Atlas Pipeline Partners 10-Q 2005 Q1 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 March 31, 2005

OR

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

For the transition period from ________to ________

Commission file number: 1-4998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

Yes x No o

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

Yes x Noo

 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004 (Unaudited)	3
	Consolidated Statements of Income for the Three Months Ended March 31, 2005 and March 31, 2004 (Unaudited)	4
	Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2005 (Unaudited)	5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and March 31, 2004 (Unaudited)	6
	Notes to Consolidated Financial Statements - March 31, 2005 (Unaudited)	7- 19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20 - 28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28- 31
Item 4.	Controls and Procedures	31
PART II.OTHER INFORMATION
Item 2.	Changes in Securities and Use of Proceeds	32
Item 4.	Submission of Matters to a Vote of Security Holders	32
Item 6.	Exhibits	32
SIGNATURES		33

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(Unaudited)

	March 31,			December 31,
ASSETS	2005			2004
Current assets:
Cash and cash equivalents	$	9,695		$	18,214
Accounts receivable−affiliates		−			1,496
Accounts receivable		16,566			13,769
Prepaid expenses		1,155			1,056
Total current assets		27,416			34,535
Property, plant and equipment, net		179,847			175,259
Goodwill(net of accumulated amortization of $285)		2,305			2,305
Other assets		6,319			4,686
	$	215,887		$	216,785
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	2,303		$	2,303
Accrued liabilities		2,677			2,619
Hedge liability		8,673			1,959
Accrued producer liabilities		12,456			10,996
Accounts payable		1,395			2,341
Accounts payable- affiliates		963			−
Distribution payable		6,904			6,467
Total current liabilities		35,371			26,685
Other long-term liabilities		3,160			1,247
Long-term debt, less current portion		51,570			52,149
Commitments and contingencies		−			−
Partners’ capital:
Common unitholders; 7,204,790 and 5,563,659 units outstanding		133,192			135,759
Subordinated unitholder, 0 and 1,641,026 units outstanding		−			2
General partner		2,181			2,261
Accumulated other comprehensive loss		(9,587	)		(1,318	)
Total partners’ capital		125,786			136,704
	$	215,887		$	216,785

See accompanying notes to consolidated financial statements

3

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE MONTHS ENDED MARCH 31, 2005 AND 2004

(in thousands, except per unit data)

(Unaudited)

	2005		2004
Revenues:
Natural gas and liquids	$	42,334	$	-
Transportation and compression - affiliates		4,847		4,193
Transportation and compression - third party		15		17
Interest income and other		81		36
Total revenues and other income		47,277		4,246
Costs and expenses:
Natural gas and liquids		35,459		−
Plant operating		1,204		−
Transportation and compression		676		607
General and administrative		1,975		468
Compensation reimbursement - affiliates		513		113
Terminated acquisition costs		136		−
Depreciation and amortization		1,929		518
Interest		1,135		63
Total costs and expenses	$	43,027	$	1,769
Net income	$	4,250	$	2,477
Net income - limited partners	$	2,830	$	2,122
Net income- general partner	$	1,420	$	355
Basic and diluted net income per limited partner unit	$	.39	$	.49
Weighted average limited partner units outstanding		7,205		4,355

See accompanying notes to consolidated financial statements

4

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED MARCH 31, 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		105		-			5			-			-			-			5
Distribution payable		-		-			(5,404	)		-			(1,500	)		-			(6,904	)
Other comprehensive loss		-		-			-			-			-			(8,269	)		(8,269	)
Net income		-		-			2,830			−			1,420			-			4,250
Balance at March 31, 2005		7,204,790		−		$	133,192		$	−		$	2,181		$	(9,587	)	$	125,786

See accompanying notes to consolidated financial statements

5

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2005 AND 2004

(in thousands)

(Unaudited)

	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,250		$	2,477
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		1,929			518
Non-cash gain on derivative value		(75	)		-
Non-cash compensation on long-term incentive plan		449			-
Loss on disposal of fixed assets		3			-
Amortization of deferred finance costs		182			37
Change in operating assets and liabilities:
Increase in accounts receivable and prepaid expenses		(2,746	)		(147	)
Increase (decrease) in accounts payable and accrued liabilities		459			(261	)
Increase in accounts payable/(decrease) in accounts receivable - affiliates		2,459			(1,304	)
Net cash provided by operating activities		6,910			1,320
CASH FLOWS FROM INVESTING ACTIVITIES:
Spectrum purchase price adjustment		(526	)		-
Capital expenditures		(6,077	)		(1,185	)
Increase in other assets		(475	)		(120	)
Proceeds from sale of fixed assets		49			-
Net cash used in investing activities		(7,029	)		(1,305	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments on long-term debt		(579	)		-
Distributions paid to partners		(6,467	)		(3,073	)
Increase in other assets		(1,354	)		(41	)
Net cash used in financing activities		(8,400	)		(3,114	)
Decrease in cash and cash equivalents		(8,519	)		(3,099	)
Cash and cash equivalents, beginning of period		18,214			15,078
Cash and cash equivalents, end of period	$	9,695		$	11,979

See accompanying notes to consolidated financial statements

6

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2005

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION

The consolidated financial statements of the Partnership and its wholly-owned subsidiaries as of March 31, 2005 and for the three month periods ended March 31, 2005 and 2004 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, 2004. The results of operations for the three month period ended March 31, 2005 may not necessarily be indicative of the results of operations for the full year ending December 31, 2005.

