Atlas Pipeline Partners 8-K Reports Second Quarter 2008 Results

Exhibit 99.1

ATLAS PIPELINE PARTNERS, L.P.

REPORTS SECOND QUARTER 2008 RESULTS

Philadelphia, PA, July 31, 2008 – Atlas Pipeline Partners, L.P. (NYSE: APL) (the “Partnership”)today reported financial results for the second quarter 2008.

The results of the second quarter 2008 include:

• Adjusted EBITDA⁽¹⁾, a non-GAAP measure, of $76.0 million compared with $24.2 million for the prior year second quarter, an increase of $51.8 million, or over 214%. The quarter-over-quarter results were favorably impacted by contributions from the Chaney Dell and Midkiff/Benedum systems, which the Partnership acquired in July 2007, higher aggregate volumes on its other systems and higher natural gas liquids (“NGL”) and condensate prices. A reconciliation of non-GAAP measures, including adjusted EBITDA, distributable cash flow, and adjusted net income, is provided within the financial tables of this release;

• Distributable cash flow, a non-GAAP measure, of $55.9 million, an increase of $39.2 million or over 234%, compared to the prior year second quarter. The Partnership declared a record quarterly cash distribution for the second quarter 2008 of $0.96 per common limited partner unit. This distribution represented an increase of $0.09 per unit, or 10.3%, compared to the prior year second quarter. Excluding the impact of the distributions declared by the Partnership on the 7.1 million aggregate common limited partner units issued at the end of June 2008 as discussed further below, the Partnership’s distribution coverage ratio for the second quarter 2008 was 1.2x. Including the issuance of such units, the Partnership’s distribution coverage ratio for the second quarter 2008 was approximately 1.0x;

• Adjusted net income, a non-GAAP measure, of $30.4 million for the second quarter 2008, an increase of $20.2 million, or almost 200%, compared to the prior year second quarter. Due to the non-cash and non-recurring cash derivative losses recognized in the current quarter as described below, on a GAAP basis the Partnership recognized a net loss of $278.7 million for the second quarter 2008 compared with a net loss of $20.8 million for the prior year second quarter;

• System-wide volumes of 1.3 billion cubic feet per day (“bcfd”) for the second quarter 2008 compared to volumes of approximately 0.8 bcfd for the prior year second quarter, an increase of approximately 63%; and

• In addition, the Partnership affirms its previously announced anticipated increase in distributions per common unit guidance after a 1.3x distribution coverage ratio of $2.00 to $2.20 per unit for the second half of 2008. The mid point of the guidance range represents a 14% increase compared to cash distributions paid in the second half of 2007 after a 1.2x distribution coverage ratio. In addition, the Partnership affirms full year 2009 guidance of $4.25 to $4.50 of distributions per common unit after a 1.3x distribution coverage ratio.

The Partnership’s financial results for the second quarter 2008 were affected by the following items:

• On June 24, 2008, the Partnership sold 5,750,000 common units in a public offering at a price to the public of $37.52, resulting in approximately $206.6 million of net proceeds. Also on June 24, 2008, the Partnership sold 278,000 common units to Atlas Pipeline Holdings, L.P., the parent of the Partnership’s general partner (NYSE: AHD – “AHD”), and 1,112,000 common units to Atlas America, Inc., the parent of AHD’s general partner (NASDAQ: ATLS – “ATLS”) in a private placement at a price of $36.02, resulting in approximately $50.1 million of net proceeds. In addition, the Partnership received approximately $5.4 million from its general partner to maintain its aggregate 2% general partner interest in the Partnership;

• The net proceeds from the public and private placement offerings of the Partnership’s common units were used to fund the early termination of approximately 85% of the Partnership’s crude oil derivative contracts that it entered into as proxy hedges for the prices it receives for the ethane and propane portion of its NGL equity volume. These hedges, which related to production periods ranging from the end of second quarter of 2008

through the fourth quarter of 2009, were put in place in connection with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and became less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. The Partnership terminated these derivative contracts during June and July 2008 at an aggregate net cost of approximately $264.0 million. The Partnership’s net loss for the second quarter 2008 includes a $116.1 million cash derivative expense resulting from the June 2008 net payments of $170.4 million to terminate a portion of these derivative contracts. The Partnership made payments of $93.6 million during July 2008 to terminate the remaining portion of these derivative contracts and will reflect a charge against its net income for a portion of this amount during the third quarter of 2008. The attached hedge schedule reflects the hedge position of the Partnership as of June 30, 2008, adjusted for the crude oil derivative contracts that were terminated in July 2008 with the proceeds of the public and private placement offerings. As a result of the termination of these hedge contracts, the Partnership’s future cash flow should more accurately reflect the revenues generated from its ethane and propane volumes produced in its natural gas processing operations;

