UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2007

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

For the transition period from                      to                     

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation or organization)		23-3011077 (I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road Moon Township, Pennsylvania (Address of principal executive office)		15108 (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 þ No o

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

Large accelerated filer o      Accelerated filer þ      Non-accelerated filer o

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

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q

		PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006 (Unaudited)			3
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2007 and 2006 (Unaudited)			4
Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2007 (Unaudited)			5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2007 and 2006 (Unaudited)			6
Notes to Consolidated Financial Statements (Unaudited)			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3. Quantitative and Qualitative Disclosures About Market Risk			38
Item 4. Controls and Procedures			42
PART II. OTHER INFORMATION
Item 6. Exhibits			43
SIGNATURES			44

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

		June 30,				December 31,
		2007				2006
ASSETS
Current assets:
Cash and cash equivalents		$	2,435			$	1,795
Accounts receivable — affiliates			3,908				7,601
Accounts receivable			48,409				51,192
Current portion of derivative asset			—				5,437
Prepaid expenses and other			4,286				10,444
Total current assets			59,038				76,469
Property, plant and equipment, net			638,479				607,097
Long-term derivative asset			—				305
Intangible assets, net			24,744				25,530
Goodwill			63,441				63,441
Other assets, net			13,464				14,042
		$	799,166			$	786,884
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	39			$	71
Accounts payable			14,311				18,624
Accrued liabilities			10,271				6,410
Distribution payable			15,706				—
Current portion of derivative liability			32,152				17,362
Accrued producer liabilities			29,999				32,766
Total current liabilities			102,478				75,233
Long-term derivative liability			26,223				8,505
Long-term debt, less current portion			368,464				324,012
Commitments and contingencies
Partners’ capital:
Preferred limited partner’s interests			37,097				39,381
Common limited partners’ interests			288,850				350,805
General partner’s interest			5,563				11,034
Accumulated other comprehensive loss			(29,509	)			(22,086	)
Total partners’ capital			302,001				379,134
		$	799,166			$	786,884

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Revenue:
Natural gas and liquids		$	104,792			$	95,609			$	206,968			$	196,086
Transportation and compression – affiliates			8,458				7,834				16,178				15,708
Transportation and compression — third parties			10,588				5,379				20,426				14,156
Other income (loss)			(28,423	)			679				(30,620	)			1,361
Total revenue and other income (loss)			95,415				109,501				212,952				227,311
Costs and expenses:
Natural gas and liquids			87,102				77,006				174,912				162,898
Plant operating			4,515				3,926				9,045				7,153
Transportation and compression			3,210				2,849				6,322				4,925
General and administrative			6,608				4,181				12,311				8,396
Compensation reimbursement – affiliates			798				885				1,428				1,605
Depreciation and amortization			6,671				5,258				13,205				10,533
Interest			7,327				6,154				14,086				12,491
Minority interest in NOARK			—				(451	)			—				118
Total costs and expenses			116,231				99,808				231,309				208,119
Net income (loss)			(20,816	)			9,693				(18,357	)			19,192
Preferred unit dividend effect			(3,756	)			—				(3,756	)			—
Preferred unit imputed dividend cost			(735	)			(540	)			(1,234	)			(635	)
Net income (loss) attributable to common limited partners and the general partner		$	(25,307	)		$	9,153			$	(23,347	)		$	18,557
Allocation of net income (loss) attributable to common Limited partners and the general partner:
Common limited partners’ interest		$	(28,728	)		$	5,299			$	(30,612	)		$	11,105
General partner’s interest			3,421				3,854				7,265				7,452
Net income (loss) attributable to common limited partners and the general partner		$	(25,307	)		$	9,153			$	(23,347	)		$	18,557
Net income (loss) attributable to common limited partners per unit:
Basic		$	(2.20	)		$	0.41			$	(2.34	)		$	0.88
Diluted		$	(2.20	)		$	0.41			$	(2.34	)		$	0.87
Weighted average common limited partner units outstanding:
Basic			13,080				12,824				13,080				12,687
Diluted			13,080				12,979				13,080				12,833

