UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2005

OR

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		23-3011077
(State or other jurisdiction of		(I.R.S. Employer Identification No.)
incorporation or organization)
311 Rouser Road
Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes x No o

 

 

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

				PAGE
PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004 (Unaudited)			3
		Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2005 and 2004 (Unaudited)			4
		Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2005 (Unaudited)			5
		Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004 (Unaudited)			6
		Notes to Consolidated Financial Statements (Unaudited)			7 - 23
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			24 - 32
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			33 - 35
Item 4.		Controls and Procedures			35
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings			36
Item 2.		Unregistered Sales of Equity Securities and Uses of Proceeds			36
Item 3.		Defaults Upon Senior Securities			36
Item 4.		Submission of Matters to a Vote of Security Holders			36
Item 5.		Other Information			36
Item 6.		Exhibits			36
SIGNATURES					37
Stock Purchase Agreement, dated September 21, 2005
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

		September 30,				December 31,
ASSETS		2005				2004
Current assets:
Cash and cash equivalents		$	12,035			$	18,214
Accounts receivable-affiliates			4,418				1,496
Accounts receivable			41,289				13,729
Current portion of hedge asset			14,993				40
Prepaid expenses			1,595				1,056
Total current assets			74,330				34,535
Property, plant and equipment, net			304,704				175,259
Long-term hedge asset			5,970				14
Intangible assets, net			12,398				—
Goodwill			80,201				2,305
Other assets			6,855				4,672
		$	484,458			$	216,785
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	63			$	2,303
Accrued liabilities			6,360				3,144
Current portion of hedge liability			37,663				1,959
Accrued producer liabilities			32,543				10,996
Accounts payable			7,257				2,341
Distribution payable			—				6,467
Total current liabilities			83,886				27,210
Long-term hedge liability			29,962				722
Long-term debt, less current portion			183,582				52,149
Commitments and contingencies
Partners’ capital:
Limited partners’ interests			227,065				135,761
General partner’s interest			6,407				2,261
Accumulated other comprehensive loss			(46,444	)			(1,318	)
Total partners’ capital			187,028				136,704
		$	484,458			$	216,785

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Revenues:
Natural gas and liquids		$	96,234			$	30,048			$	218,268			$	30,048
Transportation and compression — affiliates			6,248				4,645				16,447				13,292
Transportation and compression — third parties			16				20				54				52
Interest income and other			147				166				352				282
Total revenues and other income			102,645				34,879				235,121				43,674
Costs and expenses:
Natural gas and liquids			82,537				24,588				184,578				24,588
Plant operating			2,745				931				7,242				931
Transportation and compression			871				564				2,169				1,709
General and administrative			2,431				1,344				7,763				2,180
Compensation reimbursement — affiliates			412				393				1,365				721
Depreciation and amortization			3,438				1,021				8,495				2,132
Interest			3,166				1,076				8,478				1,202
Terminated acquisition			(9	)			2,987				138				2,987
Total costs and expenses			95,591				32,904				220,228				36,450
Net income			7,054				1,975				14,893				7,224
Premium on preferred unit redemption			—				400				—				400
Net income attributable to partners		$	7,054			$	1,575			$	14,893			$	6,824
Allocation of net income attributable to partners:
Limited partners’ interest		$	4,600			$	624			$	9,003			$	5,105
General partner’s interest			2,454				951				5,890				1,719
Net income attributable to partners		$	7,054			$	1,575			$	14,893			$	6,824
Net income attributable to partners per limited partner unit:
Basic		$	0.48			$	0.09			$	1.09			$	0.94
Diluted		$	0.48			$	0.09			$	1.09			$	0.94
Weighted average limited partner units outstanding:
Basic			9,511				6,839				8,226				5,416
Diluted			9,591				6,844				8,277				5,418

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

																						Accumulated
		Number of Limited																				Other				Total
		Partner Units																General				Comprehensive				Partners'
		Common				Subordinated				Common				Subordinated				Partner				Loss				Capital
Balance at January 1, 2005			5,563,659				1,641,026			$	135,759			$	2			$	2,261			$	(1,318	)		$	136,704
Conversion of subordinated units			1,641,026				(1,641,026	)			2				(2	)			—				—				—
Issuance of common units in public offering			2,300,000				—				91,720				—				—				—				91,720
Issuance of common units under long-term incentive plan			14,581				—				—				—				—				—				—
Capital contributions			—				—				—				—				1,930				—				1,930
Unissued common units under long-term incentive plan			—				—				3,494				—				—				—				3,494
Distributions to partners			—				—				(12,722	)			—				(3,674	)			—				(16,396	)
Distribution equivalent rights paid on unissued units under long-term incentive plan			—				—				(191	)			—				—				—				(191	)
Other comprehensive loss			—				—				—				—				—				(45,126	)			(45,126	)
Net income			—				—				9,003				—				5,890				—				14,893
Balance at September 30, 2005			9,519,266				—			$	227,065			$	—			$	6,407			$	(46,444	)		$	187,028