• On June 27, 2008, the Partnership issued $250.0 million of 10-year, 8.75% senior unsecured notes (the “senior notes”) in a private placement transaction. The sale of the senior notes generated net proceeds of approximately $244.9 million, which was utilized to repay indebtedness under its senior secured term loan and revolving credit facility; and

• On June 27, 2008, the Partnership obtained $80.0 million of increased commitments to its senior secured revolving credit facility, increasing the amount committed under the facility to $380.0 million.

*    *    *

Mid-Continent Segment Results

• Mid-Continent segment total revenue increased $318.1 million, or approximately 276%, compared with the prior year second quarter to $433.5 million for the second quarter 2008, excluding the effect of non-cash derivative expenses and the non-recurring cash derivative early termination expense. This increase principally reflects the contribution from the acquisition of the Chaney Dell and Midkiff/Benedum systems and higher volumes and commodity prices on its Velma and NOARK systems.

• The NOARK Ozark Gas Transmission (“OGT”) system’s throughput volume increased 79.8 million cubic feet per day (“MMcfd”), or 25%, compared with the prior year second quarter to 401.5 MMcfd for the second quarter 2008. The Partnership has previously announced its intention to further increase OGT’s throughput capacity during 2008 from 400 MMcfd to 500 MMcfd through additional compression added to the system.

• The Elk City/Sweetwater system’s average natural gas processed volume decreased slightly to 229.7 MMcfd when compared with the prior year second quarter. However, the system’s efficiency rose significantly when compared with the prior year second quarter as average NGL production increased 710 barrels per day (“bpd”) for the second quarter 2008, or approximately 7%, compared with the prior year comparable period. The Partnership connected 17 new wells to the Elk City/Sweetwater system during the second quarter 2008.

• The Velma system’s average processed natural gas volume increased 1.0 MMcfd, or approximately 2%, compared with the prior year second quarter to 62.1 MMcfd for the second quarter 2008. The Partnership connected 9 new wells to its Velma system during the second quarter 2008.

• The Chaney Dell system’s average processed natural gas volume was 256.8 MMcfd for the second quarter 2008. In addition, NGL production volumes increased 957 bpd to 13,358 bpd, or 8% compared to the first quarter 2008. The Partnership connected 89 new wells to its Chaney Dell system during the second quarter 2008.

• The Midkiff/Benedum system’s average processed natural gas volume was 141.2 MMcfd for the second quarter 2008. The Partnership connected 44 new wells to its Midkiff/Benedum system during the second quarter 2008.

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Appalachia Segment Results

• Total revenue for the Appalachia segment increased $4.4 million, or approximately 51%, compared with the prior year second quarter to $13.0 million for the second quarter 2008, due principally to higher throughput volume, higher natural gas prices and $1.1 million of natural gas and liquids sales associated with the Irishtown processing plant, which was acquired in August 2007.

• Throughput volume increased to a record 84.5 MMcfd for the second quarter 2008, or 28%, compared with the prior year second quarter resulting from the connection of new wells to the Appalachia gathering system, primarily through its relationship with Atlas Energy Resources, LLC (NYSE: ATN) (“Atlas Energy”), and throughput associated with the gathering system acquired in connection with the Irishtown processing plant and the northeastern Tennessee gathering system acquired in February 2008. The Tennessee gathering system, acquired for $9.1 million, serves several counties northwest of Knoxville, an area of active drilling and production including that of Atlas Energy. In conjunction with the acquisition of the gathering system, the Partnership has announced that it intends to construct a new 20 Mmcf per day cryogenic processing facility that will service natural gas produced in this northeastern Tennessee area.

• During the second quarter 2008, 203 new wells were connected to the Appalachia gathering system compared with 146 new wells for the prior year second quarter.