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

																						Accumulated
		Number of Limited								Preferred				Common								Other				Total
		Partner Units								Limited				Limited				General				Comprehensive				Partners’
		Preferred				Common				Partner				Partners				Partner				Loss				Capital
Balance at January 1, 2007			40,000				13,080,418			$	39,381			$	350,805			$	11,034			$	(22,086	)		$	379,134
Preferred unit dividend			—				—				(8,524	)			—				—				—				(8,524	)
Costs incurred related to issuance of preferred dividend			—				—				(7	)			—				—				—				(7	)
Costs incurred related to issuance of common units			—				—				—				(40	)			—				—				(40	)
Unissued common units under incentive plans			—				—				—				4,302				—				—				4,302
Costs incurred related to issuance of units under incentive plans			—				—				—				(40	)			—				—				(40	)
Distributions paid and payable to common limited partners and the general partner			—				—				—				(33,878	)			(12,711	)			—				(46,589	)
Distribution equivalent rights paid and payable on unissued units under incentive plans			—				—				—				(455	)			—				—				(455	)
Other comprehensive loss			—				—				—				—				—				(7,423	)			(7,423	)
Net loss			—				—				4,990				(30,612	)			7,265				—				(18,357	)
Balance at June 30, 2007			40,000				13,080,418			$	35,840			$	290,082			$	5,588			$	(29,509	)		$	302,001

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

		Six Months Ended
		June 30,
		2007				2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(18,357	)		$	19,192
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			13,205				10,533
Non-cash loss (gain) on derivative value			30,826				(256	)
Non-cash compensation expense			4,262				2,502
Amortization of deferred finance costs			1,068				1,205
Minority interest in NOARK			—				118
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other			8,496				8,577
Accounts payable and accrued liabilities			(3,218	)			(18,249	)
Accounts payable and accounts receivable – affiliates			3,693				314
Net cash provided by operating activities			39,975				23,936
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisition			—				(30,000	)
Capital expenditures			(43,395	)			(35,812	)
Other			216				159
Net cash used in investing activities			(43,179	)			(65,653	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of debt			8,524				36,655
Payment of preferred unit dividend			(8,524	)			—
Repayment of debt			—				(39,000	)
Borrowings under credit facility			118,000				9,500
Repayments under credit facility			(82,000	)			(19,000	)
Net proceeds from issuance of common limited partner units			—				19,769
Net proceeds from issuance of preferred limited partner units			—				39,970
General partner capital contribution			—				1,206
Distributions paid to common limited partners and the general partner			(30,883	)			(28,362	)
Other			(1,273	)			(697	)
Net cash provided by financing activities			3,844				20,041
Net change in cash and cash equivalents			640				(21,676	)
Cash and cash equivalents, beginning of period			1,795				34,237
Cash and cash equivalents, end of period		$	2,435			$	12,561

     See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTE 1 – BASIS OF PRESENTATION

     Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the transmission, gathering and processing of natural gas. The Partnership’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of the Partnership. Atlas Pipeline Partners GP, LLC (the “General Partner”), through its general partner interests in the Partnership and the Operating Partnership, owns a 2% general partner interest in the consolidated pipeline operations, through which it manages and effectively controls both the Partnership and the Operating Partnership. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests. The General Partner also owns 1,641,026 limited partner units in the Partnership which have not been registered with the Securities and Exchange Commission and, therefore, their resale in the public market is subject to restrictions under the Securities Act. At June 30, 2007, the Partnership had 13,080,418 common limited partnership units, including 1,641,026 unregistered common units held by the General Partner, and 40,000 $1,000 par value cumulative convertible preferred limited partnership units outstanding (see Note 4 and Note 15).

