Atlas Pipeline Partners 10-Q 2005 Q3 Quarterly report

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.

Yesx Noo

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

Yesx Noo

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

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)
(Unaudited)

	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

3

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)
(Unaudited)

	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

4

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005

(in thousands, except unit data)
(Unaudited)

															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

5

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)
(Unaudited)

	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

6

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2005
(Unaudited)

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).

7

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.

8

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.

9

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.

10

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.

11

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.

12

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.

13

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.

14

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

15

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.

16

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	)

17

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	)

(1)	MMBTU represents million British Thermal Units.
(2)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

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.

18

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.

19

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

(1)	The weighted average price for phantom unit awards on the date of grant was $36.60 for awards granted for the three months ended September 30, 2004 and $48.58 and $37.14 for awards granted for the nine months ended September 30, 2005 and 2004, respectively. There were no units awarded for the three months ended September 30, 2005.
(2)	Consists of adjustments to performance-based awards to reflect actual performance.

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.

20

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.

21

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

22

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

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

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.

23

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

Forward-Looking Statements

     When used in thisForm 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 onForm 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 thisForm 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.

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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.

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     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

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Third Quarter 2005 Compared with Third Quarter 2004

     Revenues

     Natural gas and liquids revenues were $96.2 million for the three months ended September 30, 2005, an increase of $66.2 million from $30.0 million for the third quarter 2004. The increase was primarily attributable to contribution from the Elk City system, acquired in April 2005, a full quarter’s results and higher volumes from the Velma system, acquired in July 2004, and an increase in commodity prices between periods. For the third quarter 2005, 15 new wells were connected to the Velma system compared with 7 new wells connected for the third quarter 2004. Overall, 112 new wells were connected to the Velma system for the twelve months ended September 30, 2005. Gross natural gas gathered averaged 68.5 mmcf per day on the Velma system for the third quarter 2005, an increase of 23% from the third quarter 2004. On the Elk City system, 17 new wells were connected to its gas gathering pipelines for the third quarter 2005, and 26 new wells since April 14, 2005, its date of acquisition. Gross natural gas gathered on the Elk City system averaged 240.8 mmcf per day for the third quarter 2005.

     Appalachia transportation and compression revenues increased to $6.3 million for the three months ended September 30, 2005 from $4.7 million for the third quarter 2004. This $1.6 million increase was primarily due to an increase in the average transportation rate earned and an increase in the volumes of natural gas we transported. Our average transportation rate was $1.19 per mcf for the third quarter 2005 as compared to $0.93 per mcf for the prior year third quarter, an increase of $0.26 per mcf. Our average daily throughput volumes were 57.3 mmcf for the third quarter 2005 as compared with 54.3 mmcf for the third quarter 2004, an increase of 3.0 mmcf. The increase in the average daily throughput volume was principally due to new wells connected to our gathering system and the completion of a capacity expansion project on certain sections of our pipeline system during the current period. For the third quarter 2005, 151 new wells were connected to our Appalachia system compared with 75 new wells connected for the third quarter 2004. For the twelve months ended September 30, 2005, we connected 442 new wells to the Appalachia system as compared with 340 new wells for the comparable prior year period.

     Costs and Expenses

     Natural gas and liquids cost of goods sold of $82.5 million and plant operating expenses of $2.7 million for the three months ended September 30, 2005 represented increases of $58.0 million and $1.8 million, respectively, from the prior year’s third quarter amounts due primarily to full quarter contributions from the acquisitions, higher volumes from the Velma system, and an increase in commodity prices. Appalachia transportation and compression expenses increased $0.3 million to $0.9 million for the third quarter 2005 due mainly to higher operating costs as a result of compressors added in connection with our capacity expansion project.

     General and administrative expenses, including amounts reimbursed to affiliates, increased $1.1 million to $2.8 million for the third quarter 2005 compared with $1.7 million for the prior year third quarter. This increase was mainly due to a $0.5 million increase in non-cash compensation expense related to phantom units issued under our long-term incentive plan and $0.6 million of expenses associated with the acquisitions. Depreciation and amortization increased to $3.4 million for the third quarter 2005 compared with $1.0 million for the third quarter 2004 due principally to the increased asset base associated with the acquisitions.