Corporate and Other

• General and administrative expense, including amounts reimbursed to affiliates, increased $2.6 million to $10.0 million for the second quarter 2008 compared with $7.4 million for the prior year second quarter. This increase was primarily related to higher costs of managing the Partnership’s operations, including the Chaney Dell and Midkiff/Benedum systems acquired in July 2007 and acquisition and capital raising opportunities, partially offset by a $1.3 million decrease in non-cash compensation expense. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized for certain common unit awards for which the ultimate amount to be issued will be determined after the completion of the Partnership’s 2008 fiscal year. The mark-to-market gain was the result of a change in the Partnership’s common unit market price at June 30, 2008 when compared with the March 31, 2008 price, which is utilized in the estimate of the non-cash compensation expense for these awards.

• Depreciation and amortization increased $19.5 million compared with the prior year second quarter to $26.2 million for the second quarter 2008 due primarily to the depreciation associated with the Chaney Dell and Midkiff/Benedum assets acquired by the Partnership in July 2007, the Partnership’s expansion capital expenditures incurred subsequent to the second quarter 2007, and a $4.0 million write-off of costs related to a pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with a contractual arrangement. The Partnership had recorded a similar $4.0 million write-off of costs related to the same contractual arrangement during the first quarter 2008, and no further write-offs with regard to this contractual arrangement are expected.

• Interest expense increased $12.1 million to $19.4 million for second quarter 2008 compared with the prior year second quarter primarily related to interest associated with the Partnership’s term loan, and secondarily, from higher average borrowings under the Partnership’s $380.0 million revolving credit facility and a $1.4 million increase in amortization of deferred finance costs. The increased borrowings were partially offset by lower interest rates. The term loan was issued in July 2007 to partially finance the acquisition of the Chaney Dell and Midkiff/Benedum systems, while the additional borrowings under the revolving credit facility reflect the Partnership’s expansion capital expenditures. The increase in amortization of deferred finance costs was principally due to $1.2 million of accelerated amortization associated with the retirement of a portion of the Partnership’s term loan with a portion of the net proceeds from its issuance of senior notes in June 2008.

At June 30, 2008, the Partnership had $1.3 billion of total debt, including its $707.2 million term loan that matures in 2014, $544.3 million of senior unsecured notes that mature in 2015 and 2018, and $20.0 million of outstanding borrowings under its revolving credit facility that matures in 2013. The Partnership also has interest rate swap contracts for a notional principal amount totaling $450.0 million which expire during the first half of 2010. These contracts convert a portion of the Partnership’s LIBOR-based floating rate exposure under its term loan and revolving credit facility to a fixed LIBOR rate averaging 3.02%, plus the applicable margin as defined under the terms credit facility.

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⁽¹⁾ Adjusted EBITDA represents adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), a non-GAAP (generally accepted accounting principles) measure.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s second quarter 2008 results on Friday, August 1, 2008 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website atwww.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 11:00 am ET on Friday, August 1, 2008. To access the replay, dial 1-888-286-8010 and enter conference code 18657041.

Atlas Pipeline Partners, L.P. is active in the transmission, gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, Arkansas, southern Kansas, northern and western Texas and the Texas panhandle, the Partnership owns and operates eight active gas processing plants and a treating facility, as well as approximately 7,900 miles of active intrastate gas gathering pipeline and a 565-mile interstate natural gas pipeline. In Appalachia, it owns and operates approximately 1,600 miles of natural gas gathering pipelines in western Pennsylvania, western New York, eastern Ohio and northeastern Tennessee. For more information, visit our website atwww.atlaspipelinepartners.com or contactbbegley@atlaspipelinepartners.com.

Atlas Pipeline Holdings, L.P.is a limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P., through which it owns a 2% general partner interest, all the incentive distribution rights and approximately 5.8 million common units of Atlas Pipeline Partners.

Atlas Energy Resources, LLC develops and produces domestic natural gas and to a lesser extent, oil. Atlas Energy is one of the largest independent energy producers in the Appalachian Basin and northern Michigan. The Company sponsors and manages tax-advantaged investment partnerships, in which it co-invests, to finance the exploration and development of the Company’s acreage in the Appalachian Basin. Atlas Energy is active principally in Pennsylvania, Michigan and Tennessee. For more information, visit Atlas Energy’s website at www.atlasenergyresources.com or contact investor relations atbbegley@atlasamerica.com.