     The Partnership’s General Partner is a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P. (“AHD”), a publicly-traded partnership (NYSE: AHD). Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), had an 82.9% ownership interest in AHD’s outstanding common units at June 30, 2007. Atlas America also had a 49.0% ownership interest in the outstanding common units of Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN) focused on the development of natural gas and oil in the Appalachian basin. Substantially all of the natural gas the Partnership transports in the Appalachian Basin is derived from wells operated by Atlas Energy.

     The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2006 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2006. The results of operations for the three and six month periods ended June 30, 2007 may not necessarily be indicative of the results of operations for the full year ending December 31, 2007.

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

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2006.

Principles of Consolidation and Minority Interest

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

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

Use of Estimates

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

     The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and six months ended June 30, 2007 represent actual results in all material respects (see “ – Revenue Recognition” accounting policy for further description).

Net Income (Loss) Per Common Unit

     Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholder’s interests, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its 2% interest and incentive distributions (see Note 5), with a priority allocation of net income in an amount equal to the general partner’s incentive distributions, in accordance with the partnership agreement, and the remaining net income or loss allocated with respect to the general partner’s and limited partners’ ownership interests. Diluted net income attributable to common limited partners per unit

is calculated by dividing net income attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of phantom unit awards, as calculated by the treasury stock method, and the dilutive effect of convertible securities. Phantom units consist of common units issuable under the terms of the Partnership’s Long-Term Incentive Plan and Incentive Compensation Agreements (see Note 12). The following table sets forth the reconciliation of the weighted average number of common limited partner units used to compute basic net income attributable to common limited partners per unit with those used to compute diluted net income attributable to common limited partners per unit (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Weighted average number of common limited partner units – basic			13,080				12,824				13,080				12,687
Add: effect of dilutive unit incentive awards (1)			—				155				—				146
Weighted average number of common limited partner units – diluted			13,080				12,979				13,080				12,833

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

Comprehensive Income (Loss)

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Net income (loss)		$	(20,816	)		$	9,693			$	(18,357	)		$	19,192
Preferred unit dividend			(3,756	)			—				(3,756	)			—
Preferred unit imputed dividend cost			(735	)			(540	)			(1,234	)			(635	)
Net (loss) income attributable to common limited partners and the general partner			(25,307	)			9,153				(23,347	)			18,557
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as hedges			(9,453	)			(18,845	)			(18,120	)			(18,471	)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Add: adjustment for realized losses reclassified to net income (loss)			7,650				3,222				10,697				5,622
Total other comprehensive (loss) income			(1,803	)			(15,623	)			(7,423	)			(12,849	)
Comprehensive (loss) income		$	(27,110	)		$	(6,470	)		$	(30,770	)		$	5,708

Revenue Recognition

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

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

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

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

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

     The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices (see Use of Estimates accounting policy for further description). The Partnership had unbilled revenues at June 30, 2007 and December 31,

2006 of $11.2 million and $20.2 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within its consolidated balance sheets.

Capitalized Interest

     The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 8.0% for both the three and six months ended June 30, 2007 and 8.1% for both the three and six months ended June 30, 2006. The amount of interest capitalized was $0.4 million and $0.6 million for the three months ended June 30, 2007 and 2006, respectively, and $1.0 million for both the six months ended June 30, 2007 and 2006.

Intangible Assets

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

										Estimated
		June 30,				December 31,				Useful Lives
		2007				2006				In Years
Gross Carrying Amount:
Customer contracts		$	12,810			$	12,390				8
Customer relationships			17,260				17,260				20
		$	30,070			$	29,650
Accumulated Amortization:
Customer contracts		$	(3,420	)		$	(2,646	)
Customer relationships			(1,906	)			(1,474	)
		$	(5,326	)		$	(4,120	)
Net Carrying Amount:
Customer contracts		$	9,390			$	9,744
Customer relationships			15,354				15,786
		$	24,744			$	25,530

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

     Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, the Partnership will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for the Partnership’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence at the date of acquisition. The estimated useful life for the Partnership’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition. Amortization expense on intangible assets was $0.6 million and $1.2 million for the three months

ended June 30, 2007 and 2006, respectively, and $1.2 million and $2.3 million for the six months ended June 30, 2007 and 2006, respectively. Amortization expense related to intangible assets is estimated to be $2.5 million for each of the next five calendar years commencing in 2008.