     Interest expense increased to $3.2 million for the three months ended September 30, 2005 as compared with $1.1 million for the third quarter 2004. This $2.1 million increase was primarily due to interest associated with borrowings under the credit facility to finance the acquired assets. For the third quarter 2004, we incurred $3.0 million of costs in connection with our terminated attempt to acquire Alaska Pipeline Company and subsequent legal action. We settled the matter in the fourth quarter 2004 and received $5.5 million.

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Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004

     Revenues

     Natural gas and liquids revenues were $218.3 million for the nine months ended September 30, 2005, an increase of $188.3 million from $30.0 million for the first nine months of 2004. The increase was primarily attributable to contributions from the Elk City system, acquired in April 2005, and the Velma system, acquired in July 2004, and an increase in commodity prices between periods. Gross natural gas gathered averaged 69.1 mmcf per day on the Velma system for the first nine months of 2005, an increase of 24% from the first nine months of 2004. Gross natural gas gathered on the Elk City system averaged 242.3 mmcf per day from its date of acquisition through September 30, 2005.

     Appalachia transportation and compression revenues increased to $16.5 million for the nine months ended September 30, 2005 from $13.3 million for the first nine months of 2004. This $3.2 million increase was primarily due to an increase in the average transportation rate earned and an increase in the volumes of natural gas we transported. Our average transportation rate was $1.10 per mcf for the nine months ended September 30, 2005 as compared to $0.92 per mcf for the prior year comparable period, an increase of $0.18 per mcf. Our average daily throughput volumes were 54.8 mmcf for the first nine months of 2005 as compared with 52.7 mmcf for the prior year comparable period, an increase of 2.1 mmcf. The increase in the average daily throughput volume was principally due to new wells connected to our gathering system and the completion of a capacity expansion project on certain sections of our pipeline system during the current period.

     Costs and Expenses

     Natural gas and liquids cost of goods sold of $184.6 million and plant operating expenses of $7.2 million for the nine months ended September 30, 2005 represented increases of $160.0 million and $6.3 million, respectively, from the prior year’s comparable period amounts due primarily to contributions from the acquisitions and an increase in commodity prices. Appalachia transportation and compression expenses increased $0.5 million to $2.2 million for the first nine months of 2005 due mainly to higher operating costs as a result of compressors added in connection with our capacity expansion project and higher maintenance expense as a result of additional wells connected to the pipeline.

     General and administrative expenses, including amounts reimbursed to affiliates, increased $6.2 million to $9.1 million for the nine months ended September 30, 2005 compared with $2.9 million for the prior year comparable period. This increase was mainly due to a $2.6 million increase in non-cash compensation expense related to phantom units issued under our long-term incentive plan and $3.7 million of expenses associated with the acquisitions. Depreciation and amortization increased to $8.5 million for the nine months ended September 30, 2005 compared with $2.1 million for the first nine months of 2004 due principally to the increased asset base associated with the acquisitions.

     Interest expense increased to $8.5 million for the nine months ended September 30, 2005 as compared with $1.2 million for the prior year comparable period. This $7.3 million increase was primarily due to interest associated with borrowings under the credit facility to finance the acquired assets and $1.0 million of accelerated amortization of deferred financing costs. This accelerated amortization was associated with the retirement of the term portion of our $270 million credit facility in April 2005. For the third quarter 2004, we incurred $3.0 million of costs in connection with our terminated attempt to acquire Alaska Pipeline Company and subsequent legal action. We settled the matter in the fourth quarter 2004 and received $5.5 million.

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Liquidity and Capital Resources

General

     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 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 common units.

