PHILADELPHIA--(BUSINESS WIRE)--Atlas Pipeline Partners, L.P. (NYSE:APL - News) (“APL” or the “Partnership”) today reported financial results for the third quarter 2009.

Highlights from the third quarter 2009 and recent events include the following:

• Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), a non-GAAP measure, was $29.3 million in the third quarter 2009 compared to $80.7 million for the prior year comparable quarter. Adjusted EBITDA for the third quarter 2009 included approximately $19.0 million of realized losses from legacy derivative positions, partially offset by a realized cash gain on asset sales of approximately $1.5 million. A reconciliation of non-GAAP measures, including adjusted EBITDA and distributable cash flow, is provided within the financial tables of this release;
• Excluding the approximately $1.5 million gain on asset sales and the approximately $19.0 million of realized hedge losses in the third quarter 2009 discussed above, adjusted EBITDA would have been $46.8 million compared with adjusted EBITDA of $80.7 million for the prior year comparable quarter. The decrease between periods was primarily due to lower overall commodity prices combined with reduced earnings resulting from the sale of income-generating assets during the second quarter of 2009;
• Net loss was $12.3 million compared with net income of $201.2 million for the prior year third quarter. The decrease between periods was primarily due to mark to market gains on certain derivatives in the prior year period as a result of the decline in crude oil prices, as well as overall lower commodity prices in the current period; and
• The Partnership closed the sale of the Sweetwater II processing facility (“Sweetwater II”), a redundant natural gas processing facility, to Penn Virginia Resource Partners, LP. The property sold had been superseded by the Partnership’s new Nine Mile processing facility completed earlier this year and is likewise located in western Oklahoma. Total proceeds from the transaction of approximately $22.6 million were used to reduce indebtedness.

“We are pleased to report another quarter of solid performance,” said Eugene N. Dubay, chief executive officer of Atlas Pipeline Partners, L.P. “For the quarter, we received average natural gas liquids price of $0.75, up 12% versus our second quarter 2009 price of $0.67. Since the end of the quarter, our margins have further improved as the outlook for NGLs has strengthened on increasing economic fundamentals. While the past year has been challenging, we are making significant progress on our initiatives to maximize the capacity of our systems, and to improve our balance sheet for the benefit of all stakeholders. We are confident we can deliver on all these objectives.”

Midkiff Consolidator Plant

The Partnership and Pioneer Natural Resources Company (NYSE: PXD - News), which owns a 27.2% undivided interest, are in the process of upgrading the processing facilities on the Midkiff-Benedum system in the Permian Basin of western Texas. The Consolidator gas plant is being constructed at APL’s Midkiff location and is progressing on budget and on schedule for a mid-November 2009 startup. The Consolidator plant will extract an incremental 3,200 barrels per day (“bpd”) of natural gas liquids (“NGL”) (primarily ethane) from existing processed natural gas volumes and will also offer increased reliability, reduced emissions and additional operating efficiencies. The new cryogenic plant also provides an incremental 40 million cubic feet per day (“mmcf/d”) of processing capacity to pursue the numerous growth prospects in the Spraberry area and the ability to accommodate the robust 2010 drilling programs by producers in the Permian Basin of Western Texas.

Mid-Continent Segment Results

• The Velma system’s average natural gas processed volume was 78.7 Mmcfd for the third quarter 2009, an increase of approximately 29.2% compared with the prior year comparable quarter. This increase is primarily due to the expansion of the gathering system and connections made to new production through the recently installed Madill to Velma pipeline. Average NGL production also increased to 8,922 bpd, an increase of 35.3% compared to the prior year third quarter.
• The western Oklahoma systems, comprised of the Elk City/Sweetwater and Chaney Dell complexes, had average NGL production of 24,168 bpd and average natural gas processed volume was 402.7 Mmcfd for the third quarter 2009. System volumes were impacted by decreased drilling in western Oklahoma and producer well shut-ins because of lower natural gas prices.
• The Midkiff/Benedum system’s average natural gas processed volume was 152.3 Mmcfd for the third quarter 2009, an increase of approximately 11.5% compared with the prior year comparable quarter. Average gross NGL production volumes increased to 19,926 bpd, up 5.3% when compared to the prior year comparable quarter.

