UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

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

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

Yes þ No o

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

Yes þ No o

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT
ON FORM 10-Q

		PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 (Unaudited)			3
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2005 and 2004 (Unaudited)			4
Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2005 (Unaudited)			5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004 (Unaudited)			6
Notes to Consolidated Financial Statements (Unaudited)			7 – 22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23 – 31
Item 3. Quantitative and Qualitative Disclosures About Market Risk			31 – 33
Item 4. Controls and Procedures			34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			34
Item 2. Unregistered Sales of Equity Securities and Uses of Proceeds			34
Item 3. Defaults Upon Senior Securities			34
Item 4. Submission of Matters to a Vote of Security Holders			34
Item 5. Other Information			34
Item 6. Exhibits			35
SIGNATURES			36
RULE 13a-14(a)/15d-14(a) CERTIFICATIONS
RULE 13a-14(a)/15d-14(a) CERTIFICATIONS
SECTION 1350 CERTIFICATIONS
SECTION 1350 CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)

		June 30,				December 31,
		2005				2004
ASSETS
Current assets:
Cash and cash equivalents		$	13,342			$	18,214
Accounts receivable-affiliates			3,488				1,496
Accounts receivable			29,565				13,769
Prepaid expenses			972				1,056
Total current assets			47,367				34,535
Property, plant and equipment, net			327,288				175,259
Goodwill			62,305				2,305
Other assets			7,362				4,686
		$	444,322			$	216,785
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	63			$	2,303
Accrued liabilities			11,355				3,144
Current portion of hedge liability			11,972				1,959
Accrued producer liabilities			23,364				10,996
Accounts payable			3,853				2,341
Distribution payable			9,492				6,467
Total current liabilities			60,099				27,210
Long-term hedge liability, less current portion			9,684				722
Long-term debt, less current portion			168,103				52,149
Commitments and contingencies
Partners’ capital:
Limited partners’ interests			221,754				135,761
General partner’s interest			3,954				2,261
Accumulated other comprehensive loss			(19,272	)			(1,318	)
Total partners’ capital			206,436				136,704
		$	444,322			$	216,785

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per unit data)
(Unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Revenues:
Natural gas and liquids		$	79,700			$	—			$	122,034			$	—
Transportation and compression — affiliates			5,352				4,454				10,199				8,647
Transportation and compression — third parties			23				15				38				32
Interest income and other			124				80				205				116
Total revenues and other income			85,199				4,549				132,476				8,795
Costs and expenses:
Natural gas and liquids			66,582				—				102,041				—
Plant operating			3,293				—				4,497				—
Transportation and compression			622				538				1,298				1,145
General and administrative			3,368				368				5,479				836
Compensation reimbursement — affiliates			440				215				953				328
Depreciation and amortization			3,128				593				5,057				1,111
Interest			4,177				63				5,312				126
Total costs and expenses			81,610				1,777				124,637				3,546
Net income		$	3,589			$	2,772			$	7,839			$	5,249
Allocation of net income:
Limited partners’ interest		$	1,573			$	2,359			$	4,403			$	4,481
General partner’s interest			2,016				413				3,436				768
Net income		$	3,589			$	2,772			$	7,839			$	5,249
Net income per limited partner unit — basic and diluted		$	0.20			$	0.47			$	0.58			$	0.95
Weighted average limited partner units outstanding:
Basic			7,938				5,039				7,573				4,697
Diluted			7,990				5,040				7,609				4,697

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
FOR THE SIX MONTHS ENDED JUNE 30, 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				—				91,661				—				—				—				91,661
Issuance of common units under long-term incentive plan			331				—				14				—				—				—				14
Capital contributions			—				—				—				—				1,930				—				1,930
Unissued common units under long-term incentive plan			—				—				2,829				—				—				—				2,829
Distributions to partners			—				—				(5,404	)			—				(1,500	)			—				(6,904	)
Distribution payable			—				—				(7,319	)			—				(2,173	)			—				(9,492	)
Distribution equivalent rights paid on unissued units under long-term incentive plan			—				—				(191	)			—				—				—				(191	)
Other comprehensive loss			—				—				—				—				—				(17,954	)			(17,954	)
Net income			—				—				4,403				—				3,436				—				7,839
Balance at June 30, 2005			9,505,016				—			$	221,754			$	—			$	3,954			$	(19,272	)		$	206,436

