Edgar Filing: ATLAS PIPELINE PARTNERS LP

e10vq

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, 2006


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

For the transition period from to

Commission file number:1-4998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


DELAWARE (State or other jurisdiction of incorporation or organization)		23-3011077 (I.R.S. Employer Identification No.)


311 Rouser 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, 2006 and December 31, 2005 (Unaudited)		3

Consolidated Statements of Income for the Three and Six Months Ended June 30, 2006 and 2005 (Unaudited)		4

Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2006 (Unaudited)		5

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005 (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		37

Item 4. Controls and Procedures		40

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 6. Exhibits		40

SIGNATURES		42
Second Amendment to Revolving Credit and Term Loan Agreement
Third Amendment to Revolving Credit and Term Loan Agreement
Statement of Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certifications
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications
Section 1350 Certifications

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	June 30,			December 31,
	2006			2005
ASSETS

Current assets:
Cash and cash equivalents	$	12,561		$	34,237
Accounts receivable — affiliates		4,335			4,649
Accounts receivable		44,647			57,528
Current portion of hedge asset		1,644			11,388
Prepaid expenses and other		6,942			2,454

Total current assets		70,129			110,256

Property, plant and equipment, net		472,535			445,066

Long-term hedge asset		467			4,388

Intangible assets, net		52,546			54,869

Goodwill		141,209			111,446

Other assets, net		15,028			16,701

	$	751,914		$	742,726


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Current portion of long-term debt	$	107		$	1,263
Accounts payable		4,109			15,609
Accrued liabilities		17,377			16,064
Current portion of hedge liability		20,233			23,796
Accrued producer liabilities		28,347			36,712

Total current liabilities		70,173			93,444

Long-term hedge liability		24,901			22,410

Long-term debt, less current portion		286,088			297,362

Commitments and contingencies

Partners’ capital:
Preferred limited partner’s interest		38,207			—
Common limited partners’ interests		364,073			349,491
General partner’s interest		11,396			10,094
Accumulated other comprehensive loss		(42,924	)		(30,075	)

Total partners’ capital		370,752			329,510

	$	751,914		$	742,726

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006			2005		2006			2005
Revenue:
Natural gas and liquids	$	96,006		$	79,700	$	197,023		$	122,034
Transportation and compression — affiliates		7,834			5,352		15,708			10,199
Transportation and compression — third parties		5,379			23		14,156			38
Interest income and other		282			124		424			205

Total revenue and other income		109,501			85,199		227,311			132,476


Costs and expenses:
Natural gas and liquids		77,006			66,582		162,898			102,041
Plant operating		3,926			3,293		7,153			4,497
Transportation and compression		3,134			622		5,456			1,298
General and administrative		3,896			3,357		7,865			5,332
Compensation reimbursement — affiliates		885			440		1,605			953
Depreciation and amortization		5,258			3,128		10,533			5,057
Interest		6,154			4,177		12,491			5,312
Minority interest in NOARK		(451	)		—		118			—
Other		—			11		—			147

Total costs and expenses		99,808			81,610		208,119			124,637


Net income		9,693			3,589		19,192			7,839
Preferred unit imputed dividend cost		(540	)		—		(635	)		—

Net income attributable to common limited partners and the general partner	$	9,153		$	3,589	$	18,557		$	7,839


Allocation of net income attributable to common limited partners and the general partner:
Common limited partners’ interest	$	5,299		$	1,573	$	11,105		$	4,403
General partner’s interest		3,854			2,016		7,452			3,436

Net income attributable to common limited partners and the general partner	$	9,153		$	3,589	$	18,557		$	7,839


Net income attributable to common limited partners per unit:
Basic	$	0.41		$	0.20	$	0.88		$	0.58

Diluted	$	0.41		$	0.20	$	0.87		$	0.58


Weighted average common limited partner units outstanding:
Basic		12,824			7,938		12,687			7,573

Diluted		12,979			7,990		12,833			7,609

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED JUNE 30, 2006

(in thousands, except unit data)

(Unaudited)


													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, 2006		—		12,549,266	$	—	$	349,491		$	10,094		$	(30,075	)	$	329,510
Issuance of common units		—		500,000		—		19,769			—			—			19,769
Issuance of 6.5% cumulative convertible preferred limited partner units		40,000		—		37,572		—			—			—			37,572
Preferred dividend discount		—		—		—		2,350			48			—			2,398
General partner capital contribution		—		—		—		—			1,206			—			1,206
Unissued common units under incentive plans		—		—		—		2,502			—			—			2,502
Distributions paid to common limited partners and the general partner		—		—		—		(20,958	)		(7,404	)		—			(28,362	)
Distribution equivalent rights paid on unissued units under incentive plans		—		—		—		(186	)		—			—			(186	)
Other comprehensive loss		—		—		—		—			—			(12,849	)		(12,849	)
Net income		—		—		635		11,105			7,452			—			19,192

Balance at June 30, 2006		40,000		13,049,266	$	38,207	$	364,073		$	11,396		$	(42,924	)	$	370,752

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	19,192		$	7,839
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10,533			5,057
Non-cash gain on derivative value		(256	)		(701	)
Non-cash compensation expense		2,502			2,158
Amortization of deferred finance costs		1,205			1,475
Minority interest in NOARK		118			—
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		8,577			(9,973	)
Accounts payable and accrued liabilities		(18,249	)		18,816
Accounts payable and accounts receivable – affiliates		314			(1,992	)

Net cash provided by operating activities		23,936			22,679


CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		(30,000	)		(195,622	)
Capital expenditures		(35,812	)		(22,883	)
Other		159			177

Net cash used in investing activities		(65,653	)		(218,328	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of debt		36,655			—
Repayment of debt		(39,000	)		—
Borrowings under credit facility		9,500			256,000
Repayments under credit facility		(19,000	)		(142,250	)
Net proceeds from issuance of common limited partner units		19,769			91,661
Net proceeds from issuance of preferred limited partner units		39,970			—
General partner capital contribution		1,206			1,930
Distributions paid to common limited partners and the general partner		(28,362	)		(13,372	)
Other		(697	)		(3,192	)

Net cash provided by financing activities		20,041			190,777


Net change in cash and cash equivalents		(21,676	)		(4,872	)
Cash and cash equivalents, beginning of period		34,237			18,214

Cash and cash equivalents, end of period	$	12,561		$	13,342

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded Delaware limited partnership formed to acquire, own and operate natural gas gathering systems previously owned by Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS). 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 (a wholly-owned subsidiary of Atlas America (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 (see Note 15). 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 yet 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, 2006, the Partnership had 13,049,266 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).

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2005 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, 2005. The results of operations for the three and six month period ended June 30, 2006 may not necessarily be indicative of the results of operations for the full year ending December 31, 2006.

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. Management of the Partnership believes that the impact of these adjustments is immaterial to its current and prior financial statements.

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, 2005.

Principles of Consolidation and Minority Interest

The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and the Operating Partnership’s 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% operating interest (see Note 8). On May 2, 2006, the Partnership acquired the remaining 25% equity 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% equity ownership interest in NOARK, which was acquired in October 2005 from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE). In connection with this acquisition, Southwestern acquired the issuer of the NOARK notes and assumed liability of $39.0 million in principal amount outstanding of 7.15% notes due in 2018, which had been presented as long-term debt on the Partnership’s consolidated balance sheet. The Partnership consolidates 100% of NOARK’s financial statements. The minority interest expense reflected on the Partnership’s consolidated statements of income represents Southwestern’s 25% ownership interest in NOARK’s net income before interest expense and interest expense related to NOARK’s long-term debt prior to the May 2, 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.