Certain reclassifications have been made to the consolidated financial statements as of and for the three month period ended March 31, 2004 to conform to the presentation for the three month period ended March 31, 2005.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further 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, 2004 filed with the securities and Exchange Commission.

Net Income Per Unit

Net income per limited partner unit is based on the weighted average number of common and subordinated units outstanding during the period. Basic net income per limited partner unit is computed by dividing net income, after deducting the general partner’s 2% and incentive distributions, by the weighted average number of outstanding common units and subordinated units. Diluted net income per limited partner unit is computed by dividing net income attributable to limited partners by the sum of the weighted average number of common and subordinated units outstanding and the weighted average number of phantom units during the period. Phantom units consist of common units issuable under the terms of the Partnership’s Long-Term Incentive Plan.

Phantom units issued and outstanding through March 31, 2005 totaling 125,201, were not included in the computation of diluted net income per limited partner unit for the three months ended March 31, 2005 and 2004 as their effect would have been anti-dilutive.

On January 1, 2005, 1,641,026 subordinated units held by the General Partner converted to common units in accordance with the terms of the partnership agreement.

7

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

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

Receivables

In evaluating its allowance for possible losses, 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 March 31, 2005 and December 31, 2004, the Partnership’s credit evaluation indicated that it has no need for an allowance for possible losses.

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 includes only changes in the fair value of unrealized hedging contracts.

	Three Months Ended
	March 31,
	2005			2004
	(in thousands)
Net income	$	4,250		$	2,477
Other comprehensive loss:
Unrealized loss on hedging contracts		(8,938	)		-
Add: reclassification adjustment for losses realizedin net income		669			-
		(8,269	)		-
Comprehensive (loss) income	$	(4,019	)	$	2,477

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. The following table sets forth supplemental disclosures of cash flow information (in thousands):

	Three Months Ended
	March 31,
	2005		2004
Cash paid during the period for:
Interest	$	287	$	51
Non-cash activities include the following:
Issuance of common units under Long-TermIncentive Plan	$	5	$	-

8

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

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

Segment Information

The Partnership has two business segments: natural gas gathering and transmission located in the Appalachian Basin area (“Appalachia”) and gathering and processing located in the Mid-Continent-Velma area (“Mid-Continent-Velma”). Appalachian revenues are, for the most part, based on contractual arrangements with Atlas America, Inc (“Atlas”) and its affiliates. Mid-Continent-Velma revenues are, for the most part, derived from the sale of residue gas and natural gas liquids (“NGLs”) to purchasers at the tailgate of the processing plant (see Note 14).

Revenue Recognition

Because there are timing differences between the delivery of natural gas, NGLs and oil and the Partnership's receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based upon volumectric data from the Partnership's records and the Partnership's estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at March 31, 2005 and December 31, 2004 of $15.5 million and $13.4 million, respectively, related to its Mid-Continent-Velma operations, which are included in accounts receivable on its Consolidated Balance Sheets. The Partnership has unbilled revenues at March 31, 2005 and December 31, 2004 of $3.3 million and $1.9 million, respectively, related to its Appalachia operations, which is included in accounts receivable-/accounts payable- affiliates on its Consolidated Balance Sheets.

Goodwill

Goodwill is evaluated for impairment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142. All goodwill is associated with the Partnership’s Appalachian operations. 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.

New Accounting Standards

In April 2005, the Financial Accounting Standards Board (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 Statement FAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. As FIN 47 was recently issued, the Partnership has not determined whether the interpretation will have a significant adverse effect on its financial position or results of operations.

9

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

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

New Accounting Standards - (Continued)

In December 2004, the FASB issued Statement No. 123 (R) (revised 2004) Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation.  Statement 123 (R) supersedes Accounting Principal 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 accounts for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  Statement 123 (R) is effective for the Partnership beginning January 1, 2006.  The statement offers several alternatives for implementation.  At this time, management has not made a decision as to the alternative it may select.

NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS

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 March 31, 2005, the Partnership and its subsidiaries had $12.5 million in deposits at two banks, of which $12.2 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair values because of the short maturity of these instruments. The carrying value of long-term debt approximates fair market value since interest rates approximate current market rates.

The following table sets forth the book and estimated fair values of derivative instruments at the dates indicated (in thousands):

	March 31, 2005						December 31, 2004
	Book Value			Fair Value			Book Value			Fair Value
Assets
Derivative instruments	$	156		$	156		$	54		$	54
	$	156		$	156		$	54		$	54
Liabilities
Derivative instruments	$	(10,975	)	$	(10,975	)	$	(2,681	)	$	(2,681	)
	$	(10,975	)	$	(10,975	)	$	(2,681	)	$	(2,681	)
	$	(10,819	)	$	(10,819	)	$	(2,627	)	$	(2,627	)

10

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 4 - 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 March 8, 2005, the Partnership declared a cash distribution of $.75 per unit on its outstanding common units. The distribution represents the estimated available cash for the three months ended March 31, 2005. The $6.9 million distribution, which includes a distribution of $1.5 million to the general partner, will be paid on May 13, 2005 to unitholders of record on March 31, 2005.

NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

	March 31, 2005			December 31, 2004
Pipelines, processing and compression facilities	$	174,251		$	168,932
Rights of way		15,107			14,128
Buildings		3,282			3,215
Furniture and equipment		521			517
Other		444			307
		193,605			187,099
Less - accumulated depreciation		(13,758	)		(11,840	)
	$	179,847		$	175,259

Depreciation is provided for in amounts sufficient to relate the cost of depreciable assets to operations over the estimated useful lives of the assets using the straight-line method. The estimated service lives of property and equipment are principally as follows:

Pipelines, processing and compression facilities	15-20 years
Rights of way-Appalachia	20 years
Rights of way-Mid-Continent-Velma	40 years
Buildings	40 years
Furniture and equipment	3-7 years
Other	3-10 years

11

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 6 - OTHER ASSETS

The following is a summary of the Partnership’s other assets at the dates indicated (in thousands):

	March 31, 2005		December 31, 2004
Deferred finance costs, net of accumulated amortization of $688 and $506	$	4,488	$	3,316
Security deposits		1,299		1,356
Acquisition costs-Elk City (see note 15)		532		-
Other		-		14
	$	6,319	$	4,686

Deferred finance costs are recorded at cost and amortized over the five-year term of the associated debt, which expires on July 15, 2009.

NOTE 7 -SPECTRUM ACQUISITION

On July 16, 2004, the Partnership acquired Spectrum Field Services, Inc. (“Spectrum” or “Mid-Continent-Velma”), for approximately $143.0 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 allocation of the purchase price, 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		140,780
Other long-term assets		1,054
Total assets acquired		161,791
Accounts payable and accrued liabilities		(17,153	)
Hedging liabilities		(1,519	)
Long-term debt		(164	)
Total liabilities assumed		(18,836	)
Net assets acquired	$	142,955

The Partnership is in the process of evaluating certain estimates made in the purchase price and related allocations; thus, the purchase price and allocation are both subject to adjustment.

The following summarized pro forma consolidated income statement information for the three months ended March 31, 2004, assumes that the acquisition discussed above occurred as of 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 this acquisition as of the periods shown below or the results that will be attained in the future. The amounts presented below are in thousands, except per unit amounts:

12

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 7 -SPECTRUM ACQUISITION - (Continued)

	Three Months Ended
	March 31, 2004
	Pro Forma
	As Reported		Adjustment			Pro Forma
Revenues	$	4,246	$	27,407		$	31,653
Net income	$	2,477	$	1,410		$	3,887
Net income per limited partner unit, basic and diluted	$	.49	$	(.03	)	$	.46
Weighted average number of limited partner units
used for net income per unit calculation, basic
and diluted		4,355		2,850			7,205

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, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, the Partnership receives a fixed price and 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.

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 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 fair value for the derivative will be recognized immediately into earnings.

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 earnings as such transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. At March 31, 2005, the Partnership reflected a net hedging liability on its balance sheet of $10.8 million. Of the $9.6 million net loss in other comprehensive income (loss) at March 31, 2005, $7.4 million of losses will be reclassified to earnings over the next twelve month period as these contracts expire, and $2.2 million will be reclassified in later periods if the fair values of the instruments remain constant. Actual amounts that will be reclassified will vary as a result of future changes in prices. Ineffective gains or losses are recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized a loss of $669,000 related to these hedging instruments in the three months ended March 31, 2005. A loss of $224,000 resulting from ineffective hedges is included in income for the three months ended March 31, 2005. These losses are included in natural gas and liquids revenue on the Partnership’s consolidated statements of income.

13

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 8─ DERIVATIVE INSTRUMENTS - (Continued)

A portion of the Partnerships future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

As of March 31, 2005, the Partnership had the following NGLs, natural gas, and crude oil volumes hedged.

Natural Gas Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset (3)
Ended March 31,	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		990,000	$	-0.500	$	156

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(2)
Ended March 31,	(gallons)		(per gallon)		(in thousands)
2006		15,966,000	$	0.585	$	(5,453	)
2007		4,536,000		0.574		(1,581	)
					$	(7,034	)

Natural Gas Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended March 31,	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		1,110,000	$	6.203	$	(2,077	)
2007		300,000		5.905		(426	)
					$	(2,503	)

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended March 31,	(barrels)		(per barrel)		(in thousands)
2006		9,000	$	40.958	$	(136	)
2007		21,000		40.818		(295	)
					$	(431	)

Crude Oil Options

Production					Average		Fair Value
Period	Option Type		Volumes		Strike Price		Liability (3)
Ended March 31,			(barrels)		(per barrel)		(in thousands)
2006		Puts purchased		45,000	$	30.00	$	-
2006		Calls sold		45,000		34.25		(1,007	)
							$	(1,007	)
				Total liability			$	(10,819	)

14

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

_______________

(1) MMBTU means Million British Thermal Units.