Appalachia Segment Results

• Gross margin for the Appalachia segment, including $1.4 million of equity income from its interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”) was $2.9 million for the third quarter 2009 compared with $10.1 million for the prior year comparable quarter. The decrease is due to APL’s contribution of the majority of the Appalachia system to Laurel Mountain, the joint venture established between the Partnership and The Williams Companies (NYSE: WMB - News), in which APL has a 49% ownership interest. Laurel Mountain generated $9.6 million in revenues and $2.4 million in net income during third quarter 2009.
• Gross throughput volume on the Appalachia system, including 100% of the volumes of Laurel Mountain, increased to 106.0 Mmcfd for the third quarter 2009, an increase of approximately 15.4% compared with the prior year third quarter, resulting from the connection of new wells to the Appalachia gathering system from drilling activity by APL’s affiliate, Atlas Energy Inc. (NASDAQ: ATLS - News).

Corporate and Other

• General and administrative expense, including amounts reimbursed to affiliates, was $8.8 million for the third quarter 2009 compared with income of $2.7 million for the prior year third quarter. The prior year third quarter included a $13.3 million gain related to a non-cash mark-to-market reduction in share-based compensation expense. Excluding this gain, general and administrative expense decreased $1.8 million compared to third quarter 2008.
• Depreciation and amortization increased to $21.9 million for the third quarter 2009 compared with $20.7 million for the prior year third quarter due primarily to expansion capital expenditures incurred subsequent to third quarter 2008, offset by the sale of certain assets in the second quarter 2009.
• Net of deferred financing costs, interest expense increased to $26.5 million for the third quarter 2009 as compared with $20.8 million for the comparable prior year period. This increase was primarily due to an increase in the interest rate on our revolver and senior secured term loans as a result of the amendment to our credit facility in May 2009, offset by a $183 million diminution in debt outstanding.
• At September 30, 2009, the Partnership had $1.243 billion of total debt which includes $433.5 million outstanding on its term loan that matures in 2014, $494.5 million of 8 1/8% and 8 7/8% senior unsecured notes that mature in 2015 and 2018, respectively, and $315.0 million of outstanding borrowings under its $380.0 million revolving credit facility that matures in 2013. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at September 30, 2009. Remaining available borrowings on the credit facility are $55.9 million.
• The credit facility contains customary covenants, including maintaining the following ratios as of the fiscal quarter ending September 30, 2009:
  
  
  • Maximum Leverage – 6.50x
  • Maximum Senior Secured Leverage – 3.75x
  • Minimum Interest Coverage – 2.50x
    
    The Partnership is in compliance with all of its covenants under the credit facility. As of September 30, 2009, the Partnership’s Leverage ratio was 4.2x, its Senior Secured Leverage ratio was 2.5x, and its Interest Coverage ratio was 3.3x.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s third quarter 2009 results on Wednesday, November 4, 2009 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 11:00 am ET on Wednesday, November 4, 2009. To access the replay, dial 1-888-286-8010 and enter conference code 60143730.

Atlas Pipeline Partners, L.P. is active in the gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, northern and western Texas and the Texas panhandle, APL owns and operates eight active gas processing plants and a treating facility, as well as approximately 8,750 miles of active intrastate gas gathering pipeline. In Appalachia, APL is a 49% joint venture partner with Williams in Laurel Mountain Midstream, LLC, which manages the natural gas gathering system in that region, namely from the Marcellus Shale in southwestern Pennsylvania. For more information, visit the Partnership’s website at www.atlaspipelinepartners.com or contact investorrelations@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 and 15,000 $1,000 par value 12% preferred limited partner units of Atlas Pipeline Partners, L.P.

