Atlas Pipeline Partners 8-K Results of Operations and Financial Condition

Exhibit 99.1

ATLAS PIPELINE PARTNERS, L.P.

REPORTS RECORD ADJUSTED EBITDA OF $66.4 MILLION FOR THE

THIRD QUARTER 2007

Philadelphia, PA, November 1, 2007 – Atlas Pipeline Partners, L.P. (NYSE: APL) (the “Partnership”)today reported record adjusted earnings before interest, income taxes, depreciation and amortization (“EBITDA”), a non-GAAP (generally accepted accounting principles) measure, of $66.4 million for the third quarter 2007 compared with $20.6 million for the prior year third quarter. Distributable cash flow totaled $45.7 million for the third quarter 2007 compared to distributable cash flow of $14.6 million for the comparable prior year quarter. The Partnership’s distribution coverage ratio for the third quarter 2007 was approximately 1.2x. 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, and higher volumes on its other systems. System-wide volumes were approximately 1.2 billion cubic feet per day (“bcfd”) for the third quarter 2007 compared with 0.6 bcfd for the prior year comparable quarter, an increase of approximately 83%. Increased throughput volume on the NOARK interstate pipeline system (“NOARK”) and an increase in Appalachia gathered natural gas also contributed to the aggregate growth in system volumes. On a GAAP basis, the Partnership recognized a net loss of $24.5 million for the third quarter 2007, largely related to one-time, non-cash charges totaling $45.2 million, primarily related to non-cash compensation expense, non-cash derivative expense and accelerated amortization of deferred financing costs. The non-cash compensation expense resulted from incentive compensation agreements with certain key employees located in our Mid-Continent headquarters in Tulsa, OK. These awards are based upon the accomplishment of certain predetermined performance targets through December 2008 related to various acquisitions, including the acquisition of the Chaney Dell and Midkiff/Benedum systems. The compensation expense amount recorded for these common unit awards reflects management’s current estimate with regard to the achievement of the predetermined performance targets. The accelerated amortization of deferred finance costs was associated with the Partnership’s replacement of its credit facility in July 2007 with a new $300.0 million revolving credit facility in connection with its acquisition of the Chaney Dell and Midkiff/Benedum systems.

On July 27, 2007, for a payment of approximately $1.9 billion, the Partnership acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, and the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems. In connection with this acquisition, the Partnership reached an agreement with Pioneer Natural Resources Company (NYSE: PXD – “Pioneer”), which held a right of first refusal to purchase the Midkiff/Benedum system. Pioneer provides approximately 50% of the natural gas processed by the Midkiff/Benedum system under its obligation to connect its wells within a certain distance of the Midkiff/Benedum system. Under this new agreement, Pioneer waived its right of first refusal and extended its obligation to the Midkiff/Benedum system an additional 10 years through 2022. The Partnership granted to Pioneer, which currently holds a 27.2% interest in the Midkiff/Benedum system, an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system one year after the closing of the Partnership’s acquisition of Anadarko’s interest, and up to an additional 7.5% interest two years after the closing of the Partnership’s acquisition of Anadarko’s interest. If the options are fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. The Partnership will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

The Partnership funded the purchase price of the acquisition in part from a private placement of 25.6 million common limited partner units, generating gross proceeds of $1.125 billion. Atlas Pipeline Holdings, L.P. (NYSE: AHD) (“Atlas Holdings”), the parent of the Partnership’s general partner, purchased 3.8 million of the 25.6 million common limited partner units issued by the Partnership. The Partnership funded the remaining purchase price with an $830.0 million senior secured term loan which matures in July 2014 and a partial advance against a new $300.0 million senior secured revolving credit facility which matures in July 2013. Atlas Holdings, which owns all of the incentive distribution rights in the Partnership, has agreed to allocate a portion of its future incentive distribution rights back to the Partnership in connection with the Anadarko acquisition, namely up to $5.0 million of incentive distribution rights per quarter to the Partnership through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

The Partnership declared a record quarterly cash distribution for the third quarter 2007 of $0.91 per common limited partner unit on October 23, 2007, an increase of $0.06 per unit or 7.1% from the comparable prior year period. The third quarter 2007 distribution will be paid on November 14, 2007 to all unitholders of record as of November 7, 2007. Total distributions declared for the third quarter 2007 of $39.7 million represent a 162% increase from the prior year comparable quarter. The Partnership established distribution guidance at a range of $1.78 to $1.85 per common limited partner unit for the second half of 2007 and $3.80 to $4.00 per common limited partner unit for 2008, while also trending the targeted distribution coverage ratio towards 1.2x.