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

		Nine Months Ended September 30,
		2005				2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	14,893			$	7,224
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			8,495				2,132
Non-cash (gain) loss on derivative value			(1,091	)			585
Non-cash compensation under long-term incentive plan			2,809				342
Amortization of deferred finance costs			1,741				163
Change in operating assets and liabilities, net of effects of acquisitions:
Increase (decrease) in accounts receivable and prepaid expenses			(22,317	)			506
Increase in accounts payable and accrued liabilities			25,511				3,797
(Increase) decrease in accounts receivable — affiliates			(2,922	)			2,987
Net cash provided by operating activities			27,119				17,736
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions			(195,201	)			(141,564	)
Capital expenditures			(34,519	)			(4,419	)
Other			(172	)			255
Net cash used in investing activities			(229,892	)			(145,728	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility			271,500				100,000
Repayments under credit facility			(142,250	)			(40,000	)
Distributions paid to partners			(22,864	)			(9,846	)
General partner capital contributions			1,930				1,994
Net proceeds from issuance of limited partner units			91,720				92,714
Net proceeds from sale of preferred units			—				20,000
Redemption of preferred units			—				(20,000	)
Other			(3,442	)			(2,928	)
Net cash provided by financing activities			196,594				141,934
Net change in cash and cash equivalents			(6,179	)			13,942
Cash and cash equivalents, beginning of period			18,214				15,078
Cash and cash equivalents, end of period		$	12,035			$	29,020

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTE 1 — BASIS OF PRESENTATION

     Atlas Pipeline Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed in May 1999 to acquire, own and operate natural gas gathering systems previously owned by Atlas America, Inc. (“Atlas” or “Atlas America”) and its affiliates. The Partnership’s operations are conducted through subsidiary entities whose equity interests are owned by the Partnership’s operating subsidiary, Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”). Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas (the “General Partner”), owns, through its general partner interests in the Partnership and the Operating Partnership, a 2% general partner interest in the consolidated pipeline operations. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests in the Partnership. Through its general partner interest, the General Partner effectively manages and controls both the Partnership and the Operating Partnership.

     The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2004 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, 2004. The results of operations for the three and nine month periods ended September 30, 2005 may not necessarily be indicative of the results of operations for the full year ending December 31, 2005.

     Certain previously reported amounts have been reclassified to conform to the current presentation.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2004.

Use of Estimates

     The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.

     The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the Partnership include estimated volumes and market prices. Differences between estimated and actual amounts are recognized in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2005 represent actual results in all material respects (see Revenue Recognition accounting policy for further description).

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)

Net Income Per Unit

     Basic net income per limited partner unit is computed by dividing net income, after deducting the general partner’s interest, by the weighted average number of limited partner units outstanding for the period. The general partner’s interest in net income is calculated on a quarterly basis based upon its 2% interest and incentive distributions (see Note 4). Diluted net income per limited partner unit is calculated by dividing net income applicable to limited partners by the sum of the weighted-average number of 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 (see Note 11). The following table sets forth the reconciliation of the weighted average number of limited partner units used to compute basic net income per limited partner unit to those used to compute diluted net income per limited partner unit (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Weighted average number of limited partner units — basic			9,511				6,839				8,226				5,416
Add effect of dilutive unit incentive awards			80				5				51				2
Weighted average number of limited partner units — diluted			9,591				6,844				8,277				5,418

Receivables

     In evaluating the realizability of its accounts receivable, the Partnership performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Partnership’s review of its customers’ credit information. The Partnership extends credit on an unsecured basis to many of its energy customers. At September 30, 2005 and December 31, 2004, the Partnership recorded no allowance for uncollectible accounts receivable impairment.