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)

		Six Months Ended June 30,
		2005				2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	7,839			$	5,249
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			5,057				1,111
Non-cash gain on derivative value			(701	)			—
Non-cash compensation under long-term incentive plan			2,158				37
Amortization of deferred finance costs			1,475				76
Change in operating assets and liabilities, net of effects of acquisitions:
Increase in accounts receivable and prepaid expenses			(9,973	)			(452	)
Increase in accounts payable and accrued liabilities			18,816				247
(Increase) decrease in accounts receivable — affiliates			(1,992	)			1,416
Net cash provided by operating activities			22,679				7,684
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions			(195,622	)			—
Capital expenditures			(22,883	)			(2,521	)
Other			177				(2,004	)
Net cash used in investing activities			(218,328	)			(4,525	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility			256,000				—
Repayments under credit facility			(142,250	)			—
Distributions paid to partners			(13,371	)			(6,192	)
General partner capital contributions			1,930				512
Net proceeds from issuance of limited partner units			91,661				25,188
Other			(3,193	)			(365	)
Net cash provided by financing activities			190,777				19,143
Net change in cash and cash equivalents			(4,872	)			22,302
Cash and cash equivalents, beginning of period			18,214				15,078
Cash and cash equivalents, end of period		$	13,342			$	37,380

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 six month periods ended June 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.

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).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

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

Net Income Per Unit — (Continued)

     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 for the three and six months ended June 30, 2005 and 2004 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Weighted average number of limited partner units — basic			7,938				5,039				7,573				4,697
Add effect of dilutive unit incentive awards			52				1				36				—
Weighted average number of limited partner units — diluted			7,990				5,040				7,609				4,697

Receivables

     In evaluating its accounts receivable for impairment, 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 June 30, 2005 and December 31, 2004, the Partnership recorded no allowance for 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.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Net income		$	3,589			$	2,772			$	7,839			$	5,249
Other comprehensive loss:
Unrealized loss on hedging contracts			(10,947	)			—				(19,885	)			—
Add: reclassification adjustment for losses realized in net income			1,262				—				1,931				—
			(9,685	)			—				(17,954	)			—
Comprehensive (loss) income		$	(6,096	)		$	2,772			$	(10,115	)		$	5,249

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

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

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. The Partnership had unbilled revenues at June 30, 2005 and December 31, 2004 of $30.6 million and $15.3 million, respectively, included in accounts receivable and accounts receivable-affiliates within the consolidated balance sheets.

Goodwill

     At June 30, 2005 and December 31, 2004, the Partnership had $62.3 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 June 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

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

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

New Accounting Standards – (Continued)

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.

     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 June 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. 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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 3 – EQUITY OFFERINGS – (Continued)

     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.

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 June 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

     On June 13, 2005, the Partnership declared a cash distribution of $0.77 per unit on its outstanding limited partner units, representing the cash distribution for the quarter ended June 30, 2005. The $9.5 million distribution, including $2.2 million to the general partner, will be paid on August 5, 2005 to unitholders of record at the close of business on June 30, 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 the tests under the terms of the partnership agreement. While the general partner’s rights as the holder of the subordinated units are no longer subordinated to the rights of the common unitholders, these units have not yet been registered with the Securities and Exchange Commission and, therefore, their resale in the public market is subject to restrictions under the Securities Act.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

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

										Estimated
		June 30,				December 31,				Useful Lives
		2005				2004				in Years
Pipelines, processing and compression facilities		$	323,535			$	168,932				15 - 40
Rights of way			16,121				14,128				20 - 40
Buildings			3,397				3,215				40
Furniture and equipment			648				517				3 - 7
Other			470				307				3 - 10
			344,171				187,099
Less – accumulated depreciation			(16,883	)			(11,840	)
		$	327,288			$	175,259

     In April 2005, the Partnership completed the acquisition of ETC Oklahoma Pipeline, Ltd. for approximately $194.9 million (see Note 7). Due to its recent date of acquisition, the purchase price allocation is based upon estimated values determined by the Partnership, which are subject to adjustment and could change significantly as the Partnership continues to evaluate this allocation. At June 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):

		June 30,				December 31,
		2005				2004
Deferred finance costs, net of accumulated amortization of $856 and $506 at June 30, 2005 and December 31, 2004, respectively		$	4,997			$	3,316
Security deposits			1,728				1,356
Other			637				14
		$	7,362			$	4,686

     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 recognized $1.0 million of accelerated amortization of deferred financing costs associated with the retirement of the term portion of its $270 million credit facility.