     At September 30, 2005, we had $183.5 million of outstanding borrowings under our credit facility, with $41.5 million of available borrowing capacity. Our percentage of total debt to total book capitalization, which is the sum of total debt and total partners’ capital, was 50% at September 30, 2005 compared with 28% at December 31, 2004. This increase was mainly due to additional borrowings to finance the acquisition of the Elk City assets for $196.0 million in April 2005 and a $45.1 million increase in accumulated other comprehensive loss within partners’ capital as a result of the change in fair value of certain hedging instruments. In addition to the availability under the credit facility, we have a $500 million universal shelf registration statement on file with the Securities and Exchange Commissions, of which the entire amount is available, which allows us to issue up to $500 million of equity or debt securities. We also had a working capital deficit of $9.6 million at September 30, 2005 compared with working capital of $7.3 million at December 31, 2004. This decrease was primarily due to an increase in the current portion of our net hedge liability between periods and is reflected in the change in fair-market value of our derivative instruments based on the subsequent increases in the price of natural gas after we entered into the hedges. These price increases will be reflected in our consolidated statements of income when the contracts settle.

Cash Flows

     Net cash provided by operating activities of $27.1 million for the nine months ended September 30, 2005 increased $9.4 million from $17.7 million for the first nine months of 2004. The increase is derived principally from increases in net income of $7.7 million, depreciation and amortization of $6.4 million, and non-cash compensation expense of $3.3 million, partially offset by a decrease in cash provided by working capital of $7.9 million. The increases in net income and depreciation and amortization were principally due to the contribution from the acquisitions of Spectrum in July 2004 and Elk City in April 2005. The decrease in cash provided by working capital between periods is mainly due to timing of settlement of accounts receivable due from Atlas.

     Net cash used in investing activities was $229.9 million for the nine months ended September 30, 2005, an increase of $84.2 million from $145.7 million for the first nine months of 2004. This increase was principally due to the acquisitions mentioned previously and a $30.1 million increase in capital expenditures. See further discussion of capital expenditures under “Capital Requirements.”

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     Net cash provided by financing activities was $196.6 million for the nine months ended September 30, 2005, an increase of $54.7 million from $141.9 million for the first nine months of 2004. This increase was principally due to a $69.3 million increase in net borrowings under our credit facility, mainly to fund the acquisition of the Elk City assets, partially offset by an increase in cash distributions to partners of $13.0 million due primarily to an increase in limited partner units outstanding and the distribution amount per 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. The capital requirements for our operations 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 to grow our operations 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				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Maintenance capital expenditures	$	245	$	247	$	1,110	$	844
Expansion capital expenditures		11,391		1,651		33,409		3,575
Total	$	11,636	$	1,898	$	34,519	$	4,419

     Expansion capital expenditures increased to $11.4 million and $33.4 million for the three and nine months ended September 30, 2005, respectively, due principally to expansions of the Velma and Elk City gathering systems and processing facilities to accommodate new wells drilled in our service areas. In addition, expansion capital expenditures increased due to compressor upgrades and gathering system expansions in the Appalachian region. Maintenance capital expenditures for the three and nine months ended September 30, 2005 remained relatively consistent compared with the prior year periods. 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”). We anticipate that our expansion capital expenditures will increase for the remainder of 2005 as a result of an increase in the estimated number of well connections to our gathering systems.

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Credit Facility

     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, we entered into a new $270.0 million credit facility with a syndicate of banks, which replaced our existing $135.0 million facility. The facility was originally 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. The revolving portion of the credit facility bears interest, at our option, at either (i) Adjusted LIBOR plus an 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 our consolidated balance sheet. Borrowings under the facility are secured by a lien on and security interest in all of our property and that of our subsidiaries, and by the guaranty of each of our 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 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. The credit facility also contains covenants requiring us 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. We are in compliance with these covenants as of September 30, 2005. Based upon the definitions set forth within the credit agreement, our 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.

Subsequent Events

     On October 19, 2005, we 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 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. We expect the Sweetwater plant to be completed in the third quarter of 2006.

     On October 31, 2005, we 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 Parntership (“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 our amended credit facility, which was increased to a borrowing capacity of $400 million.

