and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of APL’s 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 APL 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 APL’s common units as of the date of the notice of conversion. APL may elect to pay cash rather than issue common units in satisfaction of a conversion request. APL 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 APL common units or redeemed prior to May 2010, the APL preferred units will automatically be converted into its common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 (see Note 5 under Item 1, “Financial Statements”) to Sunlight Capital. The Partnership recorded the APL senior unsecured notes as long-term debt and a preferred unit dividend within minority interest in APL on its consolidated balance sheet and, during the three months ended June 30, 2007, reduced minority interest in APL by $3.8 million of this amount, which is the portion deemed to be attributable to the concessions of APL’s common limited partners and its general partner to its preferred unitholder, on its 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 accrued and paid on APL’s preferred units and the premium paid upon their redemption, if any, will be recognized within minority interest in APL in the Partnership’s consolidated statements of operations. If converted to APL common units, the preferred equity amount converted will be reclassified to common limited partners’ equity within minority interest in APL on the Partnership’s consolidated balance sheet.

APL Term Loan and Credit Facility

APL has 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 APL’s credit facility bear interest, at its 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 APL’s 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 APL’s 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 APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is in compliance with these covenants as of March 31, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of APL’s 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 credit facility, APL 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, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

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The events which constitute an event of default for APL’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires it 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, APL’s ratio of funded debt to EBITDA was 4.6 to 1.0 and its interest coverage ratio was 3.4 to 1.0.

APL 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.

APL Senior Notes

At March 31, 2008, APL 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 APL Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL 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, APL may redeem up to 35% of the aggregate principal amount of the APL Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

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

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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 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.

APL uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 10 under Item 1, “Financial Statements”). All of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and crude oil options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. APL’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 APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’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 as Level 3.

Recently Adopted Accounting Standards

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“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 APL’s derivative instruments,

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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 APL’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. APL does not believe the adoption of EITF No. 07-4 will have any impact on its financial position or results of operations. APL’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 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. We are currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding APL’s 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

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

General

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

We and APL are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and APL manage these risks through regular operating and financing activities and periodical use of derivative 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 and APL’s business.

Interest Rate Risk. At March 31, 2008, we had a $50.0 million revolving credit facility with $25.0 million outstanding. The weighted average interest rate for these borrowings was 5.0% at March 31, 2008.

At March 31, 2008, APL had a $300.0 million senior secured revolving credit facility ($165.0 million outstanding). APL also had an $830.0 million senior secured term loan outstanding at March 31, 2008. The weighted average interest rate for APL’s 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, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL 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 12 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 APL’s floating rate debt under the credit facility to fixed-rate debt. Realized gains and losses on the effective component of APL’s interest rate derivative contracts are recorded 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, APL 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, APL 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.

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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 our and APL’s interest rates would change our consolidated annual interest expense by $5.7 million.

Commodity Price Risk. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs, and condensate rather than cash. For gathering services, APL receives fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, APL either receives fees or commodities as payment for these services, based on the type of contractual agreement. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells would result in a change to our gross margin for the twelve-month period ending March 31, 2009, excluding the effect of minority interests in APL net income (loss), of approximately $1.7 million.

APL uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. APL 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, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not 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”).

APL formally documents 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. APL 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, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by APL through the utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations. For APL’s 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 APL’s 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 its Chaney Dell and Midkiff/Benedum acquisition, APL 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 9 under Item 1, “Financial Statements”). At March 31, 2008, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL 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 APL may have.

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As of March 31, 2008, APL 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	)

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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	)

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⁽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 APL’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.

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 of Atlas Pipeline Holdings, L.P.(1)
3.2	Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P. (2)
4.1	Specimen Certificate Representing Common Units(1)
31.1	Rule 13(a)-14(a)/15(d)-14(a) Certification

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31.2	Rule 13(a)-14(a)/14(d)-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification

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

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS PIPELINE HOLDINGS, L.P.
	By:	Atlas Pipeline Holdings GP, LLC, its General Partner
Date: May 8, 2008	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman of the Board of the General Partner
		Chief Executive Officer of the General Partner
Date: May 8, 2008	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer and Director of the General Partner
Date: May 8, 2008	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer of the General Partner

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