Atlas Pipeline Partners 10-Q 2004 Q2 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 June 30, 2004

OR

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

For the transition period from _________ to _________

Commission file number: 1-4998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

Yes [X]     No [ ]

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

Yes [X]    No [ ]

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, 2004 (Unaudited) and
	December 31, 2003	3
	Consolidated Statements of Income for the Three and Six Months Ended
	June 30, 2004 and 2003 (Unaudited)	4
	Consolidated Statement of Partners' Capital for the Six Months Ended
	June 30, 2004 (Unaudited)	5
	Consolidated Statements of Cash Flows for the Six Months Ended
	June 30, 2004 and June 30, 2003 (Unaudited)	6
	Notes to Consolidated Financial Statements - June 30, 2004 (Unaudited)	7 - 13
Item 2.	Management's Discussion and Analysis of Financial Condition and Results
	of Operations	14 - 22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	24
PART II	OTHER INFORMATION
Item 4.	Submission of Matters to a Vote of Security Holders	25
Item 6.	Exhibits and Reports on Form 8-K	25
SIGNATURES		26

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	June 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	37,380,400		$	15,078,100
Accounts receivable		5,700			12,300
Prepaid expenses		238,900			66,600
Total current assets		37,625,000			15,157,000
Property and equipment:
Gas gathering and transmission facilities		39,435,500			37,018,200
Less - accumulated depreciation		(8,479,600	)		(7,390,100	)
Net property and equipment		30,955,900			29,628,100
Goodwill (net of accumulated amortization of $285,300)		2,304,600			2,304,600
Other assets (net of accumulated amortization of $182,000
and $106,100)		5,084,200			2,422,400
	$	75,969,700		$	49,512,100
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	804,800		$	520,900
Accounts payable - affiliates		3,088,400			1,672,900
Distribution payable		3,654,300			3,073,200
Total current liabilities		7,547,500			5,267,000
Commitment and contingencies		--			--
Partners' capital (deficit):
Common unitholders, 3,463,659 and 2,713,659 units outstanding		67,764,400			43,551,400
Subordinated unitholder, 1,641,026 units outstanding		(151,000	)		354,200
General partner		808,800			339,500
Total partners' capital		68,422,200			44,245,100
	$	75,969,700		$	49,512,100

See accompanying notes to consolidated financial statements

3

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Revenues:
Transportation and compression	$	4,468,400	$	4,325,000	$	8,678,700	$	7,653,400
Interest income and other		80,500		23,300		116,100		24,400
Total revenues		4,548,900		4,348,300		8,794,800		7,677,800
Costs and expenses:
Transportation and compression		537,900		615,800		1,144,700		1,224,000
General and administrative		582,500		546,600		1,163,600		865,700
Depreciation and amortization		592,000		421,000		1,110,700		827,700
Interest expense		63,800		79,000		126,500		162,500
Total costs and expenses		1,776,200		1,662,400		3,545,500		3,079,900
Net income	$	2,772,700	$	2,685,900	$	5,249,300	$	4,597,900
Net income - limited partners	$	2,359,200	$	2,479,400	$	4,480,700	$	4,259,200
Net income - general partner	$	413,500	$	206,500	$	768,600	$	338,700
Basic net income per limited partner unit	$	.47	$	.63	$	.95	$	1.18
Weighted average limited partner
units outstanding - basic		5,038,751		3,934,493		4,696,718		3,600,196
Diluted net income per limited partner unit	$	.47	$	.63	$	.95	$	1.18
Weighted average limited partner
units outstanding - diluted		5,055,262		3,934,493		4,705,939		3,600,196

See accompanying notes to consolidated financial statements

4

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
FOR THE SIX MONTHS ENDED JUNE 30, 2004
(Unaudited)

	Number of Limited Partner Units										General			Total Partners' Capital
	Common		Subordinated		Common			Subordinated			Partner			(Deficit)
Balance at January 1, 2004		2,713,659		1,641,026	$	43,551,400		$	354,200		$	339,500		$	44,245,100
Issuance of common units,     net of offering costs		750,000		--		25,187,800			--			--			25,187,800
Capital contribution		--		--		--			--			512,700			512,700
Distribution to partners		--		--		(1,710,700	)		(1,033,800	)		(373,900	)		(3,118,400	)
Distribution payable		--		--		(2,182,400	)		(1,033,800	)		(438,100	)		(3,654,300	)
Net income		--		--		2,918,300			1,562,400			768,600			5,249,300
Balance at June 30, 2004		3,463,659		1,641,026	$	67,764,400		$	(151,000	)	$	808,800		$	68,422,200

See accompanying notes to consolidated financial statements

5

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND 2003
(Unaudited)