(2) Fair value based on the Partnership's internal model which forecasts forward NGL prices as a function of forward NYMEX natural gas and light crude prices.

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

NOTE 9 - LONG-TERM DEBT

At March 31, 2005, the Partnership had $10.0 million outstanding on its revolving credit facility at a rate of 4.98% and $43.7 million outstanding on its term loan at an average rate of 5.65%. In addition, the Partnership had $1.6 million outstanding under letters of credit.

Annual debt principal payments over the next four fiscal periods ending March 31 are as follows:2006 − $2.3 million; 2007 − $2.3 million; 2008 − $2.3 million; 2009 − $12.2 million; 2010 - $34.8 million.

The credit facility requires the Partnership to maintain a specified ratio of debt to EBITDA, and a specified interest coverage ratio. At March 31, 2005, the Partnership was in compliance with all of the financial covenants. See Note 15 for information on the Partnership’s new credit facility which closed in April 2005.

NOTE10 - - LEASES AND COMMITMENTS

The Partnership leases equipment and office space with varying expiration dates through 2007. Rent expense for the quarters ended March 31, 2005 and 2004 was $423,800 and $160,300, respectively. Minimum future lease payments for these leases in the twelve month periods ending March 31, 2006, 2007, 2008, 2009 and 2010 are $647,400, $7,100, $6,200, $3,600, and $1,100, respectively.

At March 31, 2005, the Partnership had planned capital expenditures of $8.3 million for the next twelve month period.

NOTE 11 - - COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will 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.

15

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 12 − LONG-TERM INCENTIVE PLAN

The Partnership has a Long-Term Incentive Plan. A summary of the fair market value of equity-based incentive compensation awards of phantom units for the periods indicated is listed below (in thousands, except per unit data):

	Three Months Ended
	March 31,
	2005			2004
	(in thousands, except unit data)
Balance, beginning of period		58,752			-
Granted		67,338			1,692
Vested		(210	)		-
Forfeited		(679	)		-
Balance, end of period		125,201			1,692
Fair value, end of period	$	5,620		$	68
Vesting expense	$	548		$	-

Units granted under the Partnership’s Long-Term Incentive Plan vest over a period of four years from the date of grant. Of the 125,201 units outstanding at March 31, 2005, 31,326 units vest within the next twelve months.

NOTE13 - - RELATED PARTY TRANSACTIONS

The Partnership is affiliated with Resource America, Inc. (“RAI”) and its subsidiaries, including Atlas, Viking Resources Corporation and Resource Energy, Inc. (“Affiliates”). The Partnership is dependent upon the resources and services provided by RAI and these Affiliates. Accounts receivable/payable-affiliates represents the net balance due from/to these Affiliates for natural gas transported through the gathering systems, net of reimbursements for Partnership costs and expenses paid by these Affiliates. Substantially all Partnership revenue in Appalachia is from these 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.

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 and for the Affiliates. Other indirect costs, such as rent for offices in Philadelphia and New York, 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.

16

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE13 - RELATED PARTY TRANSACTIONS - (Continued)

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 $513,000 and $113,000 in the three months ended March 31, 2005 and 2004, respectively, for compensation and benefits related to their executive officers.  For the three months ended March 31, 2005 and 2004, direct reimbursements were approximately $4.3 million and $2.3 million, respectively, including certain costs that have been capitalized by the Partnership. The General Partner believes that the method used 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 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 14 - - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Partnership’s operations include two reportable operating segments. In addition to the reportable operating segments, certain other activities are reported in the "Other" category. These operating segments reflect the way the Partnership manages its operations and makes business decisions.

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

Three Months Ended March 31, 2005:
	Revenues from externalcustomers		Interestincome		Interestexpense		Depreciation, depletion andamortization		Segment profit (loss)			Other significant items: Segment assets
Natural gas and liquids	$	42,334	$	11	$	5	$	1,355	$	3,545		$	163,160
Transportation and compression		4,862		65		-		574		2,843			37,710
Other(a)		-		-		1,130		-		(2,138	)		15,017
Total	$	47,196	$	76	$	1,135	$	1,929	$	4, 250		$	215,887
Three Months Ended March 31, 2004:
	Revenues from external customers			Interestincome		Interestexpense		Depreciation, depletion andamortization		Segment profit (loss)			Other significant items: Segment assets
Natural gas and liquids	$	−	$	−	$	−	$	−	$	−		$	−
Transportation and compression		4,210		17		−		518		2,831			32,605
Other(a)		−		−		63		−		(354	)		14,745
Total	$	4,210	$	17	$	63	$	518	$	2,477		$	47,350

_______________

(a) Includes revenues and expenses which do not meet the quantitative threshold for reporting segment information and general corporate expenses not allocable to any particular segment.

17

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2005

(Unaudited)

NOTE 14 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

Segment profit (loss) represents total revenues less costs and expenses attributable thereto, including interest and depreciation and amortization.

The Partnership sells natural gas and NGLs under contract to various purchasers in the normal course of business. For the three months ended March 31, 2005, Mid-Continent-Velma had three purchasers that accounted for approximately 33%, 16% and 14% of the Partnership's revenues. Additionally, those purchasers accounted for $6.7 million, $3.5 million and $2.3 million of Mid-Continent-Velma’s trade receivables at March 31, 2005. Substantially all Appalachian revenues are derived from a master gas gathering agreement with the Affiliates.