Goodwill

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

		Six Months Ended
		June 30,
		2007				2006
Balance, beginning of period		$	63,441			$	111,446
Goodwill acquired – remaining 25% interest in NOARK			—				30,195
Reduction in minority interest deficit acquired			—				(118	)
Purchase price allocation adjustment – NOARK			—				(314	)
Balance, end of period		$	63,441			$	141,209

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

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

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

NOTE 3 – COMMON UNIT EQUITY OFFERING

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

NOTE 4 – PREFERRED UNIT EQUITY OFFERING

     On March 13, 2006, the Partnership entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. The Partnership also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to the Partnership’s right under the agreement to require Sunlight Capital to purchase such additional units. The preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for the Partnership’s common units. On April 18, 2007, the Partnership and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of the preferred units were amended to entitle them to receive dividends of 6.5% per annum commencing on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for common unit distributions after March 13, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of the Partnership’s common units as of the date of the notice of conversion. The Partnership may elect to pay cash rather than issue common units in satisfaction of a conversion request. The Partnership has the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.82.

     In consideration of Sunlight Capital’s consent to the amendment of the preferred units, the Partnership issued $8.5 million of its 8.125% senior unsecured notes due 2015 (the “Notes”) (see Note 10) to Sunlight Capital. The Partnership filed, pursuant to the Registration Rights Agreement, an exchange offer registration statement to exchange the Notes for publicly tradable notes. The registration statement was declared effective by the SEC on July 17, 2007. The Partnership must complete the exchange offer by September 15, 2007 or, if it fails to do so, the Notes will accrue additional interest of 1% per annum for each 90-day period the Partnership is in default, up to a maximum amount of 3% per annum. The Partnership recorded the Notes as long-term debt and a preferred unit dividend within partners’ capital, and has reduced net income attributable to common limited partners and the general partner by $3.8 million of this amount, which is the portion deemed to be attributable to the concessions of the common limited partners and the general partner to the preferred unitholder, on its consolidated statements of income.

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

     Amortization of the imputed dividend cost, which is presented as a reduction of net income to determine net income attributable to common limited partners and the general partner on its consolidated

statements of income, was $0.7 million and $0.5 million for the three months ended June 30, 2007 and 2006, respectively, and $1.2 million and $0.6 million for the six months ended June 30, 2007 and 2006, respectively. If converted to common units, the preferred equity amount converted will be reclassified to common unit equity within partners’ capital on the Partnership’s consolidated balance sheet. Dividends accrued and paid on the preferred units and the premium paid upon their redemption, if any, will be recognized as a reduction to the Partnership’s net income in determining net income attributable to common unitholders and the general partner.

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

NOTE 5 – CASH DISTRIBUTIONS

     The Partnership is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter. If distributions in any quarter exceed specified target levels, the general partner will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by the Partnership for the period from January 1, 2006 through June 30, 2007 were as follows:

				Cash				Total Cash
				Distribution				Distribution				Total Cash
Date Cash				per Common				to Common				Distribution
Distribution		For Quarter		Limited				Limited				to the General
Paid		Ended		Partner Unit				Partners				Partner
								(in thousands)				(in thousands)
February 14, 2006		December 31, 2005		$	0.83			$	10,416			$	3,638
May 15, 2006		March 31, 2006		$	0.84			$	10,541			$	3,766
August 14, 2006		June 30, 2006		$	0.85			$	11,118			$	4,059
November 14, 2006		September 30, 2006		$	0.85			$	11,118			$	4,059
February 14, 2007		December 31, 2006		$	0.86			$	11,249			$	4,193
May 15, 2007		March 31, 2007		$	0.86			$	11,249			$	4,193
August 14, 2007		June 30, 2007		$	0.87			$	11,380			$	4,326

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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