	June 30, 2004			June 30, 2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	5,249,300		$	4,597,900
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		1,110,700			827,700
Loss on disposal of fixed assets		7,800			--
Amortization of deferred finance costs		75,900			56,200
Change in operating assets and liabilities:
Increase in accounts receivable and prepaid expenses		(459,500	)		(2,700	)
Increase (decrease) accounts payable and accrued liabilities		283,900			(447,700	)
Increase in accounts payable - affiliates		1,415,500			--
Net cash provided by operating activities		7,683,600			5,031,400
CASH FLOWS FROM INVESTING ACTIVITIES:
Increase in other assets		(2,078,600	)		--
Proceeds from disposal of fixed assets		75,000			--
Capital expenditures		(2,521,300	)		(2,154,400	)
Net cash used in investing activities		(4,524,900	)		(2,154,400	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on revolving credit facility		--			2,000,000
Repayments of revolving credit facility		--			(8,500,000	)
Capital contributions		512,700			510,700
Issuance of common units, net of offering costs		25,187,800			25,255,300
Distributions paid to partners		(6,191,600	)		(3,835,500	)
Increase in other assets		(365,300	)		(279,900	)
Net cash provided by financing activities		19,143,600			15,150,600
Increase in cash and cash equivalents		22,302,300			18,027,600
Cash and cash equivalents, beginning of period		15,078,100			1,858,600
Cash and cash equivalents, end of period	$	37,380,400		$	19,886,200
Supplemental Cash Flow Information:
Cash paid during the period for interest	$	75,800		$	79,100

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2004
(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

        The consolidated financial statements of Atlas Pipeline Partners, L.P. ("the Partnership") and its wholly-owned subsidiaries as of June 30, 2004 and for the three and six month periods ended June 30, 2004 and 2003 are unaudited. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods presented. The unaudited interim consolidated financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2003. The results of operations for the six month period ended June 30, 2004 may not necessarily be indicative of the results of operations for the full year ending December 31, 2004.

        Certain reclassifications have been made to the consolidated financial statements for the three and six month periods ended June 30, 2003 to conform to the presentation for the three and six month periods ended June 30, 2004.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        In addition to matters discussed below in this note, the Partnership’s significant accounting policies are detailed 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, 2003 filed with the Securities and Exchange Commission.

Fair Value of Financial Instruments

        For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair values because of the short maturities of these items.

Net Income Per Unit

        Basic net income per limited partner unit is determined by dividing net income, after deducting the general partner’s 2% and incentive interest, by the weighted average number of outstanding common units and subordinated units. Net income per unit — diluted is determined by dividing net income by the sum of the weighted average number of common and subordinated units outstanding and dilutive potential units during the period. Dilutive potential units consist of common units issuable under the terms of the Partnership’s Long-Term Incentive Plan (see Note 8).

7

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

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

Net Income Per Unit — (Continued)

        The following table presents a reconciliation of the components used in the computation of net income per unit-basic and net income per unit-diluted for the periods indicated:

	Three Months Ended June, 30				Six Months Ended June 30,
	2004		2003		2004		2003
Net income - limited partners	$	2,359,200	$	2,479,400	$	4,480,700	$	4,259,200
Basic average limited partner units outstanding		5,038,751		3,934,493		4,696,718		3,600,196
Dilutive effect of phantom units (see Note 5)		16,511		--		8,721		--
Dilutive average limited partner units		5,055,262		3,934,493		4,705,439		3,600,196

Comprehensive Income

        Comprehensive income includes net income and all other changes in the equity of a business during a period from non-owner sources. These changes, other than net income, are referred to as “other comprehensive income.” The Partnership has no elements of comprehensive income other than net income to report.

Cash Flow Statements

        For purposes of the statements of cash flows, all highly liquid debt instruments purchased with a maturity of three months or less are considered to be cash equivalents.

Segment Information

        The Partnership has one business segment, the transportation segment, which derives its revenues primarily from the transportation of natural gas that it receives from producers. Transportation revenues are, for the most part, based on contractual arrangements with Atlas America, Inc. and its affiliates.

Goodwill

        Goodwill is evaluated for impairment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142. As of January 1, 2002, the date of adoption, the Partnership had unamortized goodwill in the amount of $2.3 million. The Partnership evaluates its goodwill at least annually and will reflect the impairment of goodwill, if any, in operating income in the income statement in the period in which the impairment is indicated.

8

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

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

Concentration of Credit Risk

        Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash. The Partnership places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions. At June 30, 2004, the Partnership and its subsidiaries had $37.4 million in deposits at two financial institutions, of which $37.1 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

NOTE 3 – DISTRIBUTION DECLARED

        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 deemed appropriate to provide for future operating costs, potential acquisitions and future distributions.

        On June 15, 2004, the Partnership declared a cash distribution of $.63 per unit on its outstanding common units and subordinated units. The distribution represents the available cash flow for the three months ended June 30, 2004. The $3,654,300 distribution, which includes a distribution of $438,100 to the general partner, will be paid on August 6, 2004 to unitholders of record on June 30, 2004.

        Available cash is initially distributed 98% to limited partners and 2% to the general partner. These distribution percentages are modified to provide for incentive distributions to be paid to the general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Incentive distributions are generally defined as all cash distributions paid to the general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner’s incentive distributions for the distributions declared for the three and six months ended June 30, 2004 were $364,800 and $676,200 and for the three and six months ended June 30, 2003 were $155,300 and $250,800, respectively.