Atlas Energy, Inc. is one of the largest independent natural gas producers in the Appalachian and Michigan Basins and a leading producer in the Marcellus Shale in southwestern Pennsylvania. Atlas Energy, Inc. is also the country’s largest sponsor and manager of tax-advantaged energy investment partnerships that finance the exploration and development of Atlas Energy, Inc.’s acreage. Atlas Energy, Inc. also owns 1.1 million common units in APL and a 64% interest in AHD. For more information, please visit our website at www.atlasamerica.com, or contact Investor Relations at InvestorRelations@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
(unaudited; in thousands)
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008(1)				2009(1)				2008(1)
Revenue:
Natural gas and liquids		$	194,440			$	396,739			$	526,478			$	1,186,688
Transportation, compression and other fees – affiliates			380				11,916				16,877				32,496
Transportation, compression and other fees – third parties			4,719				6,125				12,574				16,792
Equity income in joint venture			1,430				−				2,140				−
Gain on asset sales			1,499				−				111,440				−
Other income (loss), net			4,065				153,878				(6,431	)			(247,136	)
Total revenue and other loss, net			206,533				568,658				663,078				988,840
Costs and expenses:
Natural gas and liquids			144,990				314,315				409,411				937,852
Plant operating			14,762				16,652				42,713				46,418
Transportation and compression			134				2,883				6,256				7,842
General and administrative			8,379				(3,832	)			24,846				8,325
Compensation reimbursement – affiliates			375				1,175				1,125				3,694
Depreciation and amortization			21,896				20,741				67,563				61,200
Interest			28,320				22,098				75,820				62,663
Total costs and expenses			218,856				374,032				627,734				1,127,994
Income (loss) from continuing operations			(12,323	)			194,626				35,344				(139,154	)
Discontinued operations:
Gain on sale of discontinued operations			–				−				51,078				−
Income from discontinued operations			–				6,538				11,417				21,029
Income from discontinued operations			–				6,538				62,495				21,029
Net income (loss)			(12,323	)			201,164				97,839				(118,125	)
Income attributable to non-controlling interests			(954	)			(2,591	)			(2,075	)			(7,793	)
Preferred unit dividends			−				(650	)			(900	)			(1,437	)
Preferred unit imputed dividend cost			−				−				−				(505	)
Net income (loss) attributable to common limited partners and the general partner		$	(13,277	)		$	197,923			$	94,864			$	(127,860	)
See footnotes at the end of this earnings release.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary
(unaudited; in thousands, except per unit amounts)
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008(1)				2009(1)				2008(1)
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partner interest:
Continuing operations		$	(13,011	)		$	179,466			$	31,718			$	(168,897	)
Discontinued operations			–				6,406				61,239				20,606
			(13,011	)			185,872				92,957				(148,291	)
General partner interest:
Continuing operations			(266	)			11,919				651				20,008
Discontinued operations			–				132				1,256				423
			(266	)			12,051				1,907				20,431
Net income (loss) attributable to common limited partners and the general partner:
Continuing operations			(13,277	)			191,385				32,369				(148,889	)
Discontinued operations			–				6,538				62,495				21,029
		$	(13,277	)		$	197,923			$	94,864			$	(127,860	)
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations		$	(0.26	)		$	3.89			$	0.67			$	(4.07	)
Discontinued operations			–				0.14				1.29				0.50
		$	(0.26	)		$	4.03			$	1.96			$	(3.57	)
Diluted:
Continuing operations		$	(0.26	)		$	3.79			$	0.67			$	(4.07	)
Discontinued operations			–				0.14				1.29				0.50
		$	(0.26	)		$	3.93			$	1.96			$	(3.57	)
Weighted average common limited partner units outstanding:
Basic			49,127				45,937				47,554				41,360
Diluted			49,127				47,203				47,591				41,360
Capital expenditure data:
Maintenance capital expenditures		$	1,460			$	1,490			$	3,561			$	4,976
Expansion capital expenditures			5,656				80,224				134,049				218,792
Total		$	7,116			$	81,714			$	137,610			$	223,768
See footnotes at the end of this earnings release.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Consolidated Balance Sheets
(unaudited; in thousands)
ASSETS		September 30, 2009				December 31, 2008
Current assets:
Cash and cash equivalents		$	5,261			$	1,445
Accounts receivable − affiliates			–				537
Accounts receivable			71,118				100,000
Current portion of derivative asset			4,514				44,961
Prepaid expenses and other			15,304				10,996
Current assets of discontinued operations			−				13,441
Total current assets			96,197				171,380
Property, plant and equipment, net			1,698,226				1,781,011
Intangible assets, net			174,480				193,647
Investment in joint venture			133,740				−
Long-term portion of derivative asset			1,980				−
Other assets, net			34,938				24,993
Long-term assets of discontinued operations			−				242,165
		$	2,139,561			$	2,413,196
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable − affiliates		$	798			$	−
Accounts payable			19,706				66,571
Accrued liabilities			31,411				15,809
Current portion of derivative liability			41,019				60,396
Accrued producer liabilities			45,539				66,846
Current liabilities of discontinued operations			−				10,572