Atlas America, Inc. owns an approximate 64% limited partner interest in Atlas Pipeline Holdings, L.P., an approximate 2% direct limited partner interest in Atlas Pipeline Partners and an approximate 48% common unit interest and all of the Class A and management incentive interests in Atlas Energy Resources, LLC. For more information, please visit its website atwww.atlasamerica.com, or contact Investor Relations atbbegley@atlasamerica.com.

Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Factors that could cause actual results to differ materially from expectations include financial performance, inability of the Partnership to successfully integrate the operations at the acquired systems, regulatory changes, changes in local or national economic conditions and other risks detailed from time to time in Atlas Pipeline’s reports filed with the SEC, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary

(in thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
STATEMENTS OF OPERATIONS
Revenue:
Natural gas and liquids	$	439,286		$	104,792		$	805,405		$	206,968
Transportation, compression, and other fees – affiliates		11,421			8,458			20,580			16,178
Transportation, compression, and other fees – third parties		12,709			10,588			27,571			20,426
Other loss		(314,261	)		(28,423	)		(401,015	)		(30,620	)
Total revenue and other loss		149,155			95,415			452,541			212,952
Costs and expenses:
Natural gas and liquids		349,980			87,102			626,644			174,912
Plant operating		14,831			4,515			29,766			9,045
Transportation and compression		4,301			3,210			8,113			6,322
General and administrative		8,631			6,608			13,001			12,311
Compensation reimbursement – affiliates		1,390			798			2,519			1,428
Depreciation and amortization		26,196			6,671			52,021			13,205
Interest		19,385			7,327			39,766			14,086
Minority interest		3,112			—			5,202			—
Total costs and expenses		427,826			116,231			777,032			231,309
Net loss		(278,671	)		(20,816	)		(324,491	)		(18,357	)
Preferred unit dividend effect		—			(3,756	)		—			(3,756	)
Preferred unit dividends		(650	)		—			(787	)		—
Preferred unit imputed dividend cost		—			(735	)		(505	)		(1,234	)
Net loss attributable to common limited partners and the general partner	$	(279,321	)	$	(25,307	)	$	(325,783	)	$	(23,347	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(281,775	)	$	(28,728	)	$	(334,162	)	$	(30,612	)
General partner’s interest		2,454			3,421			8,379			7,265
Net loss attributable to common limited partners and the general partner	$	(279,321	)	$	(25,307	)	$	(325,783	)	$	(23,347	)
Net loss attributable to common limited partners per unit:
Basic	$	(7.16	)	$	(2.20	)	$	(8.56	)	$	(2.34	)
Diluted	$	(7.16	)	$	(2.20	)	$	(8.56	)	$	(2.34	)
Weighted average common limited partner units outstanding:
Basic		39,329			13,080			39,046			13,080
Diluted		39,329			13,080			39,046			13,080
Capital expenditure data:
Maintenance capital expenditures	$	2,045		$	700		$	3,664		$	1,472
Expansion capital expenditures		71,156			24,552			153,606			40,409
Total	$	73,201		$	25,252		$	157,270		$	41,881

Balance Sheet Data (at period end):	June 30, 2008		December 31, 2007
Cash and cash equivalents	$	161,393	$	11,980
Total assets		3,157,456		2,877,614
Total debt		1,271,533		1,229,426
Total partners’ capital		1,051,514		1,273,960