“The record results this quarter are truly gratifying, but I’m extremely hopeful that in this case the past is only prologue,” stated Edward E. Cohen, Chairman and Chief Executive Officer of Atlas Pipeline. “When we next report, we will have the advantage of a full quarter incorporating our new acquisition and the further advantage, we expect, of a full integration of these operations into our system.”

Segment Analysis

Mid-Continent

Excluding the effect of an $11.5 million derivative expense, the Mid-Continent segment recognized total revenue of $244.6 million for the third quarter 2007, an increase of $134.9 million from the prior year comparable quarter. This increase principally reflects the contribution from the acquisition of the Chaney Dell and Midkiff Benedum systems of $135.0 million and higher system volumes. Average gross natural gas processed volume from July 27, 2007, the date of acquisition, through September 30, 2007 was 250.0 MMcfd for the Chaney Dell system and 106.6 MMcfd for the Midkiff/Benedum system. There were 81 new wells connected to the Chaney Dell system during the third quarter 2007 and there were 59 new wells connected to the Midkiff/Benedum system for the same period. For the Elk City/Sweetwater system, average gross natural gas processed volume for the third quarter 2007 was 231.2 MMcfd, a 69.8% increase from the third quarter 2006. The Partnership connected 18 new wells to the Elk City/Sweetwater system during the third quarter 2007 compared with 13 new wells for the prior year comparable quarter. For the NOARK system, average Ozark Gas Transmission throughput volume was 325.7 MMcfd during the third quarter 2007, a 43.5% increase from the third quarter 2006. The Velma system’s average processed natural gas volume of 62.0 MMcfd for the third quarter 2007 represented a 6.3% increase over the prior year comparable quarter. The Partnership connected 13 new wells to its Velma system during the third quarter 2007.

Appalachia

Total revenue for the Appalachia system was $9.1 million for the third quarter 2007 compared with $7.1 million for the third quarter 2006, an increase of $2.0 million due principally to higher throughput volume and higher realized transportation rates. Throughput volume increased to 71.9 MMcfd for the third quarter 2007 compared with 63.9 MMcfd for the third quarter 2006 resulting from the connection of new wells to the Appalachia gathering system. The Appalachia system’s average transportation rate per thousand cubic feet (“mcf”) was $1.32 for the third quarter 2007, a 10.9% increase from $1.19 per mcf for the prior year third quarter. During the third quarter 2007, 189 new wells were connected to the Appalachia gathering system compared with 149 new wells for the prior year comparable quarter, representing a 27% increase. Additionally, 252 wells were added to the Appalachia system during the third quarter 2007 due to the acquisition of a natural gas gathering and processing system in August 2007, which has a processing capacity of 10.0 MMcfd and was acquired for $6.1 million.

Corporate and Other

General and administrative expense, including amounts reimbursed to affiliates, increased $32.4 million to $37.8 million for the third quarter 2007 from $5.4 million for the third quarter 2006. This increase was primarily related to a $30.2 million increase in non-cash compensation expense arising from vesting of phantom and common unit awards and higher costs associated with managing our operations. Certain common unit awards of the Partnership are based upon the accomplishment of certain predetermined performance targets for consummated acquisitions, including the acquisition of the Chaney Dell and Midkiff/Benedum systems, through December 2008. The amount recorded for these common unit awards reflect management’s current estimate with regard to the achievement of the predetermined performance targets. Depreciation and amortization increased $10.0 million to $16.2 million for the third quarter 2007 due primarily to the depreciation associated with the Chaney Dell and Midkiff/Benedum assets acquired by the Partnership in July 2007 and the Partnership’s expansion capital expenditures incurred subsequent to the third quarter 2006, including the Sweetwater processing facility.

Interest expense increased to $24.0 million for the third quarter 2007, an increase of $18.3 million from the prior year third quarter. This increase was primarily related to interest associated with the Partnership’s $830.0 million term loan, which was issued in July 2007 and partially funded its acquisition of the Chaney Dell and Midkiff/Benedum systems, additional borrowings under its credit facility to finance its expansion capital expenditures, and $5.0 million of accelerated amortization of deferred finance costs associated with the Partnership’s replacement of its credit facility in July 2007 with a new $300.0 million revolving credit facility. At September 30, 2007, the Partnership had $1,158.0 million of total debt, including an $830.0 million term loan that matures in 2014, $294.4 million of senior unsecured notes that mature in 2015 and $33.5 million of outstanding borrowings under its $300.0 million credit facility.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s third quarter 2007 results on Friday, November 2, 2007 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, November 2, 2007. To access the replay, dial 1-888-286-8010 and enter conference code 46464454.