Total current liabilities			138,473				220,194
Long-term derivative liability			9,256				48,159
Long-term debt, less current portion			1,243,050				1,493,427
Other long-term liability			448				574
Commitments and contingencies
Partners’ capital:
Class A preferred limited partner’s interest			−				27,853
Class B preferred limited partner’s interest			14,955				10,007
Common limited partners’ interests			823,195				735,742
Investment in Class B cumulative preferred member units of Atlas Pipeline Holdings II, LLC (reported as treasury units)			(15,000	)			−
General partner’s interest			16,581				14,521
Accumulated other comprehensive loss			(61,142	)			(104,944	)
			778,589				683,179
Non-controlling interest			(30,255	)			(32,337	)
Total partners’ capital			748,334				650,842
		$	2,139,561			$	2,413,196
See footnotes at the end of this earnings release.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Segment Information
(in thousands)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008(1)				2009(1)				2008(1)
Mid-Continent
Revenue:
Natural gas and liquids		$	194,438			$	395,621			$	525,891			$	1,183,487
Transportation, compression and other fees			3,632				5,741				10,644				15,840
Gain on asset sale			2,493				–				2,493				–
Other income (loss), net			4,797				153,805				(5,838	)			(247,409	)
Total revenue and other loss, net			205,360				555,167				533,190				951,918
Costs and expenses:
Natural gas and liquids			145,001				313,763				409,152				936,313
Plant operating			14,762				16,652				42,713				46,418
General and administrative			6,028				(5,380	)			19,298				3,283
Depreciation and amortization			21,743				19,064				64,111				56,597
Total costs and expenses			187,534				344,099				535,274				1,042,611
Segment profit (loss)		$	17,826			$	211,068			$	(2,084	)		$	(90,693	)
Appalachia
Revenue:
Natural gas and liquids		$	2			$	1,118			$	587			$	3,201
Transportation, compression and other fees –affiliates			380				11,916				16,877				32,496
Transportation, compression and other fees – third parties			1,087				384				1,930				952
Equity income in joint venture			1,430				–				2,140				–
Gain on asset sale			(994	)			–				108,947				–
Other income, net			91				73				230				273
Total revenue and other income, net			1,996				13,491				130,711				36,922
Costs and expenses:
Natural gas and liquids			(11	)			552				259				1,539
Transportation and compression			134				2,883				6,256				7,842
General and administrative			1,363				1,361				3,337				4,368
Depreciation and amortization			153				1,677				3,452				4,603
Total costs and expenses			1,639				6,473				13,304				18,352
Segment profit		$	357			$	7,018			$	117,407			$	18,570
Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent		$	17,826			$	211,068			$	(2,084	)		$	(90,693	)
Appalachia			357				7,018				117,407				18,570
Total segment income (loss)			18,183				218,086				115,323				(72,123	)
Corporate general and administrative expenses			(1,363	)			(1,362	)			(3,336	)			(4,368	)
Other loss, net			(823	)			–				(823	)			–
Interest expense			(28,320	)			(22,098	)			(75,820	)			(62,663	)
Income (loss) from continuing operations			(12,323	)			194,626				35,344				(139,154	)
Income from discontinued operations			–				6,538				62,495				21,029
Net income (loss)		$	(12,323	)		$	201,164			$	97,839			$	(118,125	)
See footnotes at the end of this earnings release.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
(unaudited; in thousands)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008(1)				2009				2008(1)
Reconciliation of net income (loss) to other non-GAAP measures(2):
Net income (loss)		$	(12,323	)		$	201,164			$	97,839			$	(118,125	)
Income attributable to non-controlling interests			(954	)			(2,591	)			(2,075	)			(7,793	)
Depreciation and amortization			21,896				20,741				67,563				61,200
Interest expense			28,320				22,098				75,820				62,663
NOARK depreciation and amortization (included within income from discontinued operations)			–				1,809				2,773				5,409
NOARK asset impairment (included within income from discontinued operations)			−				–				−				7,962
NOARK interest expense (income) (included within income from discontinued operations)			–				(252	)			29				(1,051	)
EBITDA			36,939				242,969				241,949				10,265
Non-cash derivative expense			(6,709	)			(221,984	)			39,806				36,019
Early termination cash derivative expense(3)			−				71,516				5,000				187,641
Non-recurring crude oil to natural gas liquids price correlation impact(4)			−				–				−				10,653
Non-cash portion of gain on asset sale(5)			–				−				(79,733	)			−
Non-cash linefill (gain) loss(6)			(1,122	)			913				(3,338	)			(1,443	)
Non-cash compensation expense (income)			238				(12,673	)			497				(14,273	)
Adjusted EBITDA			29,346				80,741				204,181				228,862
Interest expense			(28,320	)			(22,098	)			(75,820	)			(62,663	)
NOARK interest income (expense) (included within income from discontinued operations)			–				252				(29	)			1,051
Amortization of deferred financing costs			1,796				1,042				6,449				3,650
Preferred unit dividends			−				(650	)			(900	)			(1,437	)
Maintenance capital expenditures			(1,459	)			(1,490	)			(3,560	)			(4,976	)
NOARK maintenance capital expenditures (included within discontinued operations)			–				(221	)			(454	)			(399	)
Distributable cash flow		$	1,363			$	57,576			$	129,867			$	164,088