The natural gas industry principally conducts it 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, 2006 represent actual results in all material respects (see Revenue Recognition accounting policy for further description).

Net Income Per Common Unit

Basic net income attributable to common limited partners per unit is computed by dividing net income attributable to common limited partners, which is after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income attributable to common limited partners and the general partner is calculated on a quarterly basis based upon its 2% interest and incentive distributions (see Note 5). 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. 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 to 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,
	2006		2005		2006		2005
Weighted average number of common limited partner units – basic		12,824		7,938		12,687		7,573

Add: effect of dilutive unit incentive awards		155		52		146		36


Weighted average number of common limited partner units – diluted		12,979		7,990		12,833		7,609

For the three and six months ended June 30, 2006, potential common limited partner units issuable upon conversion of our 40,000 $1,000 par value cumulative convertible preferred limited partner units were excluded from the computation of diluted net income attributable to common limited partners because the impact of the conversion would be 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 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, are referred to as “other comprehensive income (loss)” and include only changes in the fair value of unsettled hedging 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,
	2006			2005			2006			2005
Net income	$	9,693		$	3,589		$	19,192		$	7,839

Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as hedges		(18,845	)		(10,947	)		(18,471	)		(19,885	)
Add: reclassification adjustment for losses in net income		3,222			1,262			5,622			1,931

Total other comprehensive loss		(15,623	)		(9,685	)		(12,849	)		(17,954	)

Comprehensive income (loss)	$	(5,930	)	$	(6,096	)	$	6,343		$	(10,115	)

Revenue Recognition

Revenue in the Appalachia segment is recognized at the time the natural gas is transported through the gathering systems. Under the terms of its natural gas gathering agreements with Atlas America and its affiliates, the Partnership receives fees for gathering natural gas from wells owned by Atlas America and by drilling investment partnerships sponsored by Atlas America. The fees received for the gathering services under the Atlas America agreements are generally the greater of 16% of the gross sales price for gas produced from the wells, or $0.35 or $0.45 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantially all gas gathering revenue is derived under 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. The Partnership either 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, or the Partnership transports natural gas across its systems, from receipt to delivery point, without taking title to the 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. The majority of the revenue associated with the Partnership’s gathering and processing operations are based on percentage-of-proceeds (“POP”) and fixed-fee contracts. Under its POP purchasing arrangements, the Partnership purchases natural gas at the wellhead, processes the natural gas by extracting NGLs and removing impurities and sells the residue gas and NGLs at market-based prices, remitting to producers a contractually-determined percentage of the sale proceeds.

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, 2006 and December 31, 2005 of $36.6 million and $48.4 million, respectively, included in accounts receivable and accounts receivable-affiliates within its consolidated balance sheets.

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 8.1% for both the three and six months ended June 30, 2006, and the amount of interest capitalized was $0.6 million and $1.0 million for the three and six months ended June 30, 2006, respectively. There were no interest amounts capitalized for the three and six months ended June 30, 2005.

Intangible Assets

The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions (see Note 8). Certain amounts included within these intangible assets categories are based upon the preliminary purchase price allocation for NOARK, which is subject to adjustment and could change significantly as the Partnership continues to evaluate this allocation. The following table reflects the components of intangible assets being amortized at June 30, 2006 and December 31, 2005 (in thousands):


							Estimated
	June 30,			December 31,			Useful Lives
	2006			2005			In Years
Gross Carrying Amount:
Customer contracts	$	23,990		$	23,990			8
Customer relationships		32,960			32,960			20

	$	56,950		$	56,950


Accumulated Amortization:
Customer contracts	$	(2,838	)	$	(1,339	)
Customer relationships		(1,566	)		(742	)

	$	(4,404	)	$	(2,081	)


Net Carrying Amount:
Customer contracts	$	21,152		$	22,651
Customer relationships		31,394			32,218

	$	52,546		$	54,869

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. Customer contract and customer relationship intangible assets are amortized on a straight-line basis. Amortization expense on intangible assets was $1.2 million and $2.3 million for the three and six months ended June 30, 2006, respectively. There was no amortization expense on intangible assets recorded during the three and six months ended June 30, 2005. Amortization expense related to intangible assets is estimated to be $4.6 million for each of the next five calendar years commencing in 2006.

Goodwill

At June 30, 2006 and December 31, 2005, the Partnership had $141.2 million and $111.4 million, respectively, 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, 2006 and 2005 were as follows (in thousands):


	Six Months Ended
	June 30,
	2006			2005
Balance, beginning of period	$	111,446		$	2,305
Goodwill acquired – Elk City acquisition		—			60,000
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	$	141,209		$	62,305

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, “Goodwill and Other Intangible Assets,” 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, 2005 resulted in no impairment, and no impairment indicators have been noted as of June 30, 2006. 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.

NOTE 3 — COMMON UNIT EQUITY OFFERINGS

On May 12, 2006, the Partnership sold 500,000 common units to Wachovia Securities, which has 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 $19.8 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 recent acquisition of the remaining 25% interest in NOARK. Subsequent to this transaction, the Partnership had 13,049,266 common limited partner units outstanding.

In November 2005, the Partnership sold 2,700,000 of its common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, the Partnership sold an additional 330,000 common units in December 2005 for gross proceeds of $13.9 million, resulting in aggregate total gross proceeds of $127.3 million. The units, which were issued under the Partnership’s previously filed shelf registration statement, resulted in total net proceeds of approximately $121.0 million, after underwriting commissions and other transaction costs. The Partnership primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

In June 2005, the Partnership sold 2,300,000 common units in a public offering for total gross proceeds of $96.5 million. The units, which were issued under the Partnership’s previously filed shelf registration statement, resulted in net proceeds of approximately $91.7 million, after underwriting commissions and other transaction costs. The Partnership primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

NOTE 4 — PREFERRED UNIT EQUITY OFFERING

On March 13, 2006, the Partnership sold 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC, an affiliate of Elliott & Associates, for aggregate proceeds of $30.0 million. The Partnership also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital Partners for $10.0 million on May 19, 2006, pursuant to the Partnership’s right to require Sunlight Capital Partners to purchase such additional units under the purchase agreement with Sunlight. The preferred units are entitled to receive dividends of 6.5% per annum commencing on March 13, 2007, which will accrue and be paid quarterly on the same date as the distribution payment date for the Partnership’s common units. The preferred units are convertible, at the holder’s option, into the Partnership’s common units commencing on the date immediately following the first record date after March 13, 2007 at a conversion price equal to the lesser of $41.00 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 Partnership has agreed to file a registration statement to cover the resale of the common units underlying the preferred units. The net proceeds from the initial issuance of the preferred units will be 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% interest in NOARK.

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 recorded on the consolidated balance sheet at the amount of net proceeds received less an imputed dividend cost. The imputed dividend cost is the result of the preferred units not having a dividend yield during the first year after their issuance on March 13, 2006. The total imputed dividend cost of $2.4 million on the preferred units, including the $0.5 million of imputed dividend cost related to the additional 10,000 units, was allocated to common limited partners’ and the general partner’s interests within partner’s capital on the consolidated balance sheet and is based upon the present value of the net proceeds received using the 6.5% stated yield commencing March 13, 2007. The imputed dividend cost will be amortized for the period from the respective issuances of the preferred units through March 13, 2007, and the amortization will be presented as a reduction of net income to determine net income attributable to common limited partners and the general partner. Amortization of the imputed dividend cost for the three and six months ended June 30, 2006 was $0.5 million and $0.6 million, respectively. 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. If converted to common units, the preferred equity amount converted will be reclassified to common limited partners’ equity within Partners’ Capital on the Partnership’s consolidated balance sheet.