NOTE 4 – CREDIT FACILITY

        In September 2003, the Partnership amended and increased its credit facility from $15.0 million to $20.0 million. Borrowings under the facility are secured by a lien on and security interest in all the property of the Partnership and its subsidiaries, including pledges by the Partnership of the issued and outstanding equity interests in its subsidiaries. Up to $3.0 million of the facility may be used for standby letters of credit. No letters of credit have been issued under the facility. At June 30, 2004 and December 31, 2003, there were no borrowings under this credit facility.

9

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

NOTE 4 – CREDIT FACILITY — (Continued)

        The credit facility requires the Partnership to maintain specified net worth and specified ratios of current assets to current liabilities and debt to earnings before income tax, depreciation and amortization (“EBITDA”), and requires it to maintain a specified interest coverage ratio. At June 30, 2004, the Partnership was in compliance with all of the financial covenants.

         In July 2004, the Partnership replaced this credit facility with a $135.0 million facility (see Note 9).

NOTE 5 – SPECIAL MEETING OF UNITHOLDERS

        On February 11, 2004, at a special meeting of unitholders, the following were approved:

o The issuance of up to 2.0 million common units in connection with the Partnership’s proposed acquisition of Alaska Pipeline Company, of which 750,000 common units were issued in April 2004 (see Note 7).

o The Atlas Pipeline Partners, L.P. Long-Term Incentive Plan (the "Plan") in which officers, employees and non-employee managing board members of Atlas Pipeline Partners GP, LLC (the “General Partner”) and employees of the General Partner’s affiliates, consultants and joint venture partners who perform services for the Partnership are eligible to participate. The Plan is administered by a committee appointed by the General Partner’s managing board (the “Committee”), which sets the terms of awards under the Plan. The Committee may make awards of either phantom units or options for an aggregate of 435,000 common units, provided that the maximum number of phantom units that may be awarded in total to non-employee managing board members is 10,000. A phantom unit entitles the grantee to receive a common unit upon the 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 the right, known as a DER, 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. An option entitles the grantee to purchase the Partnership's common units at an exercise price determined by the Committee, which may be less than, equal to or more than the fair market value of the Partnership’s common units on the date of the grant. The Committee also has discretion to determine how the exercise price may be paid. Except for phantom units awarded to non-employee managing board members of the General Partner, the managing board will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managing board members will vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the Plan (see Note 8).

         After the special meeting of unitholders was adjourned and was reconvened on March 9, 2004, the unitholders approved amendments to the Partnership Agreement that remove the limitations on the Partnership’s ability to issue common units and incur debt.

10

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

NOTE 6 — RELATED PARTY TRANSACTIONS

         In June 2004, the Partnership entered into a definitive agreement to acquire Spectrum Field Services, Inc. (“Spectrum”), whose principal assets include 1,900 miles of natural gas pipelines and a natural gas processing facility in Velma, Oklahoma (see Note 9). In connection with the acquisition of Spectrum, the Partnership entered into commitment agreements with Resource America, Inc. ("Resource America") and Atlas America, Inc. ("Atlas America") for the purchase of up to $25.0 million of preferred units in Atlas Pipeline Operating Partnership, L.P., the Partnership’s subsidiary upon the closing of the acquisition. In consideration for their commitments, upon the closing of the Spectrum acquisition on July 16, 2004 and the purchase by each of $10.0 million in preferred units, the Partnership paid Resource America, Inc. and Atlas America, Inc. commitment fees of $750,000 and $500,000, respectively.

NOTE 7 – PUBLIC OFFERING

        In April 2004, the Partnership completed a public offering of 750,000 common units. The net proceeds after underwriting discounts, commissions and costs were approximately $25.2 million. Following this offering, common units represented 67.9% of the limited partnership interest in the Partnership. The General Partner simultaneously contributed $512,700 in cash to the Partnership in order to maintain its 2% general partner interest in the Partnership. As a result of SEMCO Energy Inc.’s (“SEMCO”) purported termination of the Partnership’s acquisition of Alaska Pipeline Company on July 1, 2004, the Partnership used these proceeds for the acquisition of Spectrum in July 2004.

NOTE 8 – LONG-TERM INCENTIVE PLAN

        The Partnership has a Long-Term Incentive Plan for officers as discussed in Note 5. During the six months ended June 30, 2004, 61,098 phantom units were granted. Grants for 846 units were forfeited during the three months ended June 30, 2004, leaving 60,252 phantom units outstanding as of June 30, 2004. The Partnership recognized $69,800 and $72,300 in compensation expense related to these grants and their associated distributions in the three months and six months ended June 30, 2004. The fair market value associated with these grants was $2.2 million which will be amortized into expense over the vesting period of the units.

NOTE 9 –SUBSEQUENT EVENTS

Acquisition

         On July 16, 2004, the Partnership acquired Spectrum, for approximately $145.3 million, including the payment of anticipated taxes due as a result of the transaction.