		(1)		Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system.
		(2)		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 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. 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.
		(3)		During the three months ended March 31, 2009, the Partnership made net payments of $5.0 million related to the early termination of derivative contracts for second quarter 2009 production periods. These payments were funded through the Partnership’s March 2009 issuance of 5,000 12.0% convertible preferred units of limited partner interests to Atlas Pipeline Holdings, L.P. (NYSE: AHD - News), the owner of the Partnership’s general partner, for cash consideration of $1,000 per preferred unit. The Partnership had previously entered into an amendment to its credit facility to revise the definition of Consolidated EBITDA to allow for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of equity.
		(4)		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 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 the 2nd quarter 2008 through the 4th quarter of 2009 for an aggregate net cost of $274.0 million. 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.
		(5)		Represents the portion of the gain on sale recognized upon the sale of the Partnership’s Appalachia gathering system related to the $25.5 million note receivable from which the Partnership has preferential rights to the net proceeds and the portion of the gain attributed to the increase of the Partnership’s investment in the Laurel Mountain joint venture to fair value.
		(6)		Includes the non-cash impact of commodity price movements on pipeline linefill inventory.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Operating Highlights
		Three Months Ended September 30,				Nine Months Ended September 30,
		2009		2008		2009		2008
Mid-Continent – Velma System(1)
Natural Gas
Gross natural gas gathered – mcfd		81,562		64,386		75,919		64,103
Gross natural gas processed – mcfd		78,714		60,902		73,351		60,972
Gross residue natural gas – mcfd		62,219		48,300		57,959		48,158
Natural Gas Liquids
Gross NGL sales – bpd		8,922		6,595		8,158		6,758
Condensate
Gross condensate sales – bpd		389		308		383		286
Mid-Continent – Elk City/Sweetwater System(1)
Natural Gas
Gross natural gas gathered – mcfd		211,287		279,145		228,630		292,307
Gross natural gas processed – mcfd		200,182		243,409		223,438		236,520
Gross residue natural gas – mcfd		181,011		219,945		203,034		213,668
Natural Gas Liquids
Gross NGL sales – bpd		10,792		11,486		11,361		10,874
Condensate
Gross condensate sales – bpd		260		251		374		299
Mid-Continent – Chaney Dell System(1)
Natural Gas
Gross natural gas gathered – mcfd		268,723		300,467		282,756		278,906
Gross natural gas processed – mcfd		202,516		234,529		216,407		246,365
Gross residue natural gas – mcfd		218,420		250,994		238,167		238,264
Natural Gas Liquids
Gross NGL sales – bpd		13,376		14,128		13,574		13,299
Condensate
Gross condensate sales – bpd		750		759		861		774
Mid-Continent – Midkiff/Benedum System(1)
Natural Gas
Gross natural gas gathered – mcfd		166,423		143,224		160,631		145,300
Gross natural gas processed – mcfd		152,314		136,656		149,516		138,178
Gross residue natural gas – mcfd		104,895		84,372		103,078		92,352
Natural Gas Liquids
Gross NGL sales – bpd		19,926		18,920		21,006		20,029
Condensate
Gross condensate sales – bpd		1,942		1,573		1,426		1,288
Appalachia(1)
Average throughput volume – mcfd(2)		105,989		91,829		104,009		84,007