NOTE 5 — CASH DISTRIBUTIONS

The Partnership is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) to its common unitholders and the General Partner for that quarter. If common unit distributions in any quarter exceed specified target levels, the general partner will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by the Partnership for the period from January 1, 2005 through June 30, 2006 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 11, 2005	December 31, 2004	$	0.72	$	5,187	$	1,280
May 13, 2005	March 31, 2005	$	0.75	$	5,404	$	1,500
August 5, 2005	June 30, 2005	$	0.77	$	7,319	$	2,174
November 14, 2005	September 30, 2005	$	0.81	$	7,711	$	2,565

February 14, 2006	December 31, 2005	$	0.83	$	10,416	$	3,638
May 15, 2006	March 31, 2006	$	0.84	$	10,541	$	3,766

On July 26, 2006, the Partnership declared a cash distribution of $0.85 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2006. The $15.1 million distribution, including $4.0 million to the General Partner, will be paid on August 14, 2006 to unitholders of record at the close of business on August 7, 2006.

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
	2006			2005			In Years
Pipelines, processing and compression facilities	$	475,852		$	443,729			15 – 40
Rights of way		20,465			19,252			20 – 40
Buildings		3,621			3,350			40
Furniture and equipment		2,892			1,525			3 – 7
Other		1,499			889			3 – 10

		504,329			468,745
Less – accumulated depreciation		(31,794	)		(23,679	)

	$	472,535		$	445,066

On May 2, 2006, the Partnership acquired the remaining 25% interest in NOARK for $69.0 million in cash, including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition (see Note 10). The Partnership acquired the initial 75% interest in NOARK for approximately $179.8 million in October 2005 (see Note 8). Due to the recent date of both acquisitions, the purchase price allocation is based upon estimated values, which are subject to adjustment and could change significantly as the Partnership

continues to evaluate this preliminary allocation. At June 30, 2006 and December 31, 2005, the portion of the purchase price allocated to property, plant and equipment for NOARK was included within pipelines, processing and compression facilities.

NOTE 7 — OTHER ASSETS

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


	June 30,		December 31,
	2006		2005
Deferred finance costs, net of accumulated amortization of $2,879 and $1,636 at June 30, 2006 and December 31, 2005, respectively	$	13,465	$	15,034
Security deposits		1,533		1,599
Other		30		68

	$	15,028	$	16,701

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

NOTE 8 — ACQUISITIONS

NOARK

On May 2, 2006, the Partnership acquired the remaining 25% equity ownership interest in NOARK from Southwestern, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN), 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, which was funded through borrowings under the Partnership’s senior secured credit facility. 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% interest in NOARK, for total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. The Partnership funded this acquisition through borrowings under its senior secured credit facility. 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 preliminary 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		126,307
Other assets		140
Intangible assets – customer contracts		11,600
Intangible assets – customer relationships		15,700
Goodwill		78,969

Total assets acquired		260,519
Accounts payable and other liabilities		(50,689	)

Net assets acquired		209,830
Less: Cash and cash equivalents acquired.		(16,215	)

Net cash paid for acquisitions	$	193,615

Due to the recent date of both acquisitions, the purchase price allocation for NOARK is based upon preliminary data that is subject to adjustment and could change significantly as the Partnership continues to evaluate this allocation. The Partnership recorded goodwill in connection with these acquisitions as a result of NOARK’s significant cash flow and its strategic industry and geographic position. 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 date of the acquisition.

Elk City

In April 2005, the Partnership acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $196.0 million, including related transaction costs. Elk City’s principal assets included approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma and a gas treatment facility in Prentiss, Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):


Accounts receivable	$	5,587
Other assets		497
Property, plant and equipment		104,106
Intangible assets – customer contracts		12,390
Intangible assets – customer relationships		17,260
Goodwill		61,136

Total assets acquired		200,976

Accounts payable and accrued liabilities		(4,970	)

Net assets acquired	$	196,006

The Partnership recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. Elk City’s results of operations are included within the Partnership’s consolidated financial statements from its date of acquisition.

The following data presents pro forma revenue and net income for the Partnership as if the acquisitions discussed above, the equity offerings in May 2006, November 2005 and June 2005 (see Note 3), the May 2006 and December 2005 issuances of senior notes (see Note 10), and the May 2006 and March 2006 issuances of the cumulative convertible preferred units (see Note 4) had occurred on January 1, 2005. The Partnership has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if the Partnership had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per unit data):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Total revenue and other income	$	109,501	$	102,995	$	227,311	$	208,966
Net income	$	9,327	$	3,583	$	19,382	$	4,745
Net income attributable to common limited partners and the general partner	$	8,864	$	3,583	$	18,468	$	3,831

Net income attributable to common limited partners per unit:
Basic	$	0.38	$	0.12	$	0.84	$	0.04
Diluted	$	0.38	$	0.12	$	0.84	$	0.04

NOTE 9 — DERIVATIVE INSTRUMENTS

The Partnership enters into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), 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 a fixed price and remits a floating price based on certain indices for the relevant contract period.

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 natural gas futures and options 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 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 income (loss), and reclassifies them to natural gas and liquids revenue within the 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 its consolidated statements of income as they occur. At June 30, 2006 and December 31, 2005, the Partnership reflected net hedging liabilities on its consolidated balance sheets of $43.0 million and $30.4 million, respectively. Of the $42.9 million of net loss in accumulated other comprehensive loss at June 30, 2006, if the fair value of the instruments remain at current market values, the Partnership will reclassify $18.7 million of losses to its consolidated statements of income over the next twelve month period as these contracts expire, and $24.2 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within natural gas and liquids revenue 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 $3.2 million and $1.3 million for the three months ended June 30, 2006 and

2005, respectively, and losses of $5.6 million and $1.9 million for the six months ended June 30, 2006 and 2005, respectively, within its consolidated statements of income related to the settlement of qualifying hedge instruments. The Partnership also recognized gains of $0.4 million and $0.3 million for the three months ended June 30, 2006 and 2005, respectively, and gains of $0.9 million and $0.1 million for the six months ended June 30, 2006 and 2005, respectively, within its consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

A portion of the Partnership’s future natural gas 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 revenue.

As of June 30, 2006, the Partnership had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Sales


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽¹⁾
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		31,122,000	$	0.758	$	(9,751	)
2007		36,036,000		0.717		(12,238	)
2008		33,012,000		0.697		(11,491	)
2009		8,568,000		0.746		(2,750	)

					$	(36,230	)

Natural Gas Sales


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		500,000	$	7.019	$	(194	)
2007		1,080,000		7.255		(2,080	)
2008		240,000		7.270		(487	)

					$	(2,761	)

Natural Gas Basis Sales


Production			Average			Fair Value
Period	Volumes		Fixed Price			Asset⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		600,000	$	(0.525	)	$	376
2007		1,080,000		(0.535	)		739
2008		240,000		(0.555	)		146

						$	1,261

Natural Gas Purchases


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		1,800,000	$	7.857	$	(810	)

					$	(810	)

Natural Gas Basis Purchases


Production			Average			Fair Value
Period	Volumes		Fixed Price			Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		2,160,000	$	(0.781	)	$	(738	)

						$	(738	)

Crude Oil Sales


Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		35,400	$	52.956	$	(776	)
2007		80,400		56.069		(1,613	)
2008		62,400		59.267		(933	)
2009		36,000		62.700		(335	)

					$	(3,657	)

Crude Oil Sales Options


Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)			Option Type
2006		6,600	$	60.000	$	—		Puts purchased
2006		6,600		73.380		(10	)	Calls sold
2007		13,200		60.000		—		Puts purchased
2007		13,200		73.380		(36	)	Calls sold
2008		17,400		60.000		—		Puts purchased
2008		17,400		72.807		(19	)	Calls sold
2009		30,000		60.000		—		Puts purchased
2009		30,000		71.250		(23	)	Calls sold

					$	(88	)

			Total net liability		$	(43,023	)


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

⁽²⁾		MMBTU represents million British Thermal Units.