11

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

NOTE 9 –SUBSEQUENT EVENTS - (Continued)

Acquisition - (Continued)

        The Partnership financed the Spectrum acquisition, including approximately $2.1 million of transaction costs, as follows:

o borrowing $100.0 million under the term loan portion and $2.2 million under the revolving credit portion of its $135.0 million senior secured term loan and revolving credit facility administered by Wachovia Bank, National Association;

o using the $20.0 million of proceeds received from the sale to Resource America and Atlas America of preferred units in Atlas Pipeline Operating Partnership; and

o using $25.2 million of net proceeds from Atlas Pipeline Partners’ April 2004 common unit offering.

Credit Facility

         On July 16, 2004 the Partnership entered into a new $135.0 million credit facility which replaces its existing $20.0 million facility. The loan arrangement, for which Wachovia Bank, National Association will serve as administrative agent, includes eleven additional lenders. The facility is comprised of a five-year $100.0 million term loan and a four-year $35.0 million revolving line of credit which can be increased by an additional $40.0 million under certain circumstances.

Public Offering of Units

        On July 20, 2004, the Partnership closed an offering of 2,100,000 of its common units through underwriters led by Lehman Brothers and including A.G. Edwards & Sons, Inc., Friedman Billings Ramsey, KeyBanc Capital Markets and Sanders Morris Harris, which was priced at $34.76 per common unit. After underwriting discounts and commissions, the Partnership received net proceeds of $69.5 million.

         The Partnership has granted the underwriters an over-allotment option for an additional 315,000 common units exercisable within thirty days. The over-allotment option, if fully exercised, would generate an additional $10.4 million in net proceeds for the Partnership.

        The Partnership used a portion of the net proceeds of this offering to repay $40.0 million of the borrowings under its new credit facility and to repurchase the preferred units from Resource America and Atlas America for $20.4 million. The balance of approximately $8.9 million will be used for working capital.

12

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
JUNE 30, 2004
(Unaudited)

NOTE 9 –SUBSEQUENT EVENTS -(Continued)

Alaska Pipeline Company Acquisition

         In September 2003, the Partnership entered into an agreement with SEMCO to purchase all of the stock of Alaska Pipeline Company. In order to complete the acquisition, the Partnership needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004 it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent the Partnership a notice purporting to terminate the transaction. The Partnership believes SEMCO caused the delay in closing the transaction and breached its obligations under the acquisition agreement. The Partnership intends to vigorously pursue its remedies under the acquisition agreement. In connection with the acquisition, the Partnership incurred $2.2 million of costs, which are included in other assets on the Partnership’s balance sheet.

13

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 2003 and in our prospectus supplement dated July 14, 2004. These risks and uncertainties could cause actual results to differ materially. 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 operation. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

General

        Our principal business objective is to generate income for distribution to our unitholders from the transportation of natural gas through our gathering systems. Our gathering systems gather natural gas from wells in eastern Ohio, western New York, and western Pennsylvania and transport the natural gas primarily to public utility pipelines. To a lesser extent, the gathering systems transport natural gas to end-users.

         In April 2004, we completed a public offering of 750,000 common units of limited partner interest. The net proceeds after underwriting discounts, commissions and estimated costs were approximately $25.2 million.

         On July 16, 2004, we acquired Spectrum Field Services, Inc., which we refer to as Spectrum, for approximately $145.3 million, including the payment of anticipated taxes due as a result of the transaction. This acquisition significantly increases our size and diversifies the natural gas supply basins in which we operate and the natural gas midstream services we provide to our customers. We expect the Spectrum acquisition to be accretive to our cash distributions per common unit.

        We financed the Spectrum acquisition, including approximately $2.1 million of transaction costs, as follows:

o borrowing $100.0 million under the term loan portion and $2.2 million under the revolving credit portion of our $135.0 million senior secured term loan and revolving credit facility administered by Wachovia Bank, National Association;

o using the $20.0 million of net proceeds received from the sale to Resource America and Atlas America, Inc. of preferred units in Atlas Pipeline Operating Partnership; and

o using $25.2 million of the net proceeds from Atlas Pipeline Partners’ April 2004 common unit offering.

14

         On July 20, 2004 we closed an offering of 2,100,000 of our common units through underwriters led by Lehman Brothers and including A.G. Edwards & Sons, Inc., Friedman Billings Ramsey, KeyBanc Capital Markets and Sanders Morris Harris, which was priced at $34.76 per common unit. After underwriting discounts and commissions we received net proceeds of $69.5 million. We have granted the underwriters an over-allotment option for an additional 315,000 common units exercisable within thirty days. The over-allotment option, if fully exercised, would generate an additional $10.4 million in net proceeds for us.

         We used a portion of the net proceeds of this offering to repay $40.0 million of the borrowings under our new credit facility and to repurchase the preferred units from Resource America and Atlas America.

         The acquisition of Spectrum will significantly change our financial position and results of operations. With proceeds from our July 2004 public offering we reduced our outstanding debt to $60.0 million, leaving an available borrowing capacity $73.0 million. We intend to finance our growth with a combination of long-term debt and equity to maintain our financial flexibility to fund future opportunities.