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Segment Information

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Mid-Continent
Revenue:
Natural gas and liquids	$	438,163		$	104,792		$	803,322		$	206,968
Transportation, compression, and other fees		12,388			10,571			27,003			20,390
Other loss		(314,350	)		(28,506	)		(401,215	)		(30,785	)
Total revenue and other loss		136,201			86,857			429,110			196,573
Costs and expenses:
Natural gas and liquids		349,475			87,102			625,657			174,912
Plant operating		14,831			4,515			29,766			9,045
Transportation and compression		1,656			1,780			3,154			3,500
General and administrative		6,977			4,806			9,507			8,700
Depreciation and amortization		24,652			5,555			49,095			11,015
Minority interest		3,112			—			5,202			—
Total costs and expenses		400,703			103,758			722,381			207,172
Segment loss	$	(264,502	)	$	(16,901	)	$	(293,271	)	$	(10,599	)
Appalachia
Revenue:
Natural gas and liquids	$	1,123			—		$	2,083			—
Transportation, compression, and other fees – affiliates		11,421			8,459			20,580			16,179
Transportation, compression, and other fees – third parties		321			16			568			35
Other income		89			83			200			165
Total revenue and other income		12,954			8,558			23,431			16,379
Costs and expenses:
Natural gas and liquids		505			—			987			—
Transportation and compression		2,645			1,430			4,959			2,822
General and administrative		1,523			1,300			3,007			2,520
Depreciation and amortization		1,544			1,116			2,926			2,190
Total costs and expenses		6,217			3,846			11,879			7,532
Segment profit	$	6,737		$	4,712		$	11,552		$	8,847
Reconciliation of segment loss to net loss:
Segment profit (loss):
Mid-Continent	$	(264,502	)	$	(16,901	)	$	(293,271	)	$	(10,599	)
Appalachia		6,737			4,712			11,552			8,847
Total segment loss		(257,765	)		(12,189	)		(281,719	)		(1,752	)
Corporate general and administrative expense		(1,521	)		(1,300	)		(3,006	)		(2,519	)
Interest expense		(19,385	)		(7,327	)		(39,766	)		(14,086	)
Net loss	$	(278,671	)	$	(20,816	)	$	(324,491	)	$	(18,357	)

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Reconciliation of total revenue and other loss to adjusted total revenue and other loss(1):
Total revenue and other loss	$	149,155		$	95,415		$	452,541		$	212,952
Non-cash derivative expense		181,147			28,549			258,003			30,826
Non-recurring cash derivative early termination expense(2)		116,125			—			116,125			—
Non-recurring crude oil to natural gas liquids price correlation impact(3)		10,653			—			10,653			—
Adjusted total revenue and other loss	$	457,080		$	123,964		$	837,322		$	243,778
Reconciliation of net loss to adjusted net income(1):
Net loss	$	(278,671	)	$	(20,816	)	$	(324,491	)	$	(18,357	)
Non-cash derivative expense		181,147			28,549			258,003			30,826
Non-recurring cash derivative early termination expense(2)		116,125			—			116,125			—
Non-recurring crude oil to natural gas liquids price correlation impact(3)		10,653			—			10,653			—
Non-cash compensation expense (income)		1,195			2,481			(1,600	)		4,276
Adjusted net income	$	30,449		$	10,214		$	58,690		$	16,745
Preferred unit dividend effect		—			(3,756	)		—			(3,756	)
Preferred unit dividends		(650	)		—			(787	)		—
Preferred unit imputed dividend cost		—			(735	)		(505	)		(1,234	)
Adjusted net income attributable to common limited partners and the general partner	$	29,799		$	5,723		$	57,398		$	11,755
Allocation of adjusted net income attributable to common limited partners and the general partner:
Common limited partners’ interest	$	21,132		$	1,678		$	41,317		$	3,785
General partner’s interest		8,667			4,045			16,081			7,970
Adjusted net income attributable to common limited partners and the general partner	$	29,799		$	5,723		$	57,398		$	11,755
Adjusted net income attributable to common limited partners per unit:
Basic	$	0.54		$	0.13		$	1.06		$	0.29
Diluted	$	0.52		$	0.13		$	1.03		$	0.28
Weighted average common limited partner units outstanding:
Basic		39,329			13,080			39,046			13,080
Diluted		40,319			13,351			40,031			13,338
Reconciliation of net loss to other non-GAAP measures(1):
Net loss	$	(278,671	)	$	(20,816	)	$	(324,491	)	$	(18,357	)
Depreciation and amortization		26,196			6,671			52,021			13,205
Interest expense		19,385			7,327			39,766			14,086
EBITDA		(233,090	)		(6,818	)		(232,704	)		8,934
Non-cash derivative expense		181,147			28,549			258,003			30,826
Non-recurring cash derivative early termination expense(2)		116,125			—			116,125			—
Non-recurring crude oil to natural gas liquids price correlation impact(3)		10,653			—			10,653			—
Non-cash compensation expense (income)		1,195			2,481			(1,600	)		4,276
Adjusted EBITDA		76,030			24,212			150,477			44,036
Interest expense		(19,385	)		(7,327	)		(39,766	)		(14,086	)
Amortization of deferred financing costs		1,929			534			2,608			1,068
Preferred unit dividends		(650	)		—			(787	)		—
Maintenance capital expenditures		(2,045	)		(700	)		(3,664	)		(1,472	)
Distributable cash flow(4)	$	55,879		$	16,719		$	108,868		$	29,546