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

NOTE 10 — DEBT

Total debt consists of the following (in thousands):


	June 30,			December 31,
	2006			2005
Revolving Credit Facility	$	—		$	9,500
Senior Notes		286,032			250,000
NOARK Notes		—			39,000
Other debt		163			125

		286,195			298,625
Less current maturities		(107	)		(1,263	)

	$	286,088		$	297,362

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). There were no amounts outstanding under the credit facility at June 30, 2006. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at June 30, 2006. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnership’s property and that of its subsidiaries, and by the guaranty of each of its 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, 2006.

The events which constitute an event of default are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against us in excess of a specified amount, and a change of control of our general partner.

The credit facility requires 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, 2006, the Partnership’s ratio of senior secured debt to EBITDA was 0.1 to 1.0, its funded debt ratio was 3.2 to 1.0 and its interest coverage ratio was 4.1 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

In December 2005, the Partnership and its subsidiary, Atlas Pipeline Finance Corp. (“APFC”), issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. In May 2006, the Partnership and APFC issued an additional $35.0 million of senior unsecured notes at 103% par value, with a resulting effective yield of approximately 7.6%, for net proceeds of approximately $36.7 million, including accrued interest and net of initial purchaser’s discount and other transaction costs. 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 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 for which the net proceeds are not reinvested into the Partnership 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.

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, 2006.

In connection with a Senior Notes registration rights agreement entered into by the Partnership, it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the Senior Notes by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission by July 18, 2006, and (c) cause the exchange offer to be consummated by August 17, 2006. If the Partnership does not meet the aforementioned deadlines, the Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the deadlines have been met. On April 19, 2006, the Partnership filed an exchange offer registration statement for the Senior Notes with the Securities and Exchange Commission, which was declared effective on July 11, 2006. Management of the Partnership expects to consummate the exchange offer by August 17, 2006 and thereby fulfill all of the requirements of the Senior Notes registration rights agreement by the specified dates.

NOARK Notes

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

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.

On March 9, 2004, the Oklahoma Tax Commission (“OTC”) filed a petition against Spectrum Field Services, Inc. (“Spectrum”) alleging that Spectrum, prior to its acquisition by the Partnership, underpaid gross production taxes beginning in June 2000. The OTC is seeking a settlement of $5.0 million plus interest and penalties. The Partnership plans on defending itself against this allegation vigorously. In addition, under the terms of the Spectrum purchase agreement, $14.0 million has been placed in escrow to cover the costs of any adverse settlement resulting from the petition and other indemnification obligations of the purchase agreement.

As of June 30, 2006, the Partnership is committed to expend approximately $25.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $9.2 million related to the Sweetwater gas plant, a new cryogenic gas processing plant the Partnership is constructing in Beckham County, Oklahoma. The Partnership expects the plant to be completed in third quarter of 2006.

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 the 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, 2006.

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, 2006, phantom units granted under the LTIP generally had vesting periods of four years. The vesting period may also include 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, 2006, 62,297 units will vest within the following twelve months. All units outstanding under the LTIP at June 30, 2006 include DERs granted to the participants by the Committee. The amounts paid with respect to DERs were $0.1 million for both the three months ended June 30, 2006 and 2005, respectively, and $0.2 million for both the six months ended June 30, 2006 and 2005, respectively. These amounts were recorded as reductions of Partners’ Capital on the consolidated balance sheet.

The Partnership has adopted SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), as of December 31, 2005. 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. Prior to the adoption of SFAS No. 123(R), the Partnership followed Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and its interpretations (“APB No. 25”), which SFAS No. 123(R) superseded. APB No. 25 allowed for valuation of share-based payments to employees at their intrinsic values. Under this methodology, the Partnership recognized compensation expense for phantom units granted only if the current market price of the underlying units exceeded the exercise price. Since the inception of the LTIP, the Partnership has only granted phantom units with no exercise price and, as such, recognized compensation expense based upon the fair value of the Partnership’s limited partner units. Since the Partnership has historically recognized compensation expense for its share-based payments at their fair values, the adoption of SFAS No. 123(R) did not have a material impact on its consolidated financial statements.

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
Outstanding, beginning of period		110,856		124,522			110,128		58,329
Granted⁽¹⁾		363		422			1,091		67,399
Matured		—		(14,226	)		—		(14,331	)
Forfeited		—		(340	)		—		(1,019	)

Outstanding, end of period		111,219		110,378			111,219		110,378


Non-cash compensation expense recognized (in thousands)	$	321	$	1,709		$	844	$	2,158


⁽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 $41.29 and $43.48 for awards granted for the three months ended June 30, 2006 and 2005, respectively, and $41.17 and $48.59 for awards granted for the six months ended June 30, 2006 and 2005, respectively.

At June 30, 2006, the Partnership had approximately $1.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIP based upon the fair value of the awards.

Incentive Compensation Agreements

The Partnership has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals 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 Spectrum 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 $0.9 million and $1.0 million for the three months ended June 30, 2006 and 2005, respectively, and $1.7 million and $1.0 million for the six months ended June 30, 2006 and 2005, respectively, related to the vesting of awards under these incentive compensation agreements, based upon the fair value of the 225,546 common unit awards expected to be issued as of June 30, 2006, which is based upon management’s estimate of the probable outcome of the performance targets at that date. At June 30, 2006, the Partnership had approximately $4.7 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 executive officers, 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

substantially all of their time to activities on the Partnership’s behalf. The Partnership reimburses Atlas America at cost for direct costs incurred by them on its 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 $0.9 million and $0.4 million for the three months ended June 30, 2006 and 2005, respectively, and $1.6 million and $1.0 million for six months ended June 30, 2006 and 2005, respectively, for compensation and benefits related to their executive officers. For the three months ended June 30, 2006 and 2005, direct reimbursements were $6.6 million and $7.6 million, respectively, and $13.1 million and $11.9 million for the six months ended June 30, 2006 and 2005, 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 America, Atlas America 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 America 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,
	2006			2005			2006			2005
Mid-Continent
Revenue:
Natural gas and liquids	$	96,006		$	79,700		$	197,023		$	122,034
Transportation and compression		5,360			—			14,110			—
Interest income and other		17			31			18			17

Total revenue and other income		101,383			79,731			211,151			122,051


Costs and expenses:
Natural gas and liquids		77,006			66,582			162,898			102,041
Plant operating		3,926			3,293			7,153			4,497
Transportation and compression		1,817			—			3,171			—
General and administrative		2,710			2,298			5,632			3,049
Minority interest in NOARK		(451	)		—			118			—
Depreciation and amortization		4,375			2,503			8,834			3,858

Total costs and expenses		89,383			74,676			187,806			113,445

Segment profit	$	12,000		$	5,055		$	23,345		$	8,606


Appalachia
Revenue:
Transportation and compression – affiliates	$	7,834		$	5,352		$	15,708		$	10,199
Transportation and compression – third parties		19			23			46			38
Interest income and other		265			93			406			188