         In September 2003, we entered into an agreement with SEMCO Energy, Inc. (“SEMCO”) to purchase all of the stock of Alaska Pipeline Company. In order to complete the acquisition, we needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004 it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent us a notice purporting to terminate the transaction. While the acquisition agreement was terminable by either us or SEMCO beginning on June 16, 2004, we believe SEMCO caused the delay in closing the transaction and breached its obligations under the acquisition agreement. We intend to vigorously pursue its remedies under the acquisition agreement. We incurred $2.2 million of costs in connection with the acquisition which are included in other assets on our balance sheet.

Results of Operations

         In the three and six months ended June 30, 2004 and 2003, our principal revenues came from the operation of our pipeline gathering systems which transport and compress natural gas. Two variables which affect our transportation revenues are:

o the volumes of natural gas transported 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 that natural gas; and

o the transportation fees paid to us which, in turn, depend upon the price of the natural gas we transport, which itself is a function of the relevant supply and demand in the mid-Atlantic and north-eastern areas of the United States.

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         We set forth the average volumes we transported, our average transportation rates per mcf and revenues received by us for the periods indicated in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Average daily throughput volumes in mcf		52,442		54,734		51,940		52,402
Average transportation rate per mcf	$	.94	$	.87	$	.92	$	.81
Total transporation and compression revenues	$	4,468,400	$	4,325,000	$	8,678,700	$	7,653,400

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003

        Revenues.    Our transportation and compression revenues increased to $4,468,400 in the three months ended June 30, 2004 from $4,325,000 in the three months ended June 30, 2003. The increase of $143,400 (3%) resulted from an increase in the average transportation fee paid to us ($338,600) partially offset by a decrease in the volumes of natural gas we transported ($195,200).

        Our average daily throughput volumes were 52,442 mcf in the three months ended June 30, 2004 as compared to 54,734 mcf in the three months ended June 30, 2003, a decrease of 2,292 mcf (4%). During the three months and twelve months ended June 30, 2004, we added 115 and 309 new wells to our system, respectively. Although production volumes have been added from new wells, overall production for the three months ended June 30, 2004 has declined due to the following factors. Of the above well connections, Atlas America drilled and connected 42 wells during the twelve months ended June 30, 2004 in an area of operation that produces predominately oil. The decrease in the three months ended June 30, 2004 as compared to the prior year period includes a decrease resulting from normal recurring adjustments of estimated accruals. In addition, in February 2004, a third party producer that had been connected to our Fayette County, Pennsylvania system constructed its own gathering system, resulting in a loss in throughput volumes.

         Our average transportation rate was $.94 per mcf in the three months ended June 30, 2004 as compared to $.87 per mcf in the three months ended June 30, 2003, an increase of $.07 per mcf (8%). In the second quarter of 2004, natural gas prices were higher than those of the prior year period. Since our transportation rates are generally at fixed percentages of the sales price of the natural gas we transport, the higher prices resulted in an increase in our average transportation rate.

        Costs andExpenses.    Our transportation and compression expenses decreased to $537,900 in the three months ended June 30, 2004 as compared to $615,800 in the three months ended June 30, 2003, a decrease of $77,900 (13%). Our average cost per mcf for transportation and compression was $.11 in the three months ended June 30, 2004 as compared to $.12 in the three months ended June 30, 2003. This decrease primarily resulted from a decrease in compressor lease payments as a result of our decision to purchase the majority of the compressors we had previously leased.

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        Our general and administrative expenses increased to $582,500 in the three months ended June 30, 2004 as compared to $546,600 in the three months ended June 30, 2003, an increase of $35,900 (7%). This increase is the result of the expensing of phantom units issued under the Atlas Pipeline Partners, L.P. Long-Term Incentive Plan established in February 2004 for officers and members of the managing board of our general partner and employees of our general partner’s affiliates who perform services for us, and the related distributions payable on those units at June 30, 2004. We incurred $69,800 in expense in the three months ended June 30, 2004 associated with phantom units issued. In accordance with accounting principles generally accepted in the United States of America, the fair value of phantom units is amortized over the vesting period of these units and the related distribution payable is recognized in expense as declared.

         Our depreciation and amortization expense increased to $592,000 in the three months ended June 30, 2004 as compared to $421,000 in the three months ended June 30, 2003, an increase of $171,000 (41%). This increase resulted from our increased asset base associated with pipeline extensions and the upgrade of compressors and compressor stations. We anticipate that our depreciation will increase in the remainder of 2004 as a result of our pipeline extensions and compressor upgrades.

        Our interest expense decreased to $63,800 in the three months ended June 30, 2004 as compared to $79,000 in the three months ended June 30, 2003. This decrease of $15,200 (19%) resulted from decreased borrowings in the three months ended June 30, 2004 as compared to the same period in 2003. In June 2003, we repaid all of our existing debt with proceeds from a public offering we completed in May 2003. Our interest expense in the three months ended June 30, 2004 consisted of commitment fees on amounts not drawn on our credit facility and amortization of our debt issuance costs.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

        Revenues.    Our transportation and compression revenues increased to $8,678,700 in the six months ended June 30, 2004 from $7,653,400 in the six months ended June 30, 2003. The increase of $1,025,300 (13%) resulted from an increase in the average transportation fee paid to us ($1,054,400) partially offset by a decrease in the volumes of natural gas we transported ($29,100).