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, northern and western Texas and the Texas panhandle, the Partnership owns and operates eight 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 and eastern Ohio. 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 5.5 million common units of Atlas Pipeline Partners.

Atlas Energy Resources, LLCis an energy concern focused on the development and production of natural gas and, to a lesser extent, oil principally in the eastern United States. Atlas Energy sponsors and manages tax advantaged investment partnerships, in which it co-invests, to finance the exploration and development of its acreage in the Appalachian Basin and drills on its own account in the Antrim Shale of Michigan. For more information, visit Atlas Energy’s website atwww.atlasenergyresources.com or contact investor relations at bbegley@atlasamerica.com.

Atlas America, Inc. owns an approximate 64% limited partner interest in Atlas Pipeline Holdings, L.P. and an approximate 49% common unit interest and all of the Class A and management incentive interests in Atlas Energy Resources, LLC (NYSE: ATN). For more information, please visit our 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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary

(in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
STATEMENTS OF OPERATIONS
Revenue:
Natural gas and liquids	$	229,891		$	99,997		$	436,859		$	296,083
Transportation, compression, and other fees – affiliates		8,495			6,951			24,673			22,659
Transportation, compression, and other fees – third parties		12,948			6,726			33,374			20,882
Other income (loss)		(9,034	)		6,872			(39,654	)		8,233
Total revenue and other income (loss)		242,300			120,546			455,252			347,857
Costs and expenses:
Natural gas and liquids		174,727			89,679			349,639			252,577
Plant operating		9,108			3,853			18,153			11,006
Transportation and compression		3,555			2,714			9,877			7,639
General and administrative		36,424			5,069			48,735			13,465
Compensation reimbursement – affiliates		1,392			378			2,820			1,983
Depreciation and amortization		16,176			6,152			29,381			16,685
Interest		24,040			5,700			38,126			18,191
Minority interest		1,376			—			1,376			118
Total costs and expenses		266,798			113,545			498,107			321,664
Net income (loss)		(24,498	)		7,001			(42,855	)		26,193
Preferred unit dividend effect		—			—			(3,756	)		—
Preferred unit imputed dividend cost		(624	)		(627	)		(1,858	)		(1,262	)
Net income (loss) attributable to common limited partners and the general partner	$	(25,122	)	$	6,374		$	(48,469	)	$	24,931
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(28,242	)	$	2,567		$	(58,854	)	$	13,664
General partner’s interest		3,120			3,807			10,385			11,267
Net income (loss) attributable to common limited partners and the general partner	$	(25,122	)	$	6,374		$	(48,469	)	$	24,931
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.90	)	$	0.20		$	(3.05	)	$	1.07
Diluted	$	(0.90	)	$	0.19		$	(3.05	)	$	1.05
Weighted average common limited partner units outstanding:
Basic		31,449			13,076			19,270			12,818
Diluted		31,449			13,248			19,270			12,975
Capital expenditure data:
Maintenance capital expenditures	$	2,328		$	843		$	3,800		$	2,921
Expansion capital expenditures		47,937			25,088			89,860			58,822
Total	$	50,265		$	25,931		$	93,660		$	61,743

	September 30, 2007		December 31, 2006
Balance Sheet Data (at period end):
Cash and cash equivalents	$	24,808	$	1,795
Total assets		2,807,871		786,884
Total debt		1,157,963		324,083
Total partners’ capital		1,422,482		379,134

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Segment Information

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Mid-Continent
Revenue:
Natural gas and liquids	$	229,511		$	99,997		$	436,479		$	296,083
Transportation, compression, and other fees		12,793			6,707			33,183			20,817
Other income (loss)		(9,133	)		6,754			(39,918	)		7,709
Total revenue and other income (loss)		233,171			113,458			429,744			324,609
Costs and expenses:
Natural gas and liquids		174,471			89,679			349,383			252,577
Plant operating		9,108			3,853			18,153			11,006
Transportation and compression		1,943			1,389			5,443			4,029
General and administrative		34,806			3,590			43,506			9,753
Depreciation and amortization		14,992			5,200			26,007			14,034
Minority interest		1,376			—			1,376			118
Total costs and expenses		236,696			103,711			443,868			291,517
Segment profit (loss)	$	(3,525	)	$	9,747		$	(14,124	)	$	33,092
Appalachia
Revenue:
Natural gas and liquids	$	380		$	—		$	380		$	—
Transportation, compression, and other fees – affiliates		8,494			6,951			24,673			22,659
Transportation, compression, and other fees – third parties		156			19			191			65
Other income		99			118			264			524
Total revenue and other income		9,129			7,088			25,508			23,248
Costs and expenses:
Natural gas and liquids		256			—			256			—
Transportation and compression		1,612			1,325			4,434			3,610
General and administrative		1,505			929			4,025			2,848
Depreciation and amortization		1,184			952			3,374			2,651
Total costs and expenses		4,557			3,206			12,089			9,109
Segment profit	$	4,572		$	3,882		$	13,419		$	14,139
Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent	$	(3,525	)	$	9,747		$	(14,124	)	$	33,092
Appalachia		4,572			3,882			13,419			14,139
Total segment profit (loss)		1,047			13,629			(705	)		47,231
Corporate general and administrative expense		(1,505	)		(928	)		(4,024	)		(2,847	)
Interest expense		(24,040	)		(5,700	)		(38,126	)		(18,191	)
Net income (loss)	$	(24,498	)	$	7,001		$	(42,855	)	$	26,193