Total revenues and other income		8,118			5,468			16,160			10,425


Costs and expenses:
Transportation and compression		1,317			622			2,285			1,298
General and administrative		1,035			741			1,919			1,609
Depreciation and amortization		883			625			1,699			1,199

Total costs and expenses		3,235			1,988			5,903			4,106

Segment profit	$	4,883			3,480		$	10,257		$	6,319


Reconciliation of segment profit to net income:
Segment profit
Mid-Continent	$	12,000		$	5,055		$	23,345		$	8,606
Appalachia		4,883			3,480			10,257			6,319

Total segment profit		16,883			8,535			33,602			14,925
Corporate general and administrative expenses.		(1,036	)		(758	)		(1,919	)		(1,627	)
Interest expense		(6,154	)		(4,177	)		(12,491	)		(5,312	)
Other		—			(11	)		—			(147	)

Net income	$	9,693		$	3,589		$	19,192		$	7,839


Capital Expenditures:
Mid-Continent	$	17,777		$	10,796		$	27,198		$	14,530
Appalachia		4,473			6,010			8,614			8,353

	$	22,250		$	16,806		$	35,812		$	22,883


	June 30,		December 31,
	2006		2005
Balance sheet
Total assets:
Mid-Continent	$	698,170	$	668,782
Appalachia		31,135		43,428
Corporate other		22,609		30,516

	$	751,914	$	742,726


Goodwill:
Mid-Continent	$	138,904	$	109,141
Appalachia		2,305		2,305

	$	141,209	$	111,446

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Natural gas and liquids:
Natural gas	$	42,083	$	44,067	$	99,597	$	67,724
NGLs		44,970		31,549		82,918		48,933
Condensate		2,201		1,494		3,523		2,221
Other ⁽¹⁾		6,752		2,590		10,985		3,156

Total	$	96,006	$	79,700	$	197,023	$	122,034


Transportation and compression:
Affiliates	$	7,834	$	5,352	$	15,708	$	10,199
Third parties		5,379		23		14,156		38

Total	$	13,213	$	5,375	$	29,864	$	10,237


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

NOTE 15 — SUBSEQUENT EVENT

On July 26, 2006, Atlas America contributed its ownership interests in Atlas Pipeline Partners GP, LLC, its wholly-owned subsidiary and the Partnership’s general partner, to Atlas Pipeline Holdings, L.P. (NYSE: AHD), a wholly-owned subsidiary of Atlas America. Concurrent with this transaction, Atlas Pipeline Holdings, L.P. issued 3,600,000 common units, representing a 17.1% ownership interest, in an initial public offering at a price of $23.00 per unit. The underwriters have been granted a 30-day option to purchase up to an additional 540,000 common units. Substantially all of the net proceeds from this offering will be distributed to Atlas America.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our annual report on Form 10-K for 2005. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

General

We are a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL.” We were formed to acquire, own and operate natural gas gathering systems previously owned by Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS). Our business is conducted in the midstream segment of the natural gas industry through two operating segments: our Mid-Continent operations and our Appalachian operations. Our principal business objective is to generate cash for distribution to our unitholders.

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

	•		a FERC-regulated, 565-mile interstate pipeline system, that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has throughput capacity of approximately 322 MMcf/d;

	•		two natural gas processing plants with aggregate capacity of approximately 230 MMcf/d and one treating facility with a capacity of approximately 200 MMcf/d, all located in Oklahoma; and

	•		1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas from wells and central delivery points in the Mid-Continent region to its natural gas processing plants or Ozark Gas Transmission.

Through our Appalachian operations, we own and operate 1,500 miles of intrastate natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us and Atlas America, the parent of our general partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, we gather substantially all of the natural gas for our Appalachian operations from wells operated by Atlas America.

Significant Acquisitions

Since our initial public offering in January 2000 through June 30, 2006, we have completed six acquisitions at an aggregate cost of approximately $590.1 million, including, most recently:

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

	•		In April 2005, we acquired all of the outstanding equity interests of Elk City for $196.0 million, including related transaction costs. Elk City’s principal assets include approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, a natural gas processing facility in Elk City, Oklahoma, with a total capacity of approximately 130 MMcf/d and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of approximately 200 MMcf/d.

Recent Development

On July 26, 2006, Atlas America contributed its ownership interests in Atlas Pipeline Partners GP, LLC, its wholly-owned subsidiary and our general partner, to Atlas Pipeline Holdings, L.P. (NYSE: AHD), a wholly-owned subsidiary of Atlas America. Concurrent with this transaction, Atlas Pipeline Holdings, L.P. issued 3,600,000 common units, representing a 17.1% ownership interest, in an initial public offering at a price of $23.00 per unit. The underwriters have been granted a 30-day option to purchase up to an additional 540,000 common units. Substantially all of the net proceeds from this offering will be distributed to Atlas America.

Contractual Revenue Arrangements

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

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

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

In Appalachia, substantially all of the natural gas we transport is for Atlas America under percentage of proceeds (“POP”) contracts, as described below, in which we earn a fee equal to a percentage, generally 16%, of the selling price of the gas subject, in most cases, to a minimum of $0.35 or $0.45 per thousand cubic feet, or mcf, depending upon the ownership of the well. Since our inception in January 2000, our Appalachian transportation fee has always exceeded this minimum in general. The balance of the Appalachian gas we transport is for third-party operators generally under fixed fee contracts.

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

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

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

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

Keep-Whole Contracts. These contracts require us, as the processor, to bear the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that we paid for the unprocessed natural gas. However, since the gas received by the Elk City system, which is currently our only gathering system with keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the gas can be bypassed around the Elk City processing plant and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with such type of contracts is minimized.

Recent Trends and Uncertainties

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

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

As a result of our POP and keep whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas and NGLs. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short

term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. Our profitability is positively influenced by increases in natural gas and NGL prices and negatively influenced if such prices decrease. A 10% change in the average price of NGLs, natural gas and condensate we process and sell would result in a change to our consolidated income for the twelve-month period ending June 30, 2007 of approximately $3.2 million.

Results of Operations

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Operating data:
Appalachia:
Average throughput volumes (Mcf/d)		63,113		54,694		60,235		53,539
Average transportation rate per mcf	$	1.34	$	1.08	$	1.44	$	1.06
Mid-Continent:
Velma system:
Gathered gas volume (Mcf/d)		62,079		73,810		61,401		69,407
Processed gas volume (Mcf/d)		59,823		68,326		59,179		65,670
Residue gas volume (Mcf/d)		46,647		54,160		46,203		52,082
NGL production (Bbl/d)		6,674		7,149		6,505		6,779
Condensate volume (Bbl/d)		237		278		212		256
Elk City system:
Gathered gas volume (Mcf/d)		275,865		244,088		264,093		244,088
Processed gas volume (Mcf/d)		135,394		117,602		133,187		117,602
Residue gas volume (Mcf/d)		122,644		107,653		120,840		107,653
NGL production (Bbl/d)		6,237		5,537		5,999		5,537
Condensate volume (Bbl/d)		147		119		159		119
NOARK system:
Average throughput volume (Mcf/d)		243,014		—		241,093		—

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Revenue. Natural gas and liquids revenue was $96.0 million for the three months ended June 30, 2006, an increase of $16.3 million from $79.7 million for the three months ended June 30, 2005. The increase was attributable to revenue contributions from the NOARK system acquired in October 2005 of $10.2 million and the Elk City system acquired in April 2005 of $9.6 million, partially offset by a decrease in Velma natural gas and liquids revenue of $3.5 million due to decreases in volume and realized commodity prices. Gross natural gas gathered on the Elk City system averaged 275.9 MMcf/d for the three months ended June 30, 2006, a 13.0% increase from the prior year comparable quarter. Gross natural gas gathered averaged 62.1 MMcf/d on the Velma system for the three months ended June 30, 2006, a decrease of 15.9% from the comparable prior year quarter due to a decline in low margin volume. For the NOARK system, average throughput volume was 243.0 MMcf/d for the three months ended June 30, 2006.