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 for the Partnership include only changes in the fair value of unsettled hedge contracts.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)

     The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Net income		$	7,054			$	1,975			$	14,893			$	7,224
Premium on preferred unit redemption			—				(400	)			—				(400	)
Net income attributable to partners		$	7,054			$	1,575			$	14,893			$	6,824
Other comprehensive loss:
Change in fair value of derivative instruments accounted for as hedges			(29,622	)			(3,955	)			(49,507	)			(3,955	)
Add: reclassification adjustment for losses realized in net income			2,450				27				4,381				27
			(27,172	)			(3,928	)			(45,126	)			(3,928	)
Comprehensive (loss) income		$	(20,118	)		$	(2,353	)		$	(30,233	)		$	2,896

Revenue Recognition

     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 Uses of Estimates accounting policy for further description). The Partnership had unbilled revenues at September 30, 2005 and December 31, 2004 of $42.1 million and $15.3 million, respectively, included in accounts receivable and accounts receivable-affiliates within the consolidated balance sheets.

Intangible Assets

     At September 30, 2005, the Partnership had $12.4 million of intangible assets, net of accumulated amortization of $0.5 million, which was recorded in connection with natural gas gathering contracts assumed in consummated acquisitions (see Note 7). SFAS No. 142 requires that intangible assets with finite useful lives be amortized over their respective 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. Amortization expense on the customer contract intangible assets, which have an estimated life of 12 years and are amortized on a straight-line basis, was $0.5 million for the three and nine months ended September 30, 2005. There was no amortization expense on intangible assets recorded during the three and nine months ended September 30, 2004. Amortization expense related to intangible assets is estimated to be $1.1 million for each of the next five calendar years.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)

Goodwill

     At September 30, 2005 and December 31, 2004, the Partnership had $80.2 million and $2.3 million, respectively, of goodwill which was recognized in connection with consummated acquisitions (see Note 7). The Partnership tests its goodwill for impairment at each year end by comparing fair values to its carrying values.

     The evaluation of impairment under Statement of Financial Accounting Standards (“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, 2004 resulted in no impairment, and no impairment indicators have been noted as of September 30, 2005. The Partnership will continue to evaluate its goodwill at least annually and when impairment indicators arise, will reflect the impairment of goodwill, if any, within the consolidated statements of income in the period in which the impairment is indicated.

New Accounting Standards

     In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and corrections of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on the Partnership’s financial position or results of operations.

     In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of

     settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. As FIN 47 was recently issued, the Partnership has not yet determined whether the interpretation will have a significant adverse effect on its financial position or results of operations.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)

     In December 2004, the FASB issued SFAS No. 123 (R) (revised 2004) “Share-Based Payment,” which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (R) supersedes Accounting Principals Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach to accounting in Statement 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. Currently, the Partnership follows APB No. 25 and its interpretations, which allow for valuation of share-based payments to employees at their intrinsic values. Under

     this methodology, the Partnership recognizes compensation expense for phantom units granted at their fair value at the date of grant and compensation expense for options granted only if the current market price of the underlying units exceed the exercise price. SFAS No. 123 (R) is effective for the Partnership beginning January 1, 2006. The Partnership does not expect SFAS No. 123 (R) to have a material impact on its consolidated financial statements.

NOTE 3 — EQUITY OFFERINGS

     On June 2, 2005, the Partnership sold 2.3 million common units in a public offering for total gross proceeds of $96.5 million. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of the units 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. In connection with this offering, the General Partner contributed $1.9 million to the Partnership in order to maintain its 2.0% general partner interest. At September 30, 2005, Atlas’ ownership interest in the Partnership was 18.9%, including its 2.0% general partner interest.

     On July 20, 2004, the Partnership sold 2.1 million common units in a public offering for total gross proceeds of $73.0 million. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $67.5 million, after underwriting commissions and other transaction costs. The Partnership utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its credit facility and to redeem preferred units issued in connection with the acquisition of Spectrum Field Services, Inc. in July 2004 for $20.4 million (see Note 7). In connection with this offering, the General Partner contributed $1.5 million to the Partnership in order to maintain its 2.0% general partner interest.