NOTE 7 -ACQUISITIONS

Spectrum

     On July 16, 2004, the Partnership acquired Spectrum Field Services, Inc. (“Spectrum”), for approximately $143.1 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.” The following table presents the purchase price

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 7 – ACQUISITIONS – (Continued)

Spectrum – (Continued)

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			140,936
Other long-term assets			1,054
Total assets acquired			161,947
Accounts payable and accrued liabilities			(17,153	)
Hedging liabilities			(1,519	)
Long-term debt			(164	)
Total liabilities assumed			(18,836	)
Net assets acquired		$	143,111

     The results of the acquisition were included with the Partnership’s consolidated financial statements from its date of acquisition.

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 $194.9 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, “Business Combinations.” 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		$	4,577
Other assets			497
Property, plant and equipment			133,637
Goodwill			60,000
Total assets acquired			198,711
Accounts payable and accrued liabilities			(3,770	)
Total liabilities assumed			(3,770	)
Net assets acquired		$	194,941

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 7 – ACQUISITIONS – (Continued)

Elk City – (Continued)

     Due to its recent date of acquisition, the purchase price allocation for Elk City is based upon estimated values determined by the Partnership. These estimates are 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, from which the net proceeds 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								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Total revenues and other income		$	85,199			$	75,151			$	173,208			$	138,518
Net income		$	4,651			$	4,560			$	7,555			$	6,494
Net income per limited partner unit, basic and diluted		$	0.33			$	0.82			$	0.54			$	1.21

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 options fix the price for the Partnership within the puts purchased and calls sold.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS – (Continued)

     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 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 June 30, 2005, the Partnership reflected a net hedging liability on its balance sheet of $19.9 million. Of the $19.3 million net loss in other comprehensive income (loss) at June 30, 2005, $10.3 million of losses will be reclassified to the consolidated statements of income over the next twelve month period as these contracts expire, and $9.0 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 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 a loss of $1.3 million and $1.9 million related to these hedging instruments during the three and six months ended June 30, 2005, respectively. These losses are included within natural gas and liquids revenue on the Partnership’s consolidated statements of income. There were no hedging instruments outstanding during the three and six months ended June 30, 2004.

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

Natural Gas Basis Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(3)
Ended June 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			1,260,000			$	(0.537	)		$	(83	)
2007			1,140,000				(0.530	)			(67	)
2008			780,000				(0.541	)			(55	)
										$	(205	)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS – (Continued)

Plant Volume Reduction Basis Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Asset(3)
Ended June 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			1,800,000			$	(0.478	)		$	12
2007			900,000				(0.495	)			21
										$	33

Natural Gas Liquids Fixed – Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(2)
Ended June 30,		(gallons)				(per gallon)				(in thousands)
2006			37,104,000			$	0.662			$	(9,235	)
2007			24,570,000				0.686				(5,821	)
2008			9,954,000				0.698				(2,079	)
										$	(17,135	)

Natural Gas Fixed – Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(3)
Ended June 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			1,200,000			$	6.594			$	(1,419	)
2007			1,140,000				7.131				(889	)
2008			780,000				7.260				(235	)
										$	(2,543	)

Crude Oil Fixed – Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Liability(3)
Ended June 30,		(barrels)				(per barrel)				(in thousands)
2006			54,450			$	51.558			$	(403	)
2007			74,400				53.638				(358	)
2008			55,200				55.875				(91	)
										$	(852	)

Plant Volume Reduction Fixed – Price Swaps

Production						Average				Fair Value
Period		Volumes				Fixed Price				Asset(3)
Ended June 30,		(MMBTU)(1)				(per MMBTU)				(in thousands)
2006			1,650,000			$	7.205			$	995
2007			900,000				7.255				548
										$	1,543

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 8 – DERIVATIVE INSTRUMENTS – (Continued)

Crude Oil Options

Production										Average				Fair Value
Period						Volumes				Strike Price				Liability(3)
Ended June 30,		Option Type				(barrels)				(per barrel)				(in thousands)
2006		Puts purchased					30,000			$	30.00			$	—
2006		Calls sold					30,000				34.25				(721	)
														$	(721	)
										Total net liability				$	(19,880	)