										Estimated
		June 30,				December 31,				Useful Lives
		2007				2006				in Years
Pipelines, processing and compression facilities		$	651,804			$	611,575				15 – 40
Rights of way			32,513				30,401				20 – 40
Buildings			4,078				3,800				40
Furniture and equipment			3,524				3,288				3 – 7
Other			2,538				2,081				3 – 10
			694,457				651,145
Less – accumulated depreciation			(55,978	)			(44,048	)
		$	638,479			$	607,097

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

NOTE 7 – OTHER ASSETS

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

		June 30, 2007				December 31, 2006
Deferred finance costs, net of accumulated amortization of $5,040 and $3,972 at June 30, 2007 and December 31, 2006, respectively		$	12,133			$	12,530
Security deposits			1,296				1,415
Other			35				97
		$	13,464			$	14,042

     Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 10).

NOTE 8 – ACQUISITIONS

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

Cash and cash equivalents		$	16,215
Accounts receivable			11,091
Prepaid expenses			497
Property, plant and equipment			232,576
Other assets			140
Total assets acquired			260,519
Accounts payable and accrued liabilities			(50,689	)
Net assets acquired			209,830
Less: Cash and cash equivalents acquired			(16,215	)
Net cash paid for acquisitions		$	193,615

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

NOTE 9 — DERIVATIVE INSTRUMENTS

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

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

     Derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive (loss) income, and reclassifies them to natural gas and liquids revenue within natural gas and liquids revenue in its consolidated statements of income as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss) in its consolidated statements of income as they occur. At June 30, 2007 and December 31, 2006, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $58.4 million and $20.1 million, respectively. Of the $29.5 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at June 30, 2007, if the fair values of the instruments remain at current market values, the Partnership will reclassify $22.4 million of losses to natural gas and liquids revenue in its consolidated statements of income over the next twelve month period as these contracts expire, and $7.1 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes.

     On June 3, 2007, the Partnership signed definitive agreements to acquire control of certain natural gas gathering systems and processing plants located in Oklahoma and Texas (see Note 15). In connection with certain additional agreements entered into to finance this transaction, the Partnership agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, the Partnership entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreements. The production volume of the assets to be acquired was

not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, the Partnership recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in its consolidated statements of income. The Partnership recognized a non-cash loss of $19.8 million related to the change in value of these derivatives for the three and six months ended June 30, 2007. Upon closing of the acquisition in July 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and the Partnership evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

     Ineffective hedge gains or losses are recorded within other income (loss) in the Partnership’s consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. The Partnership recognized losses of $7.7 million and $3.2 million for the three months ended June 30, 2007 and 2006, respectively, and losses of $10.7 million and $5.6 million for the six months ended June 30, 2007 and 2006, respectively, within natural gas and liquids revenue in its consolidated statements of income related to the settlement of qualifying hedge instruments. The Partnership recognized losses of $18.8 million and $9.7 million within other income (loss) in its consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the three months ended June 30, 2007. The Partnership recognized losses of $20.1 million and $10.7 million within other income (loss) in its consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the six months ended June 30, 2007. The losses recognized related to the change in market value of non-qualifying derivatives during the three and six months ended June 30, 2007 were principally due to derivative instruments entered into to hedge the projected production of the acquisition mentioned previously (see Note 15). The Partnership recognized gains of $0.4 million and $0.9 million for the three and six months ended June 30, 2006, respectively, within other income (loss) in its consolidated statements of income related to the change in market value of the ineffective portion of qualifying derivatives only. For the three and six months ended June 30, 2006, the Partnership did not have any non-qualifying derivatives.