NOTE 15 - SUBSEQUENT EVENTS

Acquisition

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 $194.4 million, including related transaction costs.Elk City’s principal assets include 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. Total gas throughput is currently approximately 262 mmcf/d. Total compression horsepower (hp) consists of 21,000 hp at six field stations and 12,000 hp within the Elk City and Prentiss facilities. The system gathers and processes gas from more than 300 receipt points representing more than fifty producers and delivers that gas into multiple interstate pipeline systems. The acquisition expands the Partnership activities in the Mid-Continent area and provides the potential for further growth in the Partnership’s operations based in Tulsa, Oklahoma.

The acquisition was accounted for using the purchase method of accounting under SFAS No. 141 “Business Combinations.” The following table presents the allocation of the purchase price, 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	$	3,837
Other current assets		1,237
Property, plant and equipment		193,121
Total assets acquired		198,195
Accounts payable and accrued liabilities		(3,770	)
Total liabilities assumed		(3,770	)
Net assets acquired	$	194,425

The purchase price is subject to post-closing adjustment based, among other things, on gas imbalances, certain prepaid expenses, capital expenditures, and title defects, if any. In addition, the Partnership is in the process of evaluating certain estimates made in the purchase price and related allocations; thus, the purchase price and allocation are both subject to adjustment.

18

NOTE 15 - SUBSEQUENT EVENTS - (Continued)

Credit Facility

To finance the Elk City acquisition, the Partnershipentered into a new $270 million credit facility which replaced its existing $135 million facility. Wachovia Capital Markets, LLC and Bank of America Securities LLC, are Co-Lead Arrangers. The bank group consists of the twelve banks that participated in the prior credit facility plus five new participants.

The five year facility is comprised of a $225 million revolving line of credit and a $45 million five year term loan. The Partnership immediately drew down $249.5 million which was used to refinance the existing $53.8 million outstanding on the prior $135 million facility and to finance the acquisition of Elk City.

                The credit facility requires The Partnership to maintain a specified interest coverage ratio, a specified ratio of funded debt to EBITDA, and a specified ratio of senior secured debt to EBITDA.

19

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. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

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

General

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, as of March 31, 2005, we gathered 52,371 mcf of gas per day 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, the parent company of our general partner.

Our Mid-Continent-Velma operations began in July 2004 upon our acquisition of Spectrum. In April 2005, we significantly expanded our Mid-Continent operations with the Elk City acquisition. In Mid-Continent-Velma, as of March 31, 2005 we gathered 64,956 mcf of gas per day from approximately 150 producers. 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.

Spectrum Acquisition

On July 16, 2004, we acquired our Velma operations for approximately $143.0 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.

The acquisition of Spectrum significantly changed our financial position and results of operations. We intend to finance our growth with a combination of long-term debt and equity to maintain our financial flexibility to fund future opportunities.

20

Elk City Acquisition

In April 2005, we acquired Elk City from affiliates of Energy Transfer Partners, L.P. (NYSE: ETP) for $194.4 million in cash, including related transaction costs. The purchase price is subject to post-closing adjustment based, among other things, on gas imbalances, certain prepaid expenses and capital expenditures, and title defects, if any. We expect the Elk City acquisition to be accretive to our cash distributions per common unit.

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.

We believe this acquisition will provide a significant source of growth and will significantly increase our size and results of operations.

Fee Arrangements

In Appalachia, substantially all of the gas we transport is for Atlas America under a percentage of proceeds, or POP, contract (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 $.35 or $.40 per 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 Mid-Continent-Velma are determined primarily by the fees we earn from the following two types of arrangements:

Fee-Based 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 or POP Contracts: These contracts provide for us to 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 75% of the natural gas volumes and 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.

As a result of our newly aquired Elk City gathering systems, we will 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.

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.

21

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 three months ended March 31, 2005, our principal revenues came from the sale of residue gas and NGLs.  In the three months ended March 31, 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 system, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

· the 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:

	For the three months ended March 31,
	2005			2004
Mid-Continent-Velma
Natural Gas
Gross natural gas gathered - mcf/day		64,956			-
Gross natural gas processed - mcf/day		62,985
Gross natural gas processed - MMBTU/day(1)		62,875
Gross residue natural gas - MMBTU/day		50,096			-
Equity natural gas sales - MMBTU/day		4,972			-
Natural gas gross margin (in thousands)(2)(4)	$	2,519		$	-
Natural gas sales equity percentage		11	%		-
NGLs
Gross NGL sales - barrels/day		6,403			-
Equity NGL sales - barrels/day		1,551			-
NGL gross margin (in thousands)(3)(4)	$	3,963		$	-
NGL equity percentage		24	%		-
Condensate
Gross condensate sales - barrels/day		243			-
Equity condensate sales - barrels/day		243			-
Condensate equity sales(4)	$	702		$	-
Appalachia
Throughout - mcf/day		52,371			51,437
Average transportation rate per mcf	$	1.03		$	.90
Total transportation and compression revenue (in thousands)	$	4,862		$	4,210

22

 _______________
⁽¹⁾ MMBTU means Million British Thermal Units 

⁽²⁾Gross margin calculated as natural gas revenue less natural gas costs.