     On April 14, 2004, the Partnership sold 0.8 million common units in a public offering for total gross proceeds of $25.4 million. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $25.2 million, after underwriting commissions and other transaction costs. The Partnership utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its credit facility. In connection with this offering, the General Partner contributed $0.5 million to the Partnership in order to maintain its 2.0% general partner interest.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 4 — DISTRIBUTIONS

     The Partnership will generally make quarterly cash distributions of substantially all of its available cash, generally defined as cash on hand at the end of the quarter less cash reserves established by the General Partner, at its discretion, to provide for future operating costs, potential acquisitions and future distributions, among other items. Pursuant to the partnership agreement, the General Partner receives incremental incentive cash distributions when cash distributions exceed certain target thresholds. Distributions paid by the Partnership for the period from January 1, 2004 through September 30, 2005 were as follows:

				Cash				Total Cash				Total Cash
Date Cash				Distribution				Distribution				Distribution
Distribution		For Quarter		per Limited				to Limited				to the General
Paid		Ended		Partner Unit				Partners				Partner
								(in thousands)				(in thousands)
February 6, 2004		December 31, 2003		$	0.625			$	2,722			$	351
May 7, 2004		March 31, 2004		$	0.630			$	2,743			$	374
August 6, 2004		June 30, 2004		$	0.630			$	3,216			$	438
November 5, 2004		September 30, 2004		$	0.690			$	4,971			$	1,060
February 11, 2005		December 31, 2004		$	0.720			$	5,187			$	1,280
May 13, 2005		March 31, 2005		$	0.750			$	5,404			$	1,500
August 5, 2005		June 30, 2005		$	0.770			$	7,319			$	2,174

     On October 27, 2005, the Partnership declared a cash distribution of $0.81 per unit on its outstanding limited partner units, representing the cash distribution for the quarter ended September 30, 2005. The $10.3 million distribution, including $2.6 million to the general partner, will be paid on November 14, 2005 to unitholders of record at the close of business on November 7, 2005.

     At December 31, 2004, the Partnership had 1,641,026 subordinated units outstanding, all of which were held by the general partner. In January 2005, these subordinated units were converted to common units as the Partnership met stipulated tests under the terms of the partnership agreement allowing for such conversions. While the general partner’s rights as the holder of the subordinated units are no longer subordinated to the rights of the common unitholders, these units 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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment consist of the following (in thousands):

										Estimated
		September 30,				December 31,				Useful Lives
		2005				2004				in Years
Pipelines, processing and compression facilities		$	304,795			$	168,932			15 - 40
Rights of way.			15,109				14,128			20 - 40
Buildings.			3,351				3,215			40
Furniture and equipment.			700				517			3 - 7
Other.			562				307			3 - 10
			324,517				187,099
Less — accumulated depreciation.			(19,813	)			(11,840	)
		$	304,704			$	175,259

     In April 2005, the Partnership completed the acquisition of ETC Oklahoma Pipeline, Ltd. for approximately $196.0 million (see Note 7). Due to its recent date of acquisition, the purchase price allocation is based upon preliminary data that is subject to adjustment and could change significantly as the Partnership continues to evaluate this allocation. At September 30, 2005, the purchase price allocated to property, plant and equipment for this acquisition by the Partnership was included within the pipelines, processing and compression facilities category within the above table.

NOTE 6 — OTHER ASSETS

     Other assets consist of the following (in thousands):

		September 30,				December 31,
		2005				2004
Deferred finance costs, net of accumulated amortization of $1,237 and $506 at September 30, 2005 and December 31, 2004, respectively		$	4,771			$	3,316
Security deposits			1,659				1,356
Other			425				—
		$	6,855			$	4,672

     Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 9). In June 2005, the Partnership charged operations $1.0 million of accelerated amortization of deferred financing costs associated with the retirement of the term portion of its $270 million credit facility.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 7 -ACQUISITIONS

Spectrum

     On July 16, 2004, the Partnership acquired Spectrum Field Services, Inc. (“Spectrum”), for approximately $141.6 million, including transaction costs and the payment of taxes due as a result of the transaction. Spectrum’s principal assets included 1,900 miles of natural gas pipelines and a natural gas processing facility in Velma, Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

Cash and cash equivalents		$	803
Accounts receivable			18,505
Prepaid expenses			649
Property, plant and equipment			139,464
Other long-term assets			1,054
Total assets acquired			160,475
Accounts payable and accrued liabilities			(17,153	)
Hedging liabilities			(1,519	)
Long-term debt			(164	)
Total liabilities assumed			(18,836	)
Net assets acquired		$	141,639

     The results of the acquisition are included within the Partnership’s consolidated financial statements from its date of acquisition. In connection with financing the acquisition of Spectrum, the Partnership issued preferred units to Resource America and Atlas America for $20.0 million. These preferred units were subsequently redeemed for $20.4 million, including a $0.4 million premium, with the net proceeds from the Partnership’s July 20, 2004 equity offering (see Note 3).