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

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

     Natural Gas Liquids Sales

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(1)
		(gallons)				(per gallon)				(in thousands)
2007			57,204,000			$	0.893			$	(8,605	)
2008			33,012,000				0.697				(7,511	)
2009			8,568,000				0.746				(1,110	)
										$	(17,226	)

     Crude Oil Sales Options (associated with NGL volume)

Production						Associated				Average
Period		Crude				NGL				Crude				Fair Value
Ended December 31,		Volume				Volume				Strike Price				Asset/(Liability)(2)				Option Type
		(barrels)				(gallons)				(per barrel)				(in thousands)
2007			1,275,000				78,681,000			$	60.00			$	782			Puts purchased
2007			1,275,000				78,681,000				75.18				(2,543	)		Calls sold
2008			4,269,600				260,692,000				60.00				12,546			Puts purchased
2008			4,269,600				260,692,000				79.20				(17,100	)		Calls sold
2009			4,752,000				290,364,000				60.00				19,667			Puts purchased
2009			4,752,000				290,364,000				78.68				(25,638	)		Calls sold
2010			2,413,500				149,009,000				60.00				11,104			Puts purchased
2010			2,413,500				149,009,000				77.28				(14,296	)		Calls sold
														$	(15,478	)

     Natural Gas Sales

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(2)
		(mmbtu)(3)				(per mmbtu) (3)				(in thousands)
2007			540,000			$	7.255			$	(40	)
2008			240,000				7.270				(266	)
2009			480,000				8.000				(265	)
										$	(571	)

     Natural Gas Basis Sales

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Asset/(Liability)(2)
		(mmbtu)(3)				(per mmbtu)(3)				(in thousands)
2007			2,820,000			$	(0.771	)		$	(157	)
2008			4,440,000				(0.671	)			(294	)
2009			4,920,000				(0.558	)			(215	)
2010			2,220,000				(0.575	)			33
										$	(633	)

     Natural Gas Purchases

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(2)
		(mmbtu)(3)				(per mmbtu)(3)				(in thousands)
2007			5,460,000			$	8.593	(4)		$	(8,582	)
2008			11,016,000				8.951	(5)			(6,626	)
2009			10,320,000				8.687				(1,390	)
2010			4,380,000				8.635				(515	)
										$	(17,113	)

     Natural Gas Basis Purchases

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(2)
		(mmbtu)(3)				(per mmbtu)(3)				(in thousands)
2007			7,740,000			$	(1.036	)		$	(73	)
2008			15,216,000				(1.125	)			(599	)
2009			14,760,000				(0.659	)			(1,299	)
2010			6,600,000				(0.560	)			(1,188	)
										$	(3,159	)

     Crude Oil Sales

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(2)
		(barrels)				(per barrel)				(in thousands)
2007			37,700			$	56.249			$	(561	)
2008			65,400				59.424				(842	)
2009			33,000				62.700				(321	)
										$	(1,724	)

     Crude Oil Sales Options

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Strike Price				Asset/(Liability)(2)				Option Type
		(barrels)				(per barrel)				(in thousands)
2007			324,600				60.000				223			Puts purchased
2007			324,600				75.256				(656	)		Calls sold
2008			691,800				60.000				1,804			Puts purchased
2008			691,800				78.004				(3,025	)		Calls sold
2009			738,000				60.000				3,045			Puts purchased
2009			738,000				80.622				(3,549	)		Calls sold
2010			402,000				60.000				1,753			Puts purchased
2010			402,000				79.341				(1,947	)		Calls sold
2011			30,000				60.000				164			Puts purchased
2011			30,000				74.500				(223	)		Calls sold
2012			30,000				60.000				177			Puts purchased
2012			30,000				73.900				(237	)		Calls sold
										$	(2,471	)
						Total net liability				$	(58,375	)

NOTE 10 — DEBT

     Total debt consists of the following (in thousands):

		June 30,				December 31,
		2007				2006
Revolving credit facility		$	74,000			$	38,000
Senior notes			294,446				285,977
Other debt			57				106
			368,503				324,083
Less current maturities			(39	)			(71	)
		$	368,464			$	324,012

Credit Facility

     The Partnership has a $225.0 million credit facility with a syndicate of banks which matures in June 2011. The credit facility bears interest, at the Partnership’s option, at either (i) adjusted LIBOR plus the

applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2007 was 7.6%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.1 million was outstanding at June 30, 2007. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnership’s property and that of its wholly-owned subsidiaries, and by the guaranty of each of its wholly-owned subsidiaries. The credit facility contains customary covenants, including restrictions on the Partnership’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. The Partnership is in compliance with these covenants as of June 30, 2007.