⁽³⁾Gross margin calculated as NGL revenue less NGL costs.

⁽⁴⁾ Natural gas and NGL gross margins and condensate equity sales does not include effects of hedging gains or losses, which are reflected in our natural gas and liquids revenue on our Consolidated Statements of Income.

Three Months Ended March 31, 2005 Compared to March 31, 2004

Revenues.Our natural gas and liquids revenues are associated with our acquisition of Spectrum on July 16, 2004.

Our transportation and compression revenues increased to $4.9 million in the three months ended March 31, 2005 from $4.2 million in the three months ended March 31, 2004. This increase of $652,000 (15%) consisted of an increase in the average transportation rate paid to us ($618,000) and an increase in the volumes of natural gas we transported ($34,000).

Our transportation rate was $1.03 per Mcf in the three months ended March 31, 2005 as compared to $.90 per Mcf in the three months ended March 31, 2004, an increase of $.13 per Mcf (14%). During the three months ended March 31, 2005, natural gas prices increased over the three months ended March 31, 2004. Since our transportation rates are generally at fixed percentages of the sale prices of the natural gas we transport, the higher prices resulted in an increase in our average transportation rate.

Our average daily throughput volumes in Appalachia were 52,371 Mcfs in the three months ended March 31, 2005 as compared to 51,437 Mcfs in the three months ended March 31, 2004, an increase of 934 mcfs (2%). The increase in the average daily throughput volume resulted principally from volumes associated with new wells added to our pipeline system. In Appalachia, we connected 369 wells during the twelve months ended March 31, 2005, including 26 third party wells, as compared to 274, including a net loss of two third party wells, in the three months ended March 31, 2004.

Costs andExpenses.Our natural gas and liquids and plant operating expenses are associated with our acquisition of Spectrum on July 16, 2004.

Our transportation and compression expenses increased to $676,000 in the three months ended March 31, 2005 as compared to $607,000 in the three months ended March 31, 2004, an increase of $69,000 (11%). Our average cost per Mcf of transportation and compression increased to $.14 in the three months ended March 31, 2005 as compared to $.12 in the three months ended March 31, 2004, an increase of $.02 (17%). This increase primarily resulted from the amount of maintenance expense related to the additional pipelines and compressors added to accommodate new wells.

Our general and administrative expenses increased to $2.0 million in the three months ended March 31, 2005 as compared to $468,000 in the three months ended March 31, 2004, an increase of $1.5 million This increase includes the following:

• $752,000 of general and administrative expenses associated with the operations of Mid-Continent-Velma, which we acquired on July 16, 2004; and

• $548,000 for the expensing of phantom units issued under our Long-Term Incentive Plan and the related distributions on those units.

23

Our compensation reimbursement - affiliates increased to $513,000 in the three months ended March 31, 2005 as compared to $113,000 in the three months ended March 31, 2004, an increase of $400,000 as a result of allocations of compensation and benefits from Atlas America and its affiliates due to an increase in management time spent on reviewing our acquisition and capital raising opportunities.

Our depreciation and amortization expense increased to $1.9 million in the three months ended March 31, 2005 as compared to $518,000 in the three months ended March 31, 2004, an increase of $1.4 million. This increase resulted from depreciation associated with the acquisition of Spectrum, and our increased asset base associated with pipeline extensions and compressor upgrades. We anticipate that our depreciation expense will increase in the remainder of 2005 as a result of a full year of depreciation associated with our Mid-Continent-Velma operations and depreciation associated with our pipeline extensions and compressor upgrades.

Our interest expense increased to$1.1 million in the three months ended March 31, 2005 as compared to $63,000 in the three months ended March 31, 2004. This increase of $1.1 million resulted from increased borrowings in the three months ended March 31, 2005 as compared to the three months ended March 31, 2004. In July 2004, we borrowed $100.0 million to partially fund our acquisition of Spectrum. Subsequently, in July 2004, we repaid $40.0 million of these borrowings upon the completion of our public offering. In December 2004, we borrowed $10.0 million on our revolver facility and used $5.0 million of our available cash to repay $15.0 million or our term-loan borrowings. Our interest expense in the three months ended March 31, 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:

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

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

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

At March 31, 2005, we had $53.7 million outstanding and $78.4 million of remaining borrowing capacity under our credit facility.

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

	March 31,			December 31,
	2005			2004
Current ratio		0.78x			1.29x
Working capital (deficit) (in thousands)	$	(7,955	)	$	7,850
Ratio of long-term debt to total partners’ capital		.43x			.40x

24

Our net working capital decreased primarily due to an increase in the current portion of our net hedge liability of $6.7 million in the three months ended March 31, 2005.  This change is reflected in the change in fair-market value of our derivative instruments based on the subsequent increase in price after contract signing.  These increases in prices will be reflected in our earnings when the contracts settle.