NOTE 9 — LONG-TERM DEBT

     Total debt consists of the following (in thousands):

		June 30,				December 31,
		2005				2004
Credit Facility:
Revolving credit facility		$	168,000			$	10,000
Term loan			—				44,250
Other debt			166				202
			168,166				54,452
Less current maturities			(63	)			(2,303	)
		$	168,103			$	52,149

     On April 14, 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 June 30, 2005 was 6.07%. Up to $10.0 million of the credit facility may be utilized for letters of credit, of which $8.2 million is outstanding at June 30, 2005 and is not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the Credit Facility are secured by a lien on and security interest in all of the Partnership’s property and that of its subsidiaries, and by the guaranty of each of the Partnership’s subsidiaries.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 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 June 30, 2005. Based upon the definitions set forth within the credit agreement, the Partnership’s ratio of total debt to EBITDA was 4.1 to 1 and the interest coverage ratio was 4.5 to 1 at June 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.

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 of directors. The Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the LTIP through June 30, 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 June 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

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

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

in the LTIP. Of the units outstanding under the LTIP at June 30, 2005, 31,214 units will vest within the following twelve months.

     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								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Outstanding, beginning of period			125,201				1,692				58,752				—
Granted(1)			—				56,906				67,338				58,598
Performance factor adjusted(2)			140,211				—				140,211				—
Matured			(226	)			—				(436	)			—
Forfeited			(340	)			(846	)			(1,019	)			(846	)
Outstanding, end of period			264,846				57,752				264,846				57,752
Non-cash compensation expense recognized (in thousands)		$	1,709			$	70			$	2,158			$	72

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 and RAI and its affiliates for natural gas transported through the gathering systems, net of reimbursements for Partnership costs and expenses paid by Atlas and RAI and its affiliates. Substantially all Partnership revenue in Appalachia is from Atlas and RAI and its affiliates.

     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 RAI and/or the Affiliates. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 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 the Affiliates based on the number of their employees who devote substantially all of their time to activities on the Partnership’s behalf. The Partnership reimburses the Affiliates 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 and $0.2 million for the three months ended June 30, 2005 and 2004, respectively, and $1.0 million and $0.3 million for the six months ended June 30, 2005 and 2004, respectively, for compensation and benefits related to their executive officers. For the three months ended June 30, 2005 and 2004, direct reimbursements were $7.6 million and $2.2 million, respectively, and $11.9 million and $4.5 million for the six months ended June 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 with the Affiliates, Atlas must construct up to 2,500 feet of sales lines from its existing wells in the Appalachian region to a point of connection to the Partnership’s gathering systems. The Partnership must, at its own cost, extend its system to connect to any such lines within 1,000 feet of its gathering systems. With respect to wells to be drilled by Atlas that will be more than 3,500 feet from the Partnership’s gathering systems, the Partnership has various options to connect those wells to its gathering systems at its own cost.

NOTE 13 — OPERATING SEGMENT INFORMATION

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

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 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								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Mid-Continent:
Revenues
Natural gas and liquids		$	79,700			$	—			$	122,034			$	—
Interest income and other			31				—				17				—
Total revenues and other income			79,731				—				122,051				—
Costs and expenses
Natural gas and liquids			66,582				—				102,041				—
Plant operating			3,293				—				4,497				—
General and administrative			2,298				—				3,049				—
Depreciation and amortization			2,503				—				3,858				—
Total costs and expenses			74,676				—				113,445				—
Segment profit		$	5,055			$	—			$	8,606			$	—
Appalachia:
Revenues
Transportation and compression — affiliates		$	5,352			$	4,454			$	10,199			$	8,647
Transportation and compression — third parties			23				15				38				32
Interest income and other			93				80				188				116
Total revenues and other income			5,468				4,549				10,425				8,795
Costs and expenses
Transportation and compression			622				538				1,298				1,145
General and administrative			741				291				1,609				582
Depreciation and amortization			625				593				1,199				1,111
Total costs and expenses			1,988				1,422				4,106				2,838
Segment profit		$	3,480			$	3,127			$	6,319			$	5,957
Reconciliation of segment profit to net income:
Segment profit
Mid-Continent		$	5,055			$	—			$	8,606			$	—
Appalachia			3,480				3,127				6,319				5,957
Total segment profit			8,535				3,127				14,925				5,957
General and administrative			(769	)			(292	)			(1,774	)			(582	)
Interest			(4,177	)			(63	)			(5,312	)			(126	)
Net income		$	3,589			$	2,772			$	7,839			$	5,249