Transportation and compression revenue increased to $13.2 million for the three months ended June 30, 2006 from $5.4 million for the comparable prior year quarter. This $7.8 million increase was

primarily due to contributions from the transportation revenues associated with the NOARK system acquired in October 2005 of $4.1 million and the Elk City system acquired in April 2005 of $1.2 million and increases in the Appalachia average transportation rate earned and volume of natural gas transported. Appalachia’s average throughput volume was 63.1 MMcf/d for the three months ended June 30, 2006 as compared with 54.7 MMcf/d for the three months ended March 31, 2005, an increase of 8.4 MMcf/d or 15.4%. Our Appalachia average transportation rate was $1.34 per Mcf for the three months ended June 30, 2006 as compared with $1.08 per Mcf for the comparable prior year quarter, an increase of $0.26 per Mcf. The increase in the Appalachia average daily throughput volume was principally due to new wells connected to our gathering system and the completion of a capacity expansion project in 2005 on certain sections of our pipeline system.

Costs and Expenses. Natural gas and liquids cost of goods sold of $77.0 million and plant operating expenses of $3.9 million for the three months ended June 30, 2006 represented increases of $10.4 million and $0.6 million, respectively, from the comparable prior year quarter amounts due primarily to contributions from the acquisitions, partially offset by lower Velma amounts due to lower volume and realized commodity prices. Transportation and compression expenses increased $2.5 million to $3.1 million for the three months ended June 30, 2006 due mainly to NOARK system operating costs and higher Appalachia operating costs as a result of compressors added during 2005 in connection with our capacity expansion project and higher maintenance expense as a result of additional wells connected to our gathering system.

General and administrative expenses, including amounts reimbursed to affiliates, increased $1.0 million to $4.8 million for the three months ended June 30, 2006 compared with $3.8 million for the prior year comparable quarter. This increase was mainly due to higher costs associated with managing our business, including management of our 2005 acquisitions and capital raising opportunities.

Depreciation and amortization increased to $5.3 million for the three months ended June 30, 2006 compared with $3.1 million for the three months ended June 30, 2005 due primarily to the depreciation and amortization associated with the Elk City and NOARK assets acquired during 2005.

Interest expense increased to $6.2 million for the three months ended June 30, 2006 as compared with $4.2 million for the comparable prior year quarter. This $2.0 million increase was primarily due to interest associated with our May 2006 and December 2005 issuances of 10-year senior unsecured notes, partially offset by a decrease in interest associated with borrowings under the credit facility.

Minority interest in NOARK of ($0.5) million for the three months ended June 30, 2006 represents Southwestern’s 25% ownership interest in the net loss of NOARK for the period prior to May 2, 2006, the date we acquired the remaining 25% ownership equity interest in NOARK. Our financial results include the consolidated financial statements of NOARK.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Revenue. Natural gas and liquids revenue was $197.0 million for the six months ended June 30, 2006, an increase of $75.0 million from $122.0 million for the six months ended June 30, 2005. The increase was primarily attributable to revenue contributions from the NOARK system acquired in October 2005 of $27.1 million and the Elk City system acquired in April 2005 of $49.0 million. Gross natural gas gathered on the Elk City system averaged 264.1 MMcf/d for the six months ended June 30, 2006, an 8.2% increase from the prior year period from April 15, its date of acquisition, through June 30, 2005. Gross natural gas gathered averaged 61.4 MMcf/d on the Velma system for the six months ended June 30, 2006, a decrease of 11.5% from the comparable prior year six month period due to a decline in low margin volume. For the NOARK system, average throughput volume was 241.1 MMcf/d for the six months ended June 30, 2006.

Transportation and compression revenue increased to $29.9 million for the six months ended June 30, 2006 from $10.2 million for the comparable prior year period. This $19.7 million increase was primarily due

to contributions from the transportation revenues associated with the NOARK system acquired in October 2005 of $11.8 million and the Elk City system acquired in April 2005 of $2.3 million and increases in the Appalachia average transportation rate earned and volume of natural gas transported. Appalachia’s average throughput volume was 60.2 MMcf/d for the six months ended June 30, 2006 as compared with 53.5 MMcf/d for the six months ended June 30, 2005, an increase of 6.7 MMcf/d or 12.5%. Our Appalachia average transportation rate was $1.44 per Mcf for the six months ended June 30, 2006 as compared with $1.06 per Mcf for the prior year six month period, an increase of $0.38 per Mcf. The increase in the Appalachia average daily throughput volume was principally due to new wells connected to our gathering system and the completion of a capacity expansion project in 2005 on certain sections of our pipeline system.

Costs and Expenses. Natural gas and liquids cost of goods sold of $162.9 million and plant operating expenses of $7.2 million for the six months ended June 30, 2006 represented increases of $60.9 million and $2.7 million, respectively, from the comparable prior year amounts due primarily to contributions from the acquisitions. Transportation and compression expenses increased $4.2 million to $5.5 million for the six months ended June 30, 2006 due mainly to NOARK system operating costs and higher Appalachia operating costs as a result of compressors added during 2005 in connection with our capacity expansion project and higher maintenance expense as a result of additional wells connected to our gathering system.

General and administrative expenses, including amounts reimbursed to affiliates, increased $3.2 million to $9.5 million for the six months ended June 30, 2006 as compared with the prior year comparable six month period. This increase was mainly due to higher costs associated with managing our business, including management of our 2005 acquisitions and capital raising opportunities.

Depreciation and amortization increased to $10.5 million for the six months ended June 30, 2006 compared with $5.1 million for the six months ended June 30, 2005 due primarily to the depreciation and amortization associated with the Elk City and NOARK assets acquired during 2005.

Interest expense increased to $12.5 million for the six months ended June 30, 2006 as compared with $5.3 million for the comparable prior year six month period. This $7.2 million increase was primarily due to interest associated with our May 2006 and December 2005 issuances of 10-year senior unsecured notes, partially offset by a decrease in interest associated with borrowings under the credit facility.

Liquidity and Capital Resources

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

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

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

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

At June 30, 2006, we had no amounts outstanding under our credit facility and $10.1 million of outstanding letters of credit which are not reflected as borrowings on our consolidated balance sheet, with $214.9 million of remaining committed capacity under the $225.0 million credit facility, subject to covenant limitations (see “Credit Facility”). In addition to the availability under the credit facility, we have a universal shelf registration statement on file with the Securities and Exchange Commission, which allows us to issue

equity or debt securities (see “Shelf Registration Statement”), of which $352.1 million remains available at June 30, 2006. At June 30, 2006, we had a working capital position of zero compared with $16.8 million at December 31, 2005. This decrease was primarily due to an increase in the current portion of our net hedge liability between periods, which is the result of changes in commodity prices after we entered into the hedges. The majority of our hedge transactions qualify as effective cash flow hedges, and changes in commodity prices with respect to these hedge transactions are reflected as adjustments to accumulated other comprehensive loss within partners’ capital on the consolidated balance sheet. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, unitholder distributions, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cashflow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings and the issuance of additional limited partner units.