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⁽¹⁾ Adjusted net income, adjusted total revenue and other loss, EBITDA, adjusted EBITDA and distributable cash flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of the Partnership believes that adjusted net income, adjusted total revenue and other loss, EBITDA, adjusted EBITDA and distributable cash flow provide additional information for evaluating the Partnership’s ability to make distributions to its common unitholders and the general partner, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. EBITDA and adjusted EBITDA are also financial measurements that, with certain negotiated adjustments, are utilized within the Partnership’s financial covenants under its credit facility. Adjusted net income, EBITDA, adjusted EBITDA and distributable cash flow are not measures of financial performance under GAAP and, accordingly, should not be considered as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.

⁽²⁾ In June and July 2008, the Partnership closed crude oil costless collar derivative positions it had on approximately 85% of the ethane and propane portion of its NGL production volume for the periods from principally the 2^nd quarter 2008 through the 4^th quarter of 2009. In completing this transaction, the Partnership made net payments to the counterparties of these derivative positions, approximately $264.0 million, to settle the outstanding positions at their current fair market value, with $170.4 million of net payments made during June 2008 and $93.6 million paid during July 2008. The settlement of these derivative positions will result in the Partnership recognizing higher adjusted EBITDA and distributable cash flow during these future periods. These settlements were funded through the Partnership’s June 2008 issuance of 5.75 million common limited partner units in a public offering and issuance of 1.39 million common limited partner units to Atlas Pipeline Holdings, L.P. (NYSE: AHD), the owner of its general partner, and Atlas America, Inc. (NASDAQ: ATLS), the parent of Atlas Pipeline Holdings, L.P.’s general partner, in a private placement.

⁽³⁾ Represents the non-recurring impact generated from the decline in the price correlation of crude oil and natural gas liquids during the second quarter 2008 and the resulting impact it had on certain crude oil derivative instruments (“proxy hedges”) which the Partnership intended to mitigate the effect of commodity price movements on the ethane and propane portion of its natural gas liquid production volume. These derivative instruments were put in place simultaneously with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and have become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. During June and July 2008, the Partnership closed the derivative positions it had on approximately 85% of the ethane and propane portion of its NGL production volume for the periods from principally the 2^nd quarter 2008 through the 4^th quarter of 2009 for an aggregate net cost of $264.0 million (see Note 2). As such, the Partnership’s future cash flow should more accurately reflect the revenues generated from its ethane and propane volumes produced in its natural gas processing operations.

⁽⁴⁾ In connection with the acquisition of control of the Chaney Dell and Midkiff/Benedum systems, the Partnership’s general partner, which holds all of the incentive distribution rights in the Partnership, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to the Partnership through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. The general partner also agreed that the resulting allocation of incentive distribution rights back to the Partnership would be allocated after the General Partner receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Operating Highlights

	Three Months Ended June 30,		Six Months Ended June 30,
	2008	2007	2008	2007
Mid-Continent – Velma System
Natural Gas
Gross natural gas gathered – mcfd(1)	65,519	62,788	63,960	61,907
Gross natural gas processed – mcfd(1)	62,148	61,150	61,008	59,836
Gross residue natural gas – mcfd(1)	49,033	47,229	48,086	46,463
Natural Gas Liquids
Gross NGL sales – bpd(1)	6,993	6,697	6,841	6,473
Condensate
Gross condensate sales – bpd(1)	296	212	277	206
Mid-Continent – Elk City/Sweetwater System
Natural Gas
Gross natural gas gathered – mcfd(1)	292,544	308,703	298,961	298,355
Gross natural gas processed – mcfd(1)	229,673	234,896	233,038	221,151
Gross residue natural gas – mcfd(1)	207,859	215,501	210,495	203,288
Natural Gas Liquids
Gross NGL sales – bpd(1)	10,452	9,742	10,565	9,132
Condensate
Gross condensate sales – bpd(1)	284	220	324	271
Mid-Continent – Chaney Dell System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)	284,528	—	268,008	—
Gross natural gas processed – mcfd(1)	256,835	—	252,348	—
Gross residue natural gas – mcfd(1)	243,465	—	231,830	—
Natural Gas Liquids
Gross NGL sales – bpd(1)	13,358	—	12,880	—
Condensate
Gross condensate sales – bpd(1)	855	—	781	—
Mid-Continent – Midkiff/Benedum System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)	150,157	—	146,350	—
Gross natural gas processed – mcfd(1)	141,240	—	138,947	—
Gross residue natural gas – mcfd(1)	96,160	—	96,386	—
Natural Gas Liquids
Gross NGL sales – bpd(1)	20,830	—	20,590	—
Condensate
Gross condensate sales – bpd(1)	1,567	—	1,144	—
Mid-Continent – NOARK system
Ozark Gas Transmission throughput – mcfd(1)	401,539	321,717	395,916	304,400
Appalachia
Throughput – mcfd(1)	84,475	66,152	80,054	64,352