Elk City

     On April 14, 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 318 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma, with total capacity of 130 million cubic feet of gas per day (“mmcf/d”) and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100 mmcf/d. The purchase price is subject to post-closing adjustments based upon, among other things, gas imbalances, certain prepaid expenses and capital expenditures, and title defects, if any. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 7 —ACQUISITIONS (Continued)

Elk City — (Continued)

     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			104,091
Intangible assets			12,890
Goodwill			77,896
Total assets acquired			200,961
Accounts payable and accrued liabilities			(4,970	)
Total liabilities assumed			(4,970	)
Net assets acquired		$	195,991

     Due to its recent date of acquisition, the purchase price allocation for Elk City is based upon preliminary data that is subject to adjustment and could change significantly as the Partnership continues to evaluate this allocation. The Partnership recognized goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. The results of the acquisition were included within the Partnership’s consolidated financial statements from its date of acquisition.

     The following data presents pro forma revenues, net income and basic and diluted net income per limited partner unit for the Partnership as if the acquisitions discussed above and the equity offerings in July 2004 and June 2005, the net proceeds of which were utilized to repay debt borrowed to finance the acquisitions (see Note 3), had occurred on January 1, 2004. The Partnership has prepared these 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 at the beginning of the periods shown below or the results that will be attained in the future (in thousands except per unit amounts):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Total revenues and other income		$	102,645			$	72,393			$	275,853			$	194,186
Net income		$	7,054			$	2,674			$	15,820			$	10,953
Net income per limited partner unit:
Basic		$	0.48			$	0.11			$	1.00			$	0.82
Diluted		$	0.48			$	0.11			$	0.99			$	0.82

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 8 — 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. The Partnership entered into these instruments to hedge the forecasted natural gas, NGL 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, NGL and condensate is sold. Under these swap agreements, the Partnership receives a fixed price and pays 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 the Partnership’s 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 utilization of market data, will be recognized immediately within the Partnership’s consolidated statements of income.

     Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ capital as accumulated other comprehensive income (loss) and reclassified 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, changes in fair value are recognized within the consolidated statements of income as they occur. At September 30, 2005 and December 31, 2004, the Partnership reflected net hedging liabilities on its balance sheets of $46.7 million and $2.6 million, respectively. Of the $46.4 million net loss in accumulated other comprehensive income (loss) at September 30, 2005, if the fair values of the instruments remain at current market values, $22.7 million of losses will be reclassified to the consolidated statements of income over the next twelve month period as these contracts expire and $23.7 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 in natural gas and liquids revenue within the consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized losses of $2.5 million and $27,000 for the three months ended September 30, 2005 and 2004, respectively, and $4.4 million and $27,000 for the nine months ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the settlement of qualifying hedge instruments. The Partnership also recognized losses of $0.8 million and $0.7 million for the three months ended September 30, 2005 and 2004, respectively, and $0.7 million and $0.7 million for the nine months ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS (Continued)

     As of September 30, 2005, the Partnership had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed — Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(2)
Ended September 30,		(gallons)				(per gallon)				(in thousands)
2006			38,586,000			$	0.673			$	(16,742	)
2007			38,115,000				0.711				(12,188	)
2008			34,587,000				0.702				(9,037	)
2009			7,434,000				0.697				(1,781	)
										$	(39,748	)

Natural Gas Fixed — Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(3)
Ended September 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			3,923,000			$	7.169			$	(5,767	)
2007			1,560,000				7.210				(1,658	)
2008			510,000				7.262				(1,037	)
										$	(8,462	)

Natural Gas Basis Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Asset(3)
Ended September 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			4,262,000			$	(0.517	)		$	1,376
2007			1,560,000				(0.522	)			1,584
2008			510,000				(0.544	)			1,383
										$	4,343

Crude Oil Fixed — Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(3)
Ended September 30,		(barrels)				(per barrel)				(in thousands)
2006			67,800			$	51.329			$	(1,056	)
2007			80,400				55.187				(844	)
2008			82,500				58.475				(414	)
										$	(2,314	)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Options

Production										Average				Fair Value
Period						Volumes				Strike Price				Liability(3)
Ended September 30,		Option Type				(barrels)				(per barrel)				(in thousands)
2006		Puts purchased					15,000			$	30.00			$	—
2006		Calls sold					15,000				34.25				(481	)
														$	(481	)
						Total net liability								$	(46,662	)

NOTE 9 — LONG-TERM DEBT

     Total debt consists of the following (in thousands):