Cash Flows — Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Net cash provided by operating activities of $23.9 million for the six months ended June 30, 2006 increased $1.2 million from $22.7 million for the comparable prior year six month period. The increase is derived principally from increases in net income of $11.4 million and depreciation and amortization of $5.5 million, partially offset by a $16.2 million decrease in cash resulting from changes in the components of working capital. The increases in net income and depreciation and amortization were principally due to the contribution from the 2005 acquisitions. The decrease in cash resulting from changes in the components of working capital was the result of working capital required for the growth of the 2005 acquisitions of NOARK and Elk City.

Net cash used in investing activities was $65.7 million for the six months ended June 30, 2006, a decrease of $152.6 million from $218.3 million for the comparable prior year six month period. This decrease was principally due to a $165.6 million decrease in cash paid for acquisitions, partially offset by a $12.9 million increase in capital expenditures. Cash paid for acquisitions in 2006 consist of the acquisition of the remaining 25% equity ownership interest in NOARK, while cash paid for acquisitions in 2005 consist of the acquisition of Elk City. See further discussion of capital expenditures under “Capital Requirements.”

Net cash provided by financing activities was $20.0 million for the six months ended June 30, 2006, a decrease of $170.8 million from $190.8 million of net cash used in financing activities for the comparable prior year six month period. This decrease was principally due to a $123.3 million increase in net repayments under our credit facility, a $71.9 million decrease in net proceeds received from the issuance of common units, a $39.0 million increase in repayment of debt, and a $15.0 million increase in cash distributions to common limited partners and the general partner. These amounts were partially offset by a $40.0 million increase in net proceeds from the issuance of cumulative convertible preferred units and a $36.7 million increase in net proceeds from the issuance of senior notes. The changes in net proceeds from the issuance of common units, preferred units, and senior notes and borrowing activity under our revolver principally relate to the construction of the Sweetwater gas plant, a new natural gas processing plant in Oklahoma expected to be operational in the third quarter of 2006 (see “— Significant Announced Internal Growth Project”) and our financing the acquisitions of Elk City in April 2005, the 75% ownership interest in NOARK in October 2005, and the remaining 25% ownership interest in NOARK in May 2006. The increase in cash distributions to common limited partners and the general partner are due mainly to increases in our common limited partner units outstanding and our cash distribution amount per common limited partner unit.

Capital Requirements

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

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

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Maintenance capital expenditures	$	917	$	473	$	2,078	$	865
Expansion capital expenditures		21,333		16,333		33,734		22,018

Total	$	22,250	$	16,806	$	35,812	$	22,883

Expansion capital expenditures increased to $21.3 million and $33.7 million for the three and six months ended June 30, 2006, respectively, due principally to expansions of the Appalachia, Velma and Elk City gathering systems, processing facilities and compressor upgrades to accommodate new wells drilled in our service areas. Expansion capital expenditures for our Mid-Continent region for the three and six months ended June 30, 2006 also include costs incurred of approximately $10.2 million and $15.5 million, respectively, related to the construction of the Sweetwater gas plant, a new natural gas processing plant in Oklahoma expected to be operational in the third quarter of 2006 (see “— Significant Announced Internal Growth Project”). As of June 30, 2006, we have incurred $26.2 million of the projected $40 million in expenditures related to the Sweetwater project. Maintenance capital expenditures for the three and six months ended June 30, 2006 increased to $0.9 million and $2.1 million, respectively, due to the additional maintenance requirements of the 2005 acquisitions. As of June 30, 2006, we are committed to expend approximately $25.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $9.2 million related to the Sweetwater gas plant.

Partnership Distributions

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

Our general partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner’s incentive distributions declared for three and six months ended June 30, 2006 was $3.7 million and $7.2 million, respectively.

Common Equity Offerings

On May 12, 2006, we sold 500,000 common units to Wachovia Securities, which has offered the common unit to public investors. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $19.8 million, after underwriting commissions and other transaction costs. We utilized the net proceeds from the sale to partially repay borrowings under our credit facility made in connection with our recent acquisition of the remaining 25% interest in NOARK. Subsequent to this transaction, we had 13,049,266 common limited partner units outstanding.

In November 2005, we sold 2,700,000 of our common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, we sold an additional 330,000 common units in December 2005 for gross proceeds of $13.9 million, resulting in aggregate total gross proceeds of $127.3 million. The units, which were issued under our previously filed shelf registration statement, resulted in total net proceeds of approximately $121.0 million, after underwriting commissions and other transaction costs. We primarily utilized the net proceeds from the sale to repay a portion of the amounts due under our credit facility.

In June 2005, we sold 2,300,000 common units in a public offering for total gross proceeds of $96.5 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $91.7 million, after underwriting commissions and other transaction costs. We primarily utilized the net proceeds from the sale to repay a portion of the amounts due under our credit facility.

Shelf Registration Statement

We have an effective shelf registration statement with the Securities and Exchange Commission that permits us to periodically issue equity and debt securities for a total value of up to $500 million. As of June 30, 2006, $352.1 million remains available for issuance under the shelf registration statement. However, the amount, type and timing of any offerings will depend upon, among other things, our funding requirements, prevailing market conditions, and compliance with our credit facility covenants.

Private Placement of Convertible Preferred Units

On March 13, 2006, we sold 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC, an affiliate of Elliott & Associates, for aggregate proceeds of $30.0 million. We also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital Partners for $10.0 million on May 19, 2006, pursuant to our right to require Sunlight Capital Partners to purchase such additional units under the purchase agreement with Sunlight. The preferred units are entitled to receive dividends of 6.5% per annum commencing on March 13, 2007, which will accrue and be paid quarterly on the same date as the distribution payment date for our common units. The preferred units are convertible, at the holder’s option, into common units commencing on the date immediately following the first record date after March 13, 2007 at a conversion price equal to the lesser of $41.00 or 95% of the market price of our common units as of the date of the notice of conversion. We may elect to pay cash rather than issue common units in satisfaction of a conversion request. We have the right to call the preferred units at a specified premium. We have also agreed to file a registration statement to cover the resale of the common units underlying the preferred units. The net proceeds from the initial issuance of the preferred units was used to fund a portion of our capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system. The proceeds from the issuance of the additional 10,000 preferred units was used to reduce indebtedness under our credit facility incurred in connection with the acquisition of the remaining 25% interest in NOARK. The preferred units are reflected on our consolidated balance sheet as preferred equity within Partners’ Capital. If converted to common units, the preferred equity amount converted will be reclassified to common unit equity within Partners’ Capital on our consolidated balance

sheet. Dividends accrued and paid on the preferred units and any premium paid upon their redemption, if any, will be recognized as a reduction to our net income in determining net income attributable to common unitholders and the general partner.

Credit Facility

We have a $225.0 million credit facility with a syndicate of banks which matures in June 2011. The credit facility bears interest, at our option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). There were no amounts outstanding under the credit facility at June 30, 2006. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at June 30, 2006. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of our property and that of our wholly-owned subsidiaries, and by the guaranty of each of our wholly-owned subsidiaries. The credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are in compliance with these covenants as of June 30, 2006.

The credit facility requires us 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, 2006, our ratio of senior secured debt to EBITDA was 0.1 to 1.0, our funded debt ratio was 3.2 to 1.0 and our interest coverage ratio was 4.1 to 1.0.

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

Senior Notes

In December 2005, we and our subsidiary, Atlas Pipeline Finance Corp. (“APFC”), issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. In May 2006, we and APFC issued an additional $35.0 million of senior unsecured notes at 103% par value, with a resulting effective yield of approximately 7.6%, for net proceeds of approximately $36.7 million, including accrued interest and net of initial purchaser’s discount and other transaction costs. 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, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under the credit facility.