         Our average daily throughput volumes were 51,940 mcf in the six months ended June 30, 2004 as compared to 52,402 mcf in the six months ended June 30, 2003, a decrease of 462 mcf (1%). During the six months and twelve months ended June 30, 2004, we added 190 and 309 new wells to our system, respectively. Although production volumes have been added from new wells, overall production for the six months ended June 30, 2004 has declined due to the following factors. Of the above well connections, Atlas America drilled and connected 42 wells during the twelve months ended June 30, 2004 in an area of operation that produces predominately oil. The decrease in the six months ended June 30, 2004 as compared to the prior year period includes a decrease resulting from normal recurring adjustments of estimated accruals. In addition, in February 2004, a third party producer that had been connected to our Fayette County, Pennsylvania system constructed it own gathering system, resulting in a loss in throughput volumes.

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         Our average transportation rate was $.92 per mcf in the six months ended June 30, 2004 as compared to $.81 per mcf in the six months ended June 30, 2003, an increase of $.11 per mcf (14%). During the six months ended June 30, 2004, natural gas prices increased over the prior year period. Since our transportation rates are generally at fixed percentages of the sales price of the natural gas we transport, the higher prices resulted in an increase in our average transportation rate.

         Costs and Expenses.     Our transportation and compression expenses decreased to $1,144,700 in the six months ended June 30, 2004 as compared to $1,224,000 in the six months ended June 30, 2003, a decrease of $79,300 (6%). Our average cost per mcf for transportation and compression was $.12 in the six months ended June 30, 2004 as compared to $.13 in the six months ended June 30, 2003. This decrease primarily resulted from a decrease in compressor lease payments as a result of our decision to purchase the majority of the compressors we had previously leased.

        Our general and administrative expenses increased to $1,163,600 in the six months ended June 30, 2004 as compared to $865,700 in the six months ended June 30, 2003, an increase of $297,900 (34%). This increase primarily resulted from an increase in our cost associated with the preparation and filing of two tax returns for 2003. This is a result of our general partner’s percentage interest in us being reduced below 50% as a result of our offering of common units in May 2003, requiring a change in our tax year-end from September 30^th to December 31^st which necessitated the filing of an additional short year tax return. This expense is non-reoccurring. In addition, under our Long-Term Incentive Plan we recognized approximately $72,300 in expense related to the expensing of phantom units issued and their related dividends.

        Our depreciation and amortization expense increased to $1,110,700 in the six months ended June 30, 2004 as compared to $827,700 in the six months ended June 30, 2003, an increase of $283,000 (34%). This increase resulted from our increased asset base associated with pipeline extensions and the upgrade of compressors and compressor stations. We anticipate that our depreciation will increase in the remainder of 2004 as a result of our pipeline extensions and compressor upgrades.

         Our interest expense decreased to $126,500 in the six months ended June 30, 2004 as compared to $162,500 in the six months ended June 30, 2003. This decrease of $36,000 (22%) resulted from decreased borrowings in the six months ended June 30, 2004 as compared to the same period in 2003. In June 2003, we repaid all of our existing debt with proceeds from a public offering we completed in May 2003. Our interest expense in the six months ended June 30, 2004 consisted of commitment fees on amounts not drawn on our credit facility and amortization of our debt issuance costs.

Liquidity and Capital Resources

        Our primary cash requirements, in addition to normal operating expenses, are for debt service, maintenance capital expenditures, expansion capital expenditures and quarterly distributions to our unitholders and general partner. In addition to cash generated from operations, we have the ability to meet our cash requirements, (other than distributions to our unitholders and general partner) through borrowings under our credit facility. In general, we expect to fund:

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

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

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o debt principal payments through additional borrowings as they become due or by the issuance of additional common units.

        The following table summarizes our financial condition and liquidity at the dates indicated:

	June 30, 2004		December 31, 2003
Current ratio		4.99x		2.88x
Working capital	$	30,077,500	$	9,890,000

        We had $37,380,400 in cash and cash equivalents at June 30, 2004, as compared to $15,078,100 at December 31, 2003. The increase in cash and our current ratio is primarily the result of our April 2004 public offering.

        Net cash provided by operations of $7,683,600 in the six months ended June 30, 2004 increased $2,652,200 from $5,031,400 in the six months ended June 30, 2003. The increase in cash flows provided by operations in 2004 was principally due an increase in net income as a result of higher transportation rates. In addition, changes in operating assets and liabilities increased cash flow by $1,415,500 as a result of advances from Atlas America in connection with expenses associated with the pending acquisition of Spectrum.

        Net cash used in investing activities was $4,524,900 for the six months ended June 30, 2004, an increase of $2,370,500 from $2,154,400 in the six months ended June 30, 2003. The primary reason for this increase was expenditures related to transaction costs associated with our acquisition of Spectrum and Alaska Pipeline Company.