Net cash provided by operations of $6.9 million in the three months ended March 31, 2005 increased $5.6 million from $1.3 million in the three months ended March 31, 2004. The increase is derived principally from an increase in net income before depreciation and amortization as a result of an increase in volumes transported and prices received for our natural gas and NGLs. Net income before depreciation and amortization was $6.2 million in the three months ended March 31, 2005, an increase of $3.2 million from the three months ended March 31, 2004. This increase was principally due to the acquisition of Spectrum on July 16, 2004 and the increase in the average transportation rate we received in Appalachia in the three months ended March 31, 2005 as compared to the three months ended March 31, 2004.

 

Net cash used in investing activities was $7.0 million for the three months ended March 31, 2005, an increase of $5.7 million from $1.3 million in the three months ended March 31, 2004. This increase was principally due to capital expenditures related to gathering system extensions and compressor upgrades to accommodate new wells which increased $4.9 million. In addition, we incurred additional acquisition costs related to Spectrum.

Net cash used in financing activities was $8.4 million for the three months ended March 31, 2005, an increase of $5.3 million from $3.1 million in the three months ended March 31, 2004. This increase was the result of an increase of $3.4 million in distributions to partners in the current year period as a result of an increase in net cash flow from operations and units outstanding. In addition, the amount of costs incurred for services related to our credit facility and repayments of that facility increased $1.9 million.

Capital Expenditures

Our property and equipment was approximately 83% and 81% of our total consolidated assets at March 31, 2005 and December 31, 2004, respectively. Capital expenditures, other than the acquisition of Spectrum, were $6.1 million and $1.2 million for the three months ended March 31, 2005 and 2004, respectively. These capital expenditures principally consisted of costs relating to the expansion of our existing gathering systems to accommodate new wells drilled in our service area and compressor upgrades. During the three months ended March 31, 2005, we connected 87 wells to our Appalachian gathering system. As of March 31, 2005, we were committed to expend approximately $8.2 million on pipeline extensions and compressor station upgrades. We anticipate that our capital expenditures will increase in the remainder of 2005 as a result of an increase in the estimated number of well connections to our gathering systems.

Credit Facility

Concurrently with the completion of the Spectrum acquisition, in July 2004, we entered into a $135.0 million senior secured term loan and revolving credit facility administered by Wachovia Bank that replaced our $20.0 million facility. The facility originally included a $35.0 million four year revolving line of credit and a $100.0 million five year term loan. Upon the completion of our July 2004 public offering, we repaid $40.0 million of the $100.0 million term loan we had borrowed in order to complete the acquisition of Spectrum, and in December 2004, we repaid an additional $15.0 million by borrowing $10.0 million on our revolving line of credit. In August 2004 and December 2004, the revolving credit portion of the credit facility was increased to $75.0 million and $90.0 million, respectively. Up to $5.0 million of the facility may be used for standby letters of credit.

25

We had $10.0 million outstanding on our revolving credit facility at a rate of 4.98% and $43.7 million outstanding on our term loan at an average rate of 5.65% at March 31, 2005. In addition, we had $1.6 million outstanding under letters of credit.

See Note 15 of our Consolidated Financial Statements for information on our new credit facility which closed on April 14, 2005. After the borrowings on our new credit facility in April 2005 to fund the Elk City acquisition, we have approximately $249.5 million outstanding at 5.70% and $18.9 million of available borrowing capacity. In addition, we have $1.6 million outstanding under letters of credit. We may be required to obtain additional financing by September 30, 2005 in order to meet the finacial covenants under this new credit facility.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments atMarch 31, 2005:

			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Long-term debt(1)	$	53,881	$	2,306	$	4,608	$	46,967	$	-
Capital lease obligations		-		-		-		-		-
Operating leases		665		647		13		5		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligations		-		-		-		-		-
Total contractual cash obligations	$	54,546	$	2,953	$	4,621	$	46,972	$	-

_______________

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at March 31, 2005, 2006 - $2.9 million; 2007 - $2.8 million; 2008 - $2.7 million; 2009 - $2.2 million and 2010 - $493,300.

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

			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Standby letters of credit	$	1,567	$	1,567	$	-	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		8,321		8,321		-		-		-
Total commercial commitments	$	9,888	$	9,888	$	-	$	-	$	-

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

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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 2004. The critical accounting policies and estimates that we have identified are discussed below.

Revenue 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. We believe our estimates are reasonable, but there is no assurance that actual amounts will not 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 undiscounted future cash flows associated with such asset or group of assets. If the carrying amount is greater than the estimated undiscounted 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 March 31, 2005, we had $2.3 million of goodwill, all of which relates to the acquisition of our Appalachia pipeline assets. We test our goodwill for impairment each year. Our test during 2004 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, 2005.

Fair Value of Derivative Commodity Contracts

We utilize various over-the-counter commodity financial instrument contracts to limit our exposure to fluctuations in natural gas and NGL prices, primarily commodity, swaps, options and certain basis contracts. Some of these contracts, which in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, are not accounted for as hedges, are marked to fair value on the income statement. We utilize published settlement prices for exchange-traded contracts, and for our other contracts, use quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. The values have been adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under existing market conditions. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. On our contracts that are designated as cash flow hedging instruments in accordance with SFAS No. 133, the effective portion of the hedged gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the instrument settles. The ineffective portion of the gain or loss is reported in earnings immediately.