     The events which constitute an event of default for the Partnership’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against the Partnership in excess of a specified amount, and a change of control of the Partnership’s General Partner. The credit facility requires the Partnership to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of not more than 4.0 to 1.0; a funded debt (as defined in the credit facility) to EBITDA 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 3.0 to 1.0. The credit facility defines EBITDA to include pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions. As of June 30, 2007, the Partnership’s ratio of senior secured debt to EBITDA was 1.0 to 1.0, its funded debt ratio was 4.6 to 1.0 and its interest coverage ratio was 3.4 to 1.0.

     The Partnership is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

Senior Notes

     At June 30, 2007, the Partnership has $293.5 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time on or after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The Senior Notes are also redeemable at any time prior to December 15, 2010 at stated redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, prior to December 15, 2008, the Partnership may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Partnership at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under the Credit Facility.

     On April 18, 2007, the Partnership issued Sunlight Capital $8.5 million of its Senior Notes in consideration of their consent to the amendment of the Partnership’s preferred units agreement (see Note 4). The Partnership filed, pursuant to the Registration Rights Agreement, an exchange offer registration statement to exchange the Notes for publicly tradable notes. The registration statement was declared effective by the SEC on July 17, 2007. The Partnership must complete the exchange offer by September 15, 2007 or, if it fails to do so, the Notes will accrue additional interest of 1% per annum for each 90-day period the Partnership is in default, up to a maximum amount of 3% per annum.

     The indenture governing the Senior Notes contains covenants, including limitations of the Partnership’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire

equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Partnership is in compliance with these covenants as of June 30, 2007.

NOTE 11 — COMMITMENTS AND CONTINGENCIES

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

     As of June 30, 2007, the Partnership is committed to expend approximately $76.9 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 12 — STOCK COMPENSATION

Long-Term Incentive Plan

     The Partnership has a Long-Term Incentive Plan (“LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The Plan is administered by a committee (the “Committee”) appointed by General Partner’s managing board. The Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the LTIP through June 30, 2007.

     A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the Committee, cash equivalent to the fair market value of a common unit. In addition, the Committee may grant a participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase the Partnership’s common limited partner units at an exercise price determined by the Committee at its discretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of the General Partner, the Committee will determine the vesting period for phantom units and the exercise period for options. Through June 30, 2007, phantom units granted under the LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the LTIP. Of the units outstanding under the LTIP at June 30, 2007, 88,914 units will vest within the following twelve months. All units outstanding under the LTIP at June 30 2007 include DERs granted to the participants by the Committee. The amounts paid with respect to DERs were $0.2 million and $0.1 million during the three months ended June 30, 2007 and 2006, respectively, and $0.3 million and $0.2 million during the six months ended June 30, 2007 and 2006, respectively. These amounts were recorded as reductions of Partners’ Capital on the consolidated balance sheet.

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

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Outstanding, beginning of period			183,859				110,856				159,067				110,128
Granted(1)			303				363				25,095				1,091
Matured			—				—				—				—
Forfeited			—				—				—				—
Outstanding, end of period			184,162				111,219				184,162				111,219
Non-cash compensation expense recognized (in thousands)		$	973			$	321			$	1,874			$	844

     At June 30, 2007, the Partnership had approximately $3.9 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIP based upon the fair value of the awards.

Incentive Compensation Agreements

     The Partnership has incentive compensation agreements which have granted awards to certain key personnel retained from previously consummated acquisitions. These individuals are entitled to receive common units of the Partnership upon the vesting of the awards, which is dependent upon the achievement of certain predetermined performance targets. These performance targets include the accomplishment of specific financial goals for the Partnership’s Velma system through September 30, 2007 and the financial performance of other previous and future consummated acquisitions, including Elk City and NOARK, through December 31, 2008. The awards associated with the performance targets of the Velma system will vest on September 30, 2007, and awards associated with performance targets of other acquisitions will vest on December 31, 2008.