        Net cash provided by financing activities was $19,143,600 for the six months ended June 30, 2004, an increase of $3,993,000 from $15,150,600 in the six months ended June 30, 2003. The primary reason for the increase was the net repayment of $6.5 million on our revolving credit facility in the prior year period, partially offset by an increase in distributions to partners in the current year period as a result of an increase in net income and common units outstanding. In the six months ended June 30, 2004 and 2003, we received proceeds from our public offerings in the amount of $25,187,800 and $25,255,300, respectively.

Capital Expenditures

        Our property and equipment was approximately 41% and 60% of our total consolidated assets at June 30, 2004 and December 31, 2003, respectively. Capital expenditures were $1,336,700 and $2,521,300 in the three months and six months ended June 30, 2004 and $962,700 and $2,154,400 in the three months and six months ended June 30, 2003, respectively. These capital expenditures principally consisted of costs relating to expansion of our existing gathering systems to accommodate new wells drilled in our service area and compressor upgrades. During the twelve months ended June 30, 2004, we connected 307 wells to our gathering system. As of June 30, 2004, we were committed to expend approximately $2.4 million for pipeline extensions and compressor upgrades. We also anticipate that capital expenditures will increase in the remainder of 2004 as a result of an increase in the number of wells estimated to be connected to our gathering systems.

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Long-Term Debt

        On July 16, 2004 we obtained a $135.0 million credit facility administered by Wachovia Bank that replaced our existing $20.0 million facility. The facility includes a $35.0 million four-year revolving line of credit which can be increased by an additional $40.0 million under certain circumstances and a $100.0 million five-year term loan. Up to $5.0 million of the facility may be used for standby letters of credit. 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 bears interest at one of two rates, elected at our option:

o the base rate plus the applicable margin; or

o the adjusted London Interbank Offered Rate, or LIBOR, plus the applicable margin.

         The base rate for any day equals the higher of the federal funds rate plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Board of Governors of the Federal Reserve System for determining the reserve requirement for euro currency funding. The applicable margin for the revolving line of credit is as follows:

o where our leverage ratio, that is, the ratio of our debt to our earnings before interest, taxes, depreciation and amortization, or EBITDA, is less than or equal to 2.5, the applicable margin is 1.00% for base rate loans and 1.75% for LIBOR loans;

o where our leverage ratio is greater than 2.5 but less than or equal to 3.0, the applicable margin is 1.25% for base rate loans and 2.00% for LIBOR loans;

o where our leverage ratio is greater than 3.0 but less than or equal to 3.5, the applicable margin is 1.75% for base rate loans and 2.50% for LIBOR loans; and

o where our leverage ratio is greater than 3.5, the applicable margin is 2.25% for base rate loans and 3.00% for LIBOR loans.

        The applicable margin for the term loan is .75% higher for both base rate loans and LIBOR loans.

         The credit facility requires us to maintain a ratio of funded debt to EBITDA of not more than 4.25 to 1.0, reducing to 4.0 to 1.0 on December 31, 2004 and 3.5 to 1.0 on June 30, 2005 and an interest coverage ratio of not less than 3.0 to 1.0. In addition, we must prepay the term loan with the net proceeds of any asset sales or issuances of debt. With respect to any issuances of equity, we must repay the term loan from the proceeds of such issuances to the extent our ratio of funded debt to EBITDA exceeds 3.5 to 1.0. On July 20, 2004, we prepaid $40.0 million of the $100.0 million we had borrowed under the term loan in connection with our acquisition of Spectrum from the proceeds of our common unit offering. We must pay down $1.25 million in principal on the outstanding balance of the term loan quarterly, but any prepayments of principal that we make will be credited pro rata against this repayment obligation.

         The credit agreement contains covenants customary for loans of this size, including restrictions on incurring additional debt and making material acquisitions, other than the Spectrum acquisition, and a prohibition on paying distributions to our unitholders if an event of default occurs. The events which constitute an event of default are also customary for loans of this size, including payment defaults, breaches of our representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control of our general partner.

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Contractual Obligations and Commercial Commitments

        The following table summarizes our contractual obligations and commercial commitments at June 30, 2004:

			Payments Due By Period
Contractual cash obligations	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Long-term debt	$	--	$	--	$	--	$	--	$	--
Capital lease obligations		--		--		--		--		--
Operating leases		285,000		171,000		114,000		--		--
Unconditional purchase obligations		--		--		--		--		--
Other long-term obligations		--		--		--		--		--
Total contractual cash obligations	$	285,000	$	171,000	$	114,000	$	--	$	--

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

			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total			Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Standby letters of credit	$	--		$	--	$	--	$	--	$	--
Guarantees		--			--		--		--		--
Standby replacement commitments		--			--		--		--		--
Other commercial commitments		2,424,100			2,424,100		--		--		--
Total commercial commitments	$	2,424,100		$	2,424,100	$	--	$	--	$	--

        Other commercial commitments relate to commitments to purchase our compressors rather than lease them 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. We summarize our significant accounting policies in Note 2 to our Consolidated Financial Statements in our annual report on Form 10-K for 2003. The critical accounting policies and estimates that we have identified are discussed as follows.