		September 30,				December 31,
		2005				2004
Credit Facility:
Revolving credit facility		$	183,500			$	10,000
Term loan			—				44,250
Other debt			145				202
			183,645				54,452
Less current maturities			(63	)			(2,303	)
		$	183,582			$	52,149

     In April 2005, the Partnership entered into a new $270.0 million credit facility (the “Credit Facility”) with a syndicate of banks, which replaced its existing $135.0 million facility. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan. The term loan portion of the Credit Facility was repaid and retired from the net proceeds of the June 2005 equity offering (see Note 3). The revolving portion of the Credit Facility bears interest, at the Partnership’s option, at either (i) Adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding Credit Facility borrowings at September 30, 2005 was 6.6%. Up to $10.0 million of the credit facility may be utilized for letters of credit, of which $7.7 million is outstanding at September 30, 2005 and is 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 the Partnership’s subsidiaries.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 9 — LONG-TERM DEBT — (Continued)

     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 unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in the Partnership’s subsidiaries. The Credit Facility also contains covenants requiring the Partnership to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio (each as defined in the credit agreement) of 5.5 to 1, reducing to 4.5 to 1 on September 30, 2005 and thereafter; and an interest coverage ratio (as defined in the credit agreement) of at least 3.0 to 1. The Partnership is in compliance with these covenants as of September 30, 2005. Based upon the definitions set forth within the credit agreement, the Partnership’s ratio of total debt to EBITDA was 3.7 to 1 and the interest coverage ratio was 4.8 to 1 at September 30, 2005.

NOTE 10 — COMMITMENTS AND CONTINGENCIES

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

     On March 9, 2004, the Oklahoma Tax Commission (“OTC”) filed a petition against Spectrum alleging that Spectrum 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 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 September 30, 2005, we are committed to expend approximately $36.6 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $13.1 million related to the Sweetwater Plant (see further description at “Subsequent Event”).

NOTE 11 — 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 September 30, 2005.

     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 units at an exercise price determined by the Committee at its discretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of the General Partner, the Committee will determine the vesting period for phantom units and the exercise period for options. Through September 30, 2005, 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. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the LTIP. Of the units outstanding under the LTIP at September 30, 2005, 31,214 units will vest within the following twelve months.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 11 — LONG-TERM INCENTIVE PLAN — (Continued)

     The Partnership accounts for equity awards under the LTIP in accordance with the provisions of APB No. 25 and its interpretations, which allows for valuation of these awards at their intrinsic values. Under this methodology, the Partnership recognizes compensation expense for phantom units granted at their fair value at the date of grant. For options granted, the Partnership recognizes compensation expense at the date of the grant only if the current market price of the underlying units exceeds the exercise price.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Outstanding, beginning of period			264,846				57,752				58,752				—
Granted(1)			—				1,000				67,338				59,598
Performance factor adjusted(2)			(57,743	)			—				82,468				—
Matured			(14,250	)			—				(14,686	)			—
Forfeited			—				—				(1,019	)			(846	)
Outstanding, end of period			192,853				58,752				192,853				58,752
Non-cash compensation expense recognized (in thousands)		$	655			$	305			$	2,809			$	342

NOTE 12 — RELATED PARTY TRANSACTIONS

     On June 30, 2005, Resource America, Inc. (“RAI”) distributed its 10.7 million shares of Atlas to its shareholders. In connection with this distribution of Atlas common stock to its shareholders, RAI and Atlas entered into various agreements, including shared services and a tax matters agreement, which govern the ongoing relationship between the two companies. The Partnership is dependent upon the resources and services provided by Atlas, and through these agreements, RAI and its affiliates. Accounts receivable/payable — affiliates represents the net balance due from/to Atlas for natural gas transported through the gathering systems, net of reimbursements for Partnership costs and expenses paid by Atlas. Substantially all Partnership revenue in Appalachia is from Atlas.