⁽¹⁾ “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.

⁽²⁾ The Chaney Dell and Midkiff/Benedum systems were acquired on July 27, 2007.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Mid-Continent Segment Hedge Positions

(as of July 31, 2008)

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,
January 2008–January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2008
				2009
				2010
April 2008–April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2008
				2009
				2010

Natural Gas Liquids Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price
	(gallons)	(per gallon)
2008	14,868,000	$	0.697
2009	8,568,000	$	0.746

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume		Associated NGL Volume		Average Crude Strike Price		Option Type
	(barrels)		(gallons)		(per barrel)
2008	600,000		40,068,000		$	60.00	Puts purchased
2008	(126,000	)	11,219,040		$	127.55	Puts sold(1)
2008	(126,000	)	(11,219,040	)	$	140.00	Calls purchased(1)
2008	946,800		51,529,968		$	80.13	Calls sold
2009	(304,200	)	27,085,968		$	126.05	Puts sold(1)
2009	(304,200	)	(27,085,968	)	$	143.00	Calls purchased(1)
2009	2,121,593		114,071,990		$	81.01	Calls sold
2010	3,127,500		202,370,490		$	81.09	Calls sold
2011	606,000		32,578,560		$	95.56	Calls sold
2012	450,000		24,192,000		$	97.10	Calls sold

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Natural Gas Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(2)	(per mmbtu) (2)
2008	2,742,000	$	8.823
2009	5,724,000	$	8.611
2010	4,560,000	$	8.526
2011	2,160,000	$	8.270
2012	1,560,000	$	8.250

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(2)	(per mmbtu)(2)
2008	2,742,000	$	(0.744	)
2009	5,724,000	$	(0.558	)
2010	4,560,000	$	(0.622	)
2011	2,160,000	$	(0.664	)
2012	1,560,000	$	(0.601	)

Natural Gas Purchases – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(2)	(per mmbtu)(2)
2008	8,130,000	$	9.001	(3)
2009	15,564,000	$	8.680
2010	8,940,000	$	8.580
2011	2,160,000	$	8.270
2012	1,560,000	$	8.250

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(2)	(per mmbtu)(2)
2008	8,130,000	$	(1.114	)
2009	15,564,000	$	(0.654	)
2010	8,940,000	$	(0.600	)
2011	2,160,000	$	(0.700	)
2012	1,560,000	$	(0.610	)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(barrels)	(per barrel)
2008	25,200	$	60.427
2009	33,000	$	62.700

14

Crude Oil Participating Swaps for NGLs

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Option Type
	(barrels)	(gallons)	(per barrel)
2008	126,000	11,219,040	$	137.00	Participating swaps

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Option Type
	(barrels)	(per barrel)
2008	10,800	$	60.000	Puts purchased
2008	138,000	$	78.055	Calls sold
2009	306,000	$	80.017	Calls sold
2010	234,000	$	83.027	Calls sold
2011	72,000	$	87.296	Calls sold
2012	48,000	$	83.944	Calls sold

⁽¹⁾ Puts sold and calls purchased in 2008 and 2009 represent collars entered into by the Partnership as offsetting positions for the calls sold related to ethane and propane production. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

⁽²⁾ Mmbtu represents million British Thermal Units.

⁽³⁾ Includes the Partnership’s premium received from its sale of an option for it to sell 468,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

15