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
JUNE 30, 2005
(Unaudited)

NOTE 13 — OPERATING SEGMENT INFORMATION — (Continued)

		June 30,				December 31,
		2005				2004
Balance sheet
Total assets:
Mid-Continent		$	395,319			$	157,675
Appalachia			30,503				39,400
Corporate other			18,500				19,710
		$	444,322			$	216,785
Goodwill:
Mid-Continent		$	60,000			$	—
Appalachia			2,305				2,305
		$	62,305			$	2,305

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Natural gas and liquids:
Natural gas		$	44,067			$	—			$	67,724			$	—
NGLs			31,549				—				48,933				—
Condensate			1,494				—				2,221				—
Other (1)			2,590				—				3,156				—
Total		$	79,700			$	—			$	122,034			$	—
Transportation and Compression:
Affiliates		$	5,352			$	4,454			$	10,199			$	8,647
Third parties			23				15				38				32
Total		$	5,375			$	4,469			$	10,237			$	8,679

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

Forward-Looking Statements

     When used in this Form 10-Q, the words “believes”, “anticipates”, “expects”, and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1, under the caption “Risk Factors”, in our annual report on Form 10-K for 2004. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

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

General

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

     In Appalachia, we gather natural gas through our pipeline system from more than 4,850 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 six months ended June 30, 2005 we gathered 69.4 million cubic feet (“mmcf”) of gas per day from approximately 150 producers in our Velma operations. 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. As of June 30, 2005 we gathered 244.1 mmcf of gas per day from approximately 130 producers in our Elk City operations. 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 $143.1 million, including the payment of income taxes due as a result of the transaction. This acquisition significantly increased our size and diversified the natural gas supply basins in which we operate and the natural gas midstream services we provide to our customers.

Elk City Acquisition

     On April 14, 2005, we acquired Elk City from affiliates of Energy Transfer Partners, L.P. (NYSE: ETP) for $194.9 million in cash, including related transaction costs. 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. We financed the Elk City acquisition, including approximately $2.8 million of transaction costs, by borrowing $45.0 million of the term loan portion and $204.5 million of the revolving loan portion of 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 residue natural gas and NGLs resulting from our gathering and processing operations, 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.

     Approximately 72% of the natural gas volumes and approximately 76% of the natural gas revenues of our Velma operations are derived from POP contracts. The percentage of the proceeds that we retain is negotiated and can vary greatly depending on a variety of factors and circumstances.

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

     As a result of our POP and keep whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas and NGLs. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. The number of active oil and gas rigs has increased in the past year, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during 2005. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

     We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices.

Results of Operations

     In the six months ended June 30, 2005, our principal revenues came from the sale of residue gas and NGLs. In the six months ended June 30, 2004, our principal revenues came from the operation of our Appalachia pipeline system. 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								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Mid-Continent
Elk City
Natural Gas
Gross natural gas gathered — mcf/day			244,088				—				244,088				—
Gross natural gas processed — mcf/day			118,000				—				118,000				—
Gross residue natural gas — mcf/day			108,000				—				108,000				—
NGLs
Gross NGL sales — barrels/day			5,537				—				5,537				—
Condensate
Gross condensate sales — barrels/day			119				—				119				—
Velma
Natural Gas
Gross natural gas gathered — mcf/day			73,810				—				69,408				—
Gross natural gas processed — mcf/day			68,326				—				65,671				—
Gross residue natural gas — mcf/day			56,893				—				53,456				—
Natural gas gross margin (in thousands) (1) ( 3)		$	2,378			$	—			$	4,897			$	—
NGLs
Gross NGL sales — barrels/day			7,149				—				6,778				—
NGL gross margin (in thousands) (2) (3)		$	4,797			$	—			$	8,760			$	—
Condensate
Gross condensate sales — barrels/day			278				—				256				—
Condensate sales (3)		$	1,259			$	—			$	1,961			$	—