     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. 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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 12 — RELATED PARTY TRANSACTIONS — (Continued)

     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 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 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 $0.4 million for both the three months ended September 30, 2005 and 2004, and $1.4 million and $0.7 million for the nine months ended September 30, 2005 and 2004, respectively, for compensation and benefits related to their executive officers. For the three months ended September 30, 2005 and 2004, direct reimbursements were $5.2 million and $2.7 million, respectively, and $17.1 million and $7.2 million for the nine months ended September 30, 2005 and 2004, 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, Atlas 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 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 13 — 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 gathering and processing located in the Mid-Continent area (“Mid-Continent”) of southern Oklahoma and northern Texas. 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 to purchasers at the tailgate of the processing plants. These operating segments reflect the way the Partnership manages its operations.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 13 — OPERATING SEGMENT INFORMATION (Continued)

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Mid-Continent:
Revenues
Natural gas and liquids		$	96,234			$	30,048			$	218,268			$	30,048
Interest income and other			60				24				77				24
Total revenues and other income			96,294				30,072				218,345				30,072
Costs and expenses
Natural gas and liquids			82,537				24,588				184,578				24,588
Plant operating			2,745				931				7,242				931
General and administrative			1,258				634				4,307				634
Depreciation and amortization			2,739				613				6,597				613
Total costs and expenses			89,279				26,766				202,724				26,766
Segment profit		$	7,015			$	3,306			$	15,621			$	3,306
Appalachia:
Revenues
Transportation and compression — affiliates		$	6,248			$	4,645			$	16,447			$	13,292
Transportation and compression — third parties			16				20				54				52
Interest income and other			87				142				275				258
Total revenues and other income			6,351				4,807				16,776				13,602
Costs and expenses
Transportation and compression			871				564				2,169				1,709
General and administrative			801				551				2,410				1,133
Depreciation and amortization			699				408				1,898				1,519
Total costs and expenses			2,371				1,523				6,477				4,361
Segment profit		$	3,980			$	3,284			$	10,299			$	9,241
Reconciliation of segment profit to net income:
Segment profit
Mid-Continent		$	7,015			$	3,306			$	15,621			$	3,306
Appalachia			3,980				3,284				10,299				9,241
Total segment profit			10,995				6,590				25,920				12,547
General and administrative			(784	)			(552	)			(2,411	)			(1,134	)
Interest			(3,166	)			(1,076	)			(8,478	)			(1,202	)
Terminated acquisition costs			9				(2,987	)			(138	)			(2,987	)
Net income		$	7,054			$	1,975			$	14,893			$	7,224

ATLAS PIPELINE PARTNERS, .P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SEPTEMBER 30, 2005
(Unaudited)

NOTE 13 — OPERATING SEGMENT INFORMATION — (Continued)

		September 30,				December 31,
		2005				2004
Balance sheet
Total assets:
Mid-Continent		$	426,628			$	157,675
Appalachia			40,766				39,400
Corporate other			17,064				19,710
		$	484,458			$	216,785
Goodwill:
Mid-Continent		$	77,896			$	—
Appalachia			2,305				2,305
		$	80,201			$	2,305

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Natural gas and liquids:
Natural gas		$	54,970			$	15,973			$	122,837			$	15,973
NGLs			37,827				14,031				86,761				14,031
Condensate			1,547				(294	)			3,768				(294	)
Other (1)			1,890				338				4,902				338
Total		$	96,234			$	30,048			$	218,268			$	30,048
Transportation and Compression:
Affiliates		$	6,248			$	4,645			$	16,447			$	13,292
Third parties			16				20				54				52
Total		$	6,264			$	4,665			$	16,501			$	13,344

NOTE 14 — SUBSEQUENT EVENTS

     On October 31, 2005, the Partnership acquired all of the outstanding equity interests in a subsidiary of OGE Energy Corp. which owns a 75% operating interest in NOARK Pipeline System, Limited Partnership (“NOARK”). NOARK’s assets include a FERC-regulated interstate pipeline and an unregulated natural gas gathering system. Total consideration of $173.2 million, including $10.2 million for working capital adjustments, was funded through borrowings under the Partnership’s amended credit facility, which was increased to a borrowing capacity of $400 million.

     On October 19, 2005, the Partnership announced plans to construct a new 120 mmcf/d cryogenic gas processing plant in Beckham County, Oklahoma. The new facility, to be known as the Sweetwater gas plant, will be located west of the Partnership’s Elk City gas plant, and is being built to further access natural gas production actively being developed in western Oklahoma and the Texas panhandle. The Partnership expects the Sweetwater plant to be completed in the third quarter of 2006.

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 1, under the caption “Risk Factors”, in our annual report on Form 10-K for 2004. 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 notes thereto appearing elsewhere in this report.

General

     Our principal business objective is to generate cash for distribution to our unitholders. Our business is conducted in the midstream segment of the natural gas industry and we are active in the Appalachian and Mid-Continent areas of the United States, specifically, Pennsylvania, Ohio, New York, Oklahoma and Texas.