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Contractual Obligations and Commercial Commitments

     The following tables summarize our contractual obligations and commercial commitments at September 30, 2005:

			Payments Due By Period
			Less than		1 - 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Long-term debt(1)	$	183,645	$	63	$	82	$	183,500	$	—
Operating leases		3,663		1,948		1,427		288		—
Total contractual cash obligations	$	187,308	$	2,011	$	1,509	$	183,788	$	—

⁽¹⁾ Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2005: 2006 — $12.3 million; 2007 — $12.3 million; 2008 - $12.3 million; 2009 — $12.3 million; and 2010 — $6.6 million.

     The operating leases represent lease commitments for compressors, office space, and office equipment with varying expiration dates. These commitments are routine and were made in the normal course of our business.

			Amount of Commitment Expiration Per Period
			Less than		1 - 3		4 - 5		After 5
Other commercial commitments:	Total		1 Year		Years		Years		Years
Standby letters of credit	$	7,692	$	7,667	$	25	$	—	$	—
Other commercial commitments		36,642		36,642		—		—		—
Total commercial commitments	$	44,334	$	44,309	$	25	$	—	$	—

     Other commercial commitments relate to commitments to install new compressors and sales lines for new well hookups, and expenditures for pipeline extensions.

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, 2004, and there have been no material changes to these policies through September 30, 2005.

New Accounting Standards

     See discussion of new accounting pronouncements in Note 2 within the accompanying consolidated financial statements.

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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 reasonably 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.

     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 periodic use of derivative financial instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2005. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

     Interest Rate Risk.At September 30, 2005, we had a $225.0 million revolving credit facility ($183.5 million outstanding) to fund the expansion of our existing gathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. The weighted average interest rate for these borrowings was 6.6% at September 30, 2005. Holding all other variables constant, a 1% change in interest rates would change interest expense by $1.8 million.

     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 for 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% increase in the average price of NGLs, natural gas and crude oil we process and sell would result in an increase or decrease to our 2005 annual income of approximately $2.1 million.

     We enter into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133. We enter into these instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. 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 pay 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 we determine 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 fair value for the derivative will be recognized immediately within our consolidated statements of income.

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     We record derivatives on the 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 income (loss) and reclassify them to earnings as such transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within the consolidated statements of income as they occur. At September 30, 2005 and December 31, 2004, we reflected net hedging liabilities on our 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, we will reclassify $22.7 million of losses to our consolidated statements of income over the next twelve month period as these contracts expire, and $23.7 million will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within our consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. We 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 our consolidated statements of income related to the settlement of qualifying hedge instruments. We 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 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 September 30, 2005, we 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		(0.521	)		1,584
2008		510,000		(0.544	)		1,383
						$	4,343

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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	)

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	)

(1)	MMBTU represents million British Thermal Units.
(2)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(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 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. In connection with our acquisitions of Spectrum in July 2004 and Elk City in April 2005, we have undertaken initial steps to implement a new version of our natural gas volume tracking and allocation software. The upgrade is expected to be completed by December 31, 2005 and is expected to enhance the overall operating effectiveness of our internal controls.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     We are a party to various routine legal proceedings arising out of the ordinary course of business. Management believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on our 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. We plan on defending ourselves 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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USES OF PROCEEDS

     None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None

ITEM 5. OTHER INFORMATION

     None

ITEM 6. EXHIBITS

Exhibit No.		Description
	2.1	Stock Purchase Agreement, dated September 21, 2005, by and between Enogex Inc. and Atlas Pipeline Partners, L.P.
		Schedules omitted. The registrant will file the omitted schedules with the Securities and Exchange Commission upon request.
	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

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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:	November 2, 2005	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:	November 2, 2005	By:	/s/ MICHAEL L. STAINES
			Michael L. Staines President, Chief Operating Officer and Managing Board Member of the General Partner
Date:	November 2, 2005	By:	/s/ MATTHEW A. JONES
			Matthew A. Jones Chief Financial Officer of the General Partner
Date:	November 2, 2005	By:	/s/ SEAN P. MCGRATH
			Sean P. McGrath Chief Accounting Officer of the General Partner

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