     The Partnership recognized compensation expense of $1.5 million and $0.9 million for the three months ended June 30, 2007 and 2006, respectively, and $2.4 million and $1.7 million for the six months ended June 30, 2007 and 2006, respectively, related to the vesting of awards under these incentive compensation agreements. Based upon management’s estimate of the probable outcome of the performance targets at June 30, 2007, 221,813 common unit awards are ultimately expected to be issued under these agreements. At June 30, 2007, the Partnership had approximately $1.1 million of unrecognized compensation expense related to the unvested portion of these awards based upon management’s estimate of performance target achievement. The Partnership follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

NOTE 13 — RELATED PARTY TRANSACTIONS

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

     The partnership agreement provides that the General Partner will determine the costs and expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner at its sole

discretion. The Partnership reimbursed the General Partner and its affiliates $0.8 million and $0.9 million for the three months ended June 30, 2007 and 2006, respectively, and $1.4 million and $1.6 million for six months ended June 30, 2007 and 2006, respectively, for compensation and benefits related to their executive officers. For the three months ended June 30, 2007 and 2006, direct reimbursements were $6.2 million and $6.6 million, respectively, and $12.2 million and $13.1 million for the six months ended June 30, 2007 and 2006, respectively, including certain costs that have been capitalized by the Partnership. The General Partner believes that the method utilized in allocating costs to the Partnership is reasonable.

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

NOTE 14 — OPERATING SEGMENT INFORMATION

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

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Mid-Continent
Revenue:
Natural gas and liquids		$	104,792			$	95,609			$	206,968			$	196,086
Transportation and compression			10,571				5,360				20,390				14,110
Other income (loss)			(28,506	)			414				(30,785	)			955
Total revenue and other income (loss)			86,857				101,383				196,573				211,151
Costs and expenses:
Natural gas and liquids			87,102				77,006				174,912				162,898
Plant operating			4,515				3,926				9,045				7,153
Transportation and compression			1,780				1,532				3,500				2,640
General and administrative			4,806				2,995				8,700				6,163
Minority interest in NOARK			—				(451	)			—				118
Depreciation and amortization			5,555				4,375				11,015				8,834
Total costs and expenses			103,758				89,383				207,172				187,806
Segment profit (loss)		$	(16,901	)		$	12,000			$	(10,599	)		$	23,345
Appalachia
Revenue:
Transportation and compression – affiliates		$	8,458			$	7,834			$	16,178			$	15,708
Transportation and compression – third parties			17				19				36				46
Other income			83				265				165				406
Total revenue and other income			8,558				8,118				16,379				16,160

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Costs and expenses:
Transportation and compression			1,430				1,317				2,822				2,285
General and administrative			1,300				1,035				2,520				1,919
Depreciation and amortization			1,116				883				2,190				1,699
Total costs and expenses			3,846				3,235				7,532				5,903
Segment profit		$	4,712			$	4,883			$	8,847			$	10,257
Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent		$	(16,901	)		$	12,000			$	(10,599	)		$	23,345
Appalachia			4,712				4,883				8,847				10,257
Total segment profit (loss)			(12,189	)			16,883				(1,752	)			33,602
Corporate general and administrative expenses			(1,300	)			(1,036	)			(2,519	)			(1,919	)
Interest expense			(7,327	)			(6,154	)			(14,086	)			(12,491	)
Net income (loss)		$	(20,816	)		$	9,693			$	(18,357	)		$	19,192
Capital Expenditures:
Mid-Continent		$	22,017			$	17,777			$	37,606			$	27,198
Appalachia			3,001				4,473				5,789				8,614
		$	25,018			$	22,250			$	43,395			$	35,812