The indenture governing the Senior Notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets. We are in compliance with these covenants as of June 30, 2006.

In connection with a Senior Notes registration rights agreement entered into by us, we agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the Senior Notes by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission by July 18, 2006, and (c) cause the exchange offer to be consummated by August 17, 2006. If we do not meet the aforementioned deadlines, the Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the deadlines have been met. On April 19, 2006, we filed an exchange offer registration statement for the Senior Notes with the Securities and Exchange Commission, which was declared effective on July 11, 2006. We expect to consummate the exchange offer by August 17, 2006 and thereby fulfill all of the requirements of the Senior Notes registration rights agreement by the specified dates.

NOARK Notes

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

Significant Announced Internal Growth Project

In October 2005, we announced plans to complete construction of a new natural gas processing plant in Beckham County, Oklahoma near our Prentiss treating facility, in the third quarter of 2006. The new plant, to be known as the Sweetwater gas plant, will be scaled to 120 MMcf/d of processing capacity. The Sweetwater gas plant will be located west of our Elk City gas plant, and is being built to further access natural gas production actively being developed in western Oklahoma and the Texas panhandle. Along with the Sweetwater gas plant, we will construct a gathering system to be located primarily in western Oklahoma and in the Texas panhandle, more specifically, Beckham and Roger Mills counties in Oklahoma and Hemphill County, Texas. We anticipate that construction of the Sweetwater gas plant and associated gathering system will cost approximately $40.0 million, of which approximately $26.2 million has been expended through June 30, 2006.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenues and expenses during the reporting period. Although we believe our estimates are reasonable, actual results could differ from those estimates. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2005, and there have been no material changes to these policies through June 30, 2006.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

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

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use 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 June 30, 2006. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At June 30, 2006, we had a $225.0 million revolving credit facility (no amounts outstanding) to fund the expansion of our existing gathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. Borrowings under this credit facility in future periods will subject us to movements in interest rates, which could negatively impact our net income and cash flow.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on our current portfolio of gas supply contracts, we have long condensate, NGL, and natural gas positions. A 10% change in the average price of NGLs, natural gas and condensate we process and sell would result in a change to our consolidated income for the twelve-month period ending June 30, 2007 of approximately $3.2 million.

We enter into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133 to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, we receive a fixed price and remit a floating price based on certain indices for the relevant contract period.

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

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive loss and reclassify them to natural gas and liquids revenue within the consolidated statements of income as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within our consolidated statements of income as they occur. At June 30, 2006 and December 31, 2005, we reflected net hedging liabilities on our consolidated balance sheets of $43.0 million and $30.4 million, respectively. Of the $42.9 million of net loss in accumulated other comprehensive loss at June 30, 2006, if the fair value of the instruments remain at current market values, we will reclassify $18.7 million of losses to our consolidated statements of income over the next twelve month period as these contracts expire, and $24.2 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within natural gas and liquids revenue in our consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. We recognized losses of $3.2 million and $1.3 million for the three months ended June 30, 2006 and 2005, respectively, and losses of $5.6 million and $1.9 million for the six months ended June 30, 2006 and 2005, respectively, within our consolidated statements of income related to the settlement of qualifying hedge instruments. We also recognized gains of $0.4 million and $0.3 million for the three months ended June 30, 2006 and 2005, respectively, and gains of $0.9 million and $0.1 million for the six months ended June 30, 2006 and 2005, respectively, within our consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

A portion of our future natural gas 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 revenue.

As of June 30, 2006, we had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Sales


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽¹⁾
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		31,122,000	$	0.758	$	(9,751	)
2007		36,036,000		0.717		(12,238	)
2008		33,012,000		0.697		(11,491	)
2009		8,568,000		0.746		(2,750	)

					$	(36,230	)

Natural Gas Sales


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		500,000	$	7.019	$	(194	)
2007		1,080,000		7.255		(2,080	)
2008		240,000		7.270		(487	)

					$	(2,761	)

Natural Gas Basis Sales


Production			Average			Fair Value
Period	Volumes		Fixed Price			Asset⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		600,000	$	(0.525	)	$	376
2007		1,080,000		(0.535	)		739
2008		240,000		(0.555	)		146

						$	1,261

Natural Gas Purchases


Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		1,800,000	$	7.857	$	(810	)

					$	(810	)

Natural Gas Basis Purchases


Production			Average			Fair Value
Period	Volumes		Fixed Price			Liability⁽³⁾
Ended December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		2,160,000	$	(0.781	)	$	(738	)

						$	(738	)

Crude Oil Sales


Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		35,400	$	52.956	$	(776	)
2007		80,400		56.069		(1,613	)
2008		62,400		59.267		(933	)
2009		36,000		62.700		(335	)

					$	(3,657	)

Crude Oil Sales Options


Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)			Option Type
2006		6,600	$	60.000	$	—		Puts purchased
2006		6,600		73.380		(10	)	Calls sold
2007		13,200		60.000		—		Puts purchased
2007		13,200		73.380		(36	)	Calls sold
2008		17,400		60.000		—		Puts purchased
2008		17,400		72.807		(19	)	Calls sold
2009		30,000		60.000		—		Puts purchased
2009		30,000		71.250		(23	)	Calls sold

					$	(88	)

	Total net liability				$	(43,023	)


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

⁽²⁾		MMBTU represents million British Thermal Units.

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

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.

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 1. LEGAL PROCEEDINGS

None.

ITEM 6. EXHIBITS


Exhibit No.		Description
	3.1	Second Amended and Restated Agreement of Limited Partnership⁽¹⁾
	3.2	Certificate of Limited Partnership of Atlas Pipeline Partners, L.P.⁽²⁾
	3.3	Certificate of Designation of 6.5% Cumulative Convertible Preferred Units⁽³⁾
	10.1	Securities Purchase Agreement dated as of March 13, 2006 between the Partnership and Sunlight Capital Partners, LLC⁽³⁾
	10.2	Registration Rights Agreement dated as of March 13, 2006 between the Partnership and Sunlight Capital Partners, LLC⁽³⁾
	10.3	Second Amendment to Revolving Credit and Term Loan Agreement dated as of May 1, 2006
	10.4	Third Amendment to Revolving Credit and Term Loan Agreement dated as of June 29, 2006
	12.1	Statement of Computation of Ratio of Earnings to Fixed Charges
	31.1	Rule 13a-14(a)/15d-14(a) Certifications
	31.2	Rule 13a-14(a)/15d-14(a) Certifications
	32.1	Section 1350 Certifications
	32.2	Section 1350 Certifications


⁽¹⁾		Previously filed as an exhibit to the Partnership’s registration statement on Form S-3, Registration No. 333-113523 and incorporated herein by reference.


⁽²⁾		Previously filed as an exhibit to the Partnership’s registration statement on Form S-1, Registration No. 333-85193 and incorporated herein by reference.

⁽³⁾		Previously filed as an exhibit to the Partnership’s current report on Form 8-K filed on March 14, 2006 and incorporated herein by reference.

SIGNATURES

ATLAS PIPELINE PARTNERS, L.P.

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.



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

Date: August 4, 2006	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Managing Board of the General Partner (Chief Executive Officer of the General Partner)


Date: August 4, 2006	By:	/s/ MICHAEL L.STAINES
		Michael L. Staines
		President, Chief Operating Officer and Managing Board Member of the General Partner


Date: August 4, 2006	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer of the General Partner


Date: August 4, 2006	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer of the General Partner