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Revenues and Costs and Expenses

        We routinely make accruals for both revenues and costs and expenses due to the timing of receiving information from third parties and reconciling our records with those of third parties. We estimate the accrual amounts using available market data and valuation methodologies. While we believe our estimates are reasonable, actual amounts may vary from estimated amounts.

Depreciation and Amortization

        We calculate our depreciation based on the estimated useful lives and salvage values of our assets. However, factors such as usage, equipment failure, competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.

Impairment of Assets

        In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, we determine if our long-lived assets are impaired by comparing the carrying amount of an asset or group of assets with the estimated future cash flows associated with such asset or group of assets. If the carrying amount is greater than the estimated future cash flows, an impairment loss is recognized in the amount of the excess, if any, of such carrying amount over the fair value of the asset or group of assets.

Goodwill

        At June 30, 2004, we had $2.3 million of goodwill, all of which relates to our acquisition of pipeline assets. We test our goodwill for impairment each year. Our test during 2003 resulted in no impairment. We will continue to evaluate our goodwill at least annually and will reflect the impairment of goodwill, if any, in operating income in the income statement in the period in which the impairment is indicated. Our next annual evaluation of goodwill for impairment will be as of December 31, 2004.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        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 do not engage in any interest rate, foreign currency exchange rate or commodity price-hedging transactions, and as a result, we do not have exposure to derivatives risk.

        Our major market risk exposure is in the pricing applicable to natural gas sales which in turn affect our transportation rates. Realized pricing is primarily driven by spot market prices for natural gas. Pricing for natural gas production has been volatile and unpredictable for several years.

        Market risk inherent in our debt is the potential change arising from increases or decreases in interest rates. Changes in variable rate debt usually do not affect the fair value of the debt instrument, but may affect our future earnings and cash flows.

        At June 30, 2004 we had a $20.0 million revolving credit facility to fund the expansion of our existing gathering systems and the acquisition of other gas gathering systems. We had no amounts drawn on this facility.

         In July 2004, we replaced the above loan with a $135.0 million senior secured term loan and revolving credit facility of which a portion was used to finance the Spectrum acquisition.

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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 general partner, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our general partner and its 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 general partner’s management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

         Under the supervision of the Chief Executive Officer and Chief Financial Officer of our general partner, and with the participation of the 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, the Chief Executive Officer and Chief Financial Officer of our general partner, concluded that our disclosure controls and procedures are effective.

         There have been no significant changes in our internal controls over financial reporting that has partially affected, or is reasonably likely to materially affect, our internal control over financial reporting during our most recent fiscal quarter.

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PART II. OTHER INFORMATION

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

        No matter was submitted to a vote of security holders during the quarter ended June 30, 2004.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K OPEN

          (a)   Exhibits:

Exhibit No.	Description
2.1	Securities Purchase Agreement, dated June 10, 2004, among Atlas Pipeline Operating Partnership, L.P. and Spectrum Field Services, Inc., et al. (1)
3.1	Second Amended and Restated Agreement of Limited Partnership (2)
3.2	Certificate of Limited Partnership of Atlas Pipeline Partners, L.P. (3)
31.1	Rule 13a-14(a)/15d-14(a) Certifications
31.2	Rule 13a-14(a)/15d-14(a) Certifications
32.1	Section 1350 Certifications
32.2	Section 1350 Certifications

⁽¹⁾ Previously filed as an exhibit to the Partnership’s current report on Form 8-K filed July 13, 2004 and incorporated herein by reference.

⁽²⁾ Previously filed as an exhibit to the Partnership’s registration statement on Form S-3, Registration No. 333-113523 and incorporated herein by reference.

⁽³⁾ Previously filed as an exhibit to the Partnership’s registration statement on Form S-1, Registration No. 333-85193 and incorporated herein by reference.

          (b)   Reports on Form 8-K:

        During the quarter ended June 30, 2004, the Partnership filed three current reports on Form 8-K as follows:

o We filed a Form 8-K on April 8, 2004 regarding our public offering of up to 862,500 common units pursuant to a registration statement.

o We filed a Form 8-K on June 9, 2004 regarding SEMCO Energy, Inc.‘s petition with the Regulatory Commission of Alaska seeking classification of their order issued on April 20, 2004 in connection with approvals sought by us and SEMCO Energy, Inc. in connection with the proposed sale of Alaska Pipeline Company to us.

o We filed a Form 8-K on June 15, 2004 regarding our belief that SEMCO Energy, Inc. had breached its obligations under the Purchase and Sale Agreement with respect to the sale of Alaska Pipeline Company to us.

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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

Dated: August 9, 2004	By:     /s/ Freddie M. Kotek                       Freddie M. Kotek            Chief Financial Officer of the General Partner
Dated: August 9, 2004	By:    /s/ Nancy J. McGurk                      Nancy J. McGurk           Chief Accounting Officer of the General Partner

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