     In Appalachia, we gather natural gas through our pipeline system from more than 5,120 wells for delivery to a variety of customers on major intra- and/or interstate pipeline systems and a limited number of direct end-users. This transported gas is primarily controlled by Atlas America, Inc., the parent company of our general partner.

     Our Mid-Continent operations began in July 2004 upon our acquisition of Spectrum Field Services, Inc. in Velma, Oklahoma. We refer to the Spectrum assets as our Velma operations. During the nine months ended September 30, 2005, we gathered 69.1 million cubic feet (“mmcf”) of gas per day in our Velma system. This gas is then transported to our processing facilities where the natural gas liquids, or NGLs, along with various impurities are removed. The remaining pipeline quality gas is then delivered into a major intra- and/or interstate pipeline system where it is sold at market prices. The NGLs are similarly delivered into a separate major intrastate liquids product pipeline system where they are also sold for a price determined by the value of the actual components of that liquid stream, such as ethane, butane, propane and natural gasoline.

     Our Elk City operations began in April 2005 upon our acquisition of ETC Oklahoma Pipeline, Ltd., in Elk City, Oklahoma. For the nine months ended September 30, 2005, we gathered 242.3 mmcf of gas per day in our Elk City system. Our Elk City operations transport, process and sell natural gas similarly to our Velma operations.

Spectrum Acquisition

     On July 16, 2004, we acquired our Velma gathering system for approximately $141.6 million, including the payment of income taxes due as a result of the transaction. This acquisition significantly increased our size and diversified the natural gas supply basins in which we operate and the natural gas midstream services we provide to our customers.

Elk City Acquisition

     On April 14, 2005, we acquired Elk City from affiliates of Energy Transfer Partners, L.P. (NYSE: ETP) for $196.0 million in cash, including related transaction costs. We financed the Elk City acquisition, including related transaction costs, through a $45.0 million term loan and $204.5 million revolving loan under our new $270.0 million senior secured term loan and revolving credit facility administered by Wachovia Bank.

Fee Arrangements

     In Appalachia, substantially all of the gas we transport is for Atlas America under percentage of proceeds, or POP, contracts (as described below) where 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 $0.40 per thousand cubic feet, or mcf. Since our inception in January 2000, our transportation fee has always exceeded this minimum. The balance of the Appalachian gas we transport is for third party operators generally under fixed fee contracts.

     Our revenues in the Mid-Continent area are determined primarily by the fees we earn from the following types of arrangements:

     Fee-Based Contracts. Under these contracts, we receive 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 that gas.

     Percent of Proceeds Contracts. Under these contracts, we 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 ultimate market value.

     Keep Whole Contracts. As a result of our acquired Elk City gathering systems, we have “keep whole” contracts. “Keep whole” contracts require the processor to bear the economic risk (called 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 the processor paid for the unprocessed natural gas. However, since gas received into our Elk City system is generally low in liquids content and meets downstream pipeline specifications without being processed, the gas can be bypassed around our Elk City processing plant and delivered directly into downstream pipelines during periods of margin risk.

     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 the past year, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during 2005. 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 these 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.

Results of Operations

     Our principal revenues are generated from the transportation and sale of residue gas and NGLs. Variables which affect our revenues are:

	•		the volumes of natural gas gathered, transported and processed by us 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 paid to us 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.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Mid-Continent
Velma
Natural Gas
Gross natural gas gathered — mcf/day			68,469				55,580				69,091				55,580
Gross natural gas processed — mcf/day			62,439				54,755				64,581				54,755
Gross residue natural gas — mcf/day			53,235				41,555				52,471				41,555
NGLs
Gross NGL sales — barrels/day			6,877				5,916				6,812				5,916
Condensate
Gross condensate sales — barrels/day			293				204				269				204
Elk City
Natural Gas
Gross natural gas gathered — mcf/day			240,774				—				242,294				—
Gross natural gas processed — mcf/day			115,913				—				116,688				—
Gross residue natural gas — mcf/day			106,783				—				107,182				—
NGLs
Gross NGL sales — barrels/day			5,130				—				5,317				—
Condensate
Gross condensate sales — barrels/day			123				—				121				—
Appalachia
Throughput — mcf/day			57,294				54,337				54,804				52,745
Average transportation rate per mcf		$	1.19			$	0.93			$	1.10			$	0.92
Total transportation and compression revenue (in thousands)		$	6,264			$	4,665			$	16,501			$	13,344