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARES

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Reconciliation of net income (loss) to adjusted net income (loss):
Net income (loss)	$	(24,498	)	$	7,001		$	(42,855	)	$	26,193
Effect of prior period items(1)		—			—			—			1,090
Effect of certain items(2)		—			1,971			—			(1,596	)
Adjusted net income (loss)	$	(24,498	)	$	8,972		$	(42,855	)	$	25,687
Reconciliation of net income (loss) to non-GAAP measures(3):
Net income (loss)	$	(24,498	)	$	7,001		$	(42,855	)	$	26,193
Depreciation and amortization		16,176			6,152			29,381			16,685
Interest expense		24,040			5,700			38,126			18,191
EBITDA		15,718			18,853			24,652			61,069
Non-cash derivative expense (income)		8,430			(1,851	)		39,256			(2,107	)
Non-cash compensation expense		31,834			1,623			36,110			4,125
Unrecognized economic impact of Anadarko acquisition(4)		10,423			—			10,423			—
Effect of prior period items(1)		—			—			—			1,090
Effect of certain items(2)		—			1,971			—			(1,596	)
Adjusted EBITDA		66,405			20,596			110,441			62,581
Interest expense		(24,040	)		(5,700	)		(38,126	)		(18,191	)
Minority interest share of interest expense		—			—			—			938
Amortization of deferred financing costs (included within interest expense)		5,622			548			6,690			1,753
Maintenance capital expenditures		(2,328	)		(843	)		(3,800	)		(2,921	)
Distributable cash flow	$	45,659		$	14,601		$	75,205		$	44,160

⁽¹⁾ During June 2006, the Partnership identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which related to natural gas volume gathered during the third and fourth quarters of 2005 and first quarter of 2006, the Partnership recorded an adjustment of $1.2 million during the second quarter of 2006 to increase natural gas and liquids cost of goods sold. If the $1.2 million adjustment had been recorded when the inaccuracies arose, reported net income would have been reduced by approximately 2.7%, 8.3%, and 1.4% for the third quarter of 2005, fourth quarter of 2005, and first quarter of 2006, respectively. Management of the Partnership believes that the impact of these adjustments is immaterial to its current and prior financial statements.

⁽²⁾ Includes the addback of $3.6 million of unfavorable revisions to previously estimated producer volumes, $0.8 million of estimated unrecoverable costs and loss of revenue as a result of the temporary outage at a Velma compressor station due to fire damage sustained, and $0.4 million of lower condensate revenue due to evaporation caused by unusually warm temperatures in the areas where the Partnership operates. These amounts are partially offset by a $2.7 million gain on sale of certain gathering pipelines in the Velma system.

⁽³⁾ 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 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 is also a financial measurement that, with certain negotiated adjustments, is utilized within the Partnership’s financial covenants under its credit facility. 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.

⁽⁴⁾ The acquisition of the Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisitions' effective date was July 1, 2007. As such, the Partnership receives the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with accounting regulations, the Partnership has only recorded the results of the acquired assets commencing on the closing date of the acquisition.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARES

Operating Highlights

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Mid-Continent – Velma System
Natural Gas
Gross natural gas gathered – mcfd(1)		63,757		62,113		62,531		61,641
Gross natural gas processed – mcfd(1)		61,968		58,296		60,555		58,881
Gross residue natural gas – mcfd(1)		49,502		45,724		47,487		46,042
Natural Gas Liquids
Gross NGL sales – bpd(1)		6,215		6,598		6,386		6,536
Condensate
Gross condensate sales – bpd(1)		254		205		222		209
Mid-Continent – Elk City/Sweetwater System
Natural Gas
Gross natural gas gathered – mcfd(1)		299,450		284,461		298,724		270,957
Gross natural gas processed – mcfd(1)		231,152		136,101		224,521		134,169
Gross residue natural gas – mcfd(1)		211,368		123,275		206,011		121,661
Natural Gas Liquids
Gross NGL sales – bpd(1)		9,782		6,049		9,351		6,016
Condensate
Gross condensate sales – bpd(1)		143		59		228		125
Mid-Continent – Chaney Dell System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)		255,649		—		255,649		—
Gross natural gas processed – mcfd(1)		249,982		—		249,982		—
Gross residue natural gas – mcfd(1)		222,508		—		222,508		—
Natural Gas Liquids
Gross NGL sales – bpd(1)		12,678		—		12,678		—
Condensate
Gross condensate sales – bpd(1)		564		—		564		—
Mid-Continent – Midkiff/Benedum System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)		150,061		—		150,061		—
Gross natural gas processed – mcfd(1)		106,601		—		106,601		—
Gross residue natural gas – mcfd(1)		93,859		—		93,859		—
Natural Gas Liquids
Gross NGL sales – bpd(1)		20,702		—		20,702		—
Condensate
Gross condensate sales – bpd(1)		1,754		—		1,754		—
Mid-Continent – NOARK system
Ozark Gas Transmission throughput – mcfd(1)		325,652		226,962		311,562		236,331
Appalachia
Throughput – mcfd(1)		71,876		63,909		66,888		61,473
Average transportation rate per mcf(1)	$	1.32	$	1.19	$	1.36	$	1.35

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

⁽²⁾ Volumetric data for the Chaney Dell System and Midkiff/Benedum system for the three and nine months ended September 30, 2007 represents volumes recorded for the 66-day period from July 27, 2007, the date of acquisition, through September 30, 2007.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Mid-Continent Segment Hedge Positions

(as of November 1, 2007)

Natural Gas Liquids Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(gallons)	(per gallon)
2007	42,651,000	$	0.893
2008	61,362,000		0.706
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)
2007	390,000	25,789,680	$	60.00	Puts purchased
2007	390,000	25,789,680		75.15	Calls sold
2008	3,744,600	249,257,484		60.00	Puts purchased
2008	3,744,600	249,257,484		79.38	Calls sold
2009	4,752,000	324,233,280		60.00	Puts purchased
2009	4,752,000	324,233,280		78.68	Calls sold
2010	2,413,500	169,282,890		60.00	Puts purchased
2010	2,413,500	169,282,890		77.28	Calls sold

Natural Gas Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(1)	(per mmbtu)(1)
2007	1,449,000	$	8.197
2008	5,484,000		8.795
2009	5,724,000		8.611
2009	2,820,000		8.635

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(1)	(per mmbtu)(1)
2007	1,449,000	$	(0.729	)
2008	5,484,000		(0.727	)
2009	5,724,000		(0.513	)
2010	2,820,000		(0.572	)

Natural Gas Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(1)	(per mmbtu)(1)
2007	3,909,000	$	8.633	(2)
2008	16,260,000		8.923	(3)
2009	15,564,000		8.680
2010	7,200,000		8.635

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Mid-Continent Segment Hedge Positions

(as of November 1, 2007)

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price
	(mmbtu)(1)	(per mmbtu)(1)
2007	3,909,000	$	(1.048	)
2008	15,276,000		(1.186	)
2009	14,820,000		(0.686	)
2010	7,200,000		(0.560	)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(barrels)	(per barrel)
2007	17,600	$	56.477
2008	65,400		59.424
2009	33,000		62.700

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price	Option Type
	(barrels)	(per barrel)
2007	189,300	60.000	Puts purchased
2007	189,300	75.363	Calls sold
2008	691,800	60.000	Puts purchased
2008	691,800	78.004	Calls sold
2009	738,000	60.000	Puts purchased
2009	738,000	80.622	Calls sold
2010	402,000	60.000	Puts purchased
2010	402,000	79.341	Calls sold
2011	30,000	60.000	Puts purchased
2011	30,000	74.500	Calls sold
2012	30,000	60.000	Puts purchased
2012	30,000	73.900	Calls sold

⁽¹⁾ Mmbtu represents million British Thermal Units.

⁽²⁾ Includes the Partnership’s premium received from its sale of an option for it to sell 1,200,000 mmbtu of natural gas at an average price of $17.00 per mmbtu for the year ended December 31, 2007.

⁽³⁾ Includes the Partnership’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.