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Volume Measurement

We record amounts for natural gas gathering and transportation revenue, NGL processing revenue, natural gas sales and natural gas purchases, and the sale of production based on volumetric calculations. Variances resulting from such calculations are inherent in our business.

New Accounting Standards

In April 2005, the Financial Accounting Standards Board (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 Statement FAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. As FIN 47 was recently issued, we have not determined whether the interpretation will have a significant adverse effect on our financial position or results of operations.

In December 2004, the FASB issued Statement No. 123 (R) (revised 2004) Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation.  Statement 123 (R) supersedes Accounting Principal 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 Company accounts for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  Statement 123 (R) is effective for the Partnership beginning January 1, 2006.  The Statement offers several alternatives for implementation.  At this time, management has not made a decision as to the alternative it may select.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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General

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

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use derivative financial instruments.

The following analysis presents the effect on our earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2005. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate RiskAt March 31, 2005, we had a $90.0 million revolving credit facility ($10.0 million outstanding) and a $43.7 million term loan ($43.7 million outstanding) to fund the expansion of our existing gathering systems and the acquisitions of other natural gas gathering systems. The weighted average interest rate for these borrowings was 5.51% at March 31, 2005.

Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $297,000.

Commodity Price Risk.We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees for commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on our current portfolio of gas supply contracts, we have long condensate, NGL and natural gas positions. A 10% increase in the average price of NGLs, natural gas and crude oil we process and sell would result in an increase to our 2005 annual income of approximately $643,000. A 10% decrease in the average price of NGLs, natural gas and crude oil we process and sell would result in a decrease to our 2005 annual income of $838,000.

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

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

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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 partner’s capital as other comprehensive income (loss) and reclassified to earnings as such transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. At March 31, 2005, we reflected a net hedging liability on our balance sheet of $10.8 million. Of the $9.6 million net loss in other comprehensive income (loss) at March 31, 2005, $7.4 million of losses will be reclassified to earnings over the next twelve month period as these contracts expire, and $2.2 million will be reclassified in later periods, if the fair values of the instruments remain constant. Actual amounts that will be reclassified will vary as a result of future changes in prices. Ineffective gains or losses are recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. We recognized a loss of $669,000 related to these hedging instruments in the three months ended March 31, 2005. A loss of $224,000 resulting from ineffective hedges is included in income for the three months ended March 31, 2005. These losses are included in natural gas and liquids revenue on our consolidated statements of income.

A portion of our future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

As of March 31, 2005, we had the following NGLs, natural gas, and crude oil volumes hedged.

Natural Gas Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset (3)
Ended March 31,	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		990,000	$	-0.500	$	156

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(2)
Ended March 31,	(gallons)		(per gallon)		(in thousands)
2006		15,966,000	$	0.585	$	(5,453	)
2007		4,536,000		0.574		(1,581	)
					$	(7,034	)

Natural Gas Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended March 31,	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		1,110,000	$	6.203	$	(2,077	)
2007		300,000		5.905		(426	)
					$	(2,503	)

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended March 31,	(barrels)		(per barrel)		(in thousands)
2006		9,000	$	40.958	$	(136	)
2007		21,000		40.818		(295	)
					$	(431	)

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Crude Oil Options

Production					Average		Fair Value
Period	Option Type		Volumes		Strike Price		Liability (3)
Ended March 31,			(barrels)		(per barrel)		(in thousands)
2006		Puts purchased		45,000	$	30.00	$	-
2006		Calls sold		45,000		34.25		(1,007	)
							$	(1,007	)
Total liability							$	(10,819	)

_______________

(1) MMBTU means Million British Thermal Units.

(2) Fair value based on APLMC internal model which forecasts forward natural gas liquid prices as a function of forward NYMEX natural gas and light crude prices.

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

We do not engage in any interest rate or foreign currency exchange rate transactions, and as a result, we do not have exposure to those types of derivative risk.

ITEM 4.CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

There have been no significant changes in our internal controls over financial reporting that have 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 2.CHANGES IN SECURITIES AND USE OF PROCEEDS

None

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

None

ITEM 6.EXHIBITS

Exhibit No.	Description
2.1	Purchase and Sale Agreement, dated March 8, 2005, by and among LG PL, LLC and LaGrange Acquisition as Sellers and Atlas Pipeline Partners, L.P. as Purchaser(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 on April 19, 2005 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.

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SIGNATURES

ATLAS PIPELINE PARTNERS, L.P.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	By:	Atlas Pipeline Partners GP, LLC, its General Partner
Date: May 10, 2005	By:	/s/ Edward E. Cohen
		EDWARD E. COHEN Chairman of the Managing Board of the General Partner (Chief Executive Officer of the General Partner)

Date: May 10, 2005	By:	/s/ Michael L. Staines
		MICHAEL L. STAINES President, Chief Operating Officer and Managing Board Member of the General Partner

Date: May 10, 2005	By:	/s/ Matthew A. Jones
		MATTHEW A. JONES Chief Financial Officer of the General Partner

Date: May 10, 2005	By:	/s/ Nancy J. McGurk
		NANCY J. MCGURK Chief Accounting Officer of the General Partner

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