(1)		“Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.
(2)		Effective May 31, 2009, this amount represents 100% of the throughput volume of Laurel Mountain, a joint venture in which the Partnership has a 49% ownership interest, for the period from May 31, 2009, the date of inception, through September 30, 2009 and the throughput volume of its Tennessee gathering system.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Hedge Positions through 2010

(as of November 3, 2009)

Note: The natural gas, natural gas liquid and condensate hedge positions shown below represent the hedge contracts in place through December 31, 2010. APL’s hedge position in its entirety, including any hedges for periods after December 31, 2010, will be disclosed in the Partnership’s Form 10-Q.

INTEREST RATE HEDGES
Swap Contracts
					Notional
	Term				Amount				Type
	January 2008-
	January 2010				$200,000,000				Pay 2.88% —Receive LIBOR
	April 2008-
	April 2010				$250,000,000				Pay 3.14% —Receive LIBOR

NATURAL GAS HEDGES
Natural Gas Sales - Fixed Price Swaps
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (MMBTU)¹		120,000		–		–		–		–
	Average Fixed Price		$8.000		–		–		–		–
Natural Gas Basis Sales
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (MMBTU)¹		1,230,000		1,110,000		1,110,000		–		–
	Average Fixed Price		$(0.558)		$(0.575)		$(0.575)		–		–
Natural Gas Purchases - Fixed Price Swaps
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (MMBTU)¹		2,580,000		2,190,000		2,190,000		–		–
	Average Fixed Price		$8.687		$8.635		$8.635		–		–
Natural Gas Basis Purchases
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (MMBTU)¹		3,690,000		3,300,000		3,300,000		–		–
	Average Fixed Price		$(0.659)		$(0.560)		$(0.560)		–		–
NATURAL GAS LIQUID (NGLs) HEDGES
NGLs Sales - Fixed Price Swaps
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		5,544,000		–		–		–		–
	Average Fixed Price		$0.754		–		–		–		–
Ethane Put Options Purchased
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		630,000		–		–		–		–
	Average Price(2)		$0.340		–		–		–		–
Propane Put Options Purchased
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		15,246,000		18,270,000		–		–		–
	Average Price(2)		$0.820		$0.845		–		–		–
Isobutane Put Options Purchased
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		126,000		–		–		–		–
	Average Price(2)		$0.589		–		–		–		–
Normal Butane Put Options Purchased
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		3,654,000		3,654,000		–		–		–
	Average Price(2)		$0.943		$1.038		–		–		–
Natural Gasoline Put Options Purchased
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (gallons)		3,906,000		3,906,000		–		–		–
	Average Price(2)		$1.341		$1.345		–		–		–
Crude Oil Put Options Purchased (associated with NGLs, normal butane, isobutane and natural gasoline)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		165,000		172,500		181,500		66,000		66,000
	Average Price(2)		$63.53		$61.20		$63.05		$58.81		$58.81
Crude Oil Call Options Sold (associated with NGLs)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		527,700		1,314,750		1,314,750		249,000		249,000
	Average Price(2)		$84.80		$82.81		$82.89		$103.85		$103.85
Crude Oil Call Options Purchased (associated with NGLs) (3)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		-		270,000		270,000		87,000		87,000
	Average Price(2)		-		$131.93		$131.93		$132.93		$132.93
CONDENSATE HEDGES
Crude Oil Sales (associated with condensate)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		6,000		–		–		–		–
	Average Price(2)		$62.70		–		–		–		–
Crude Oil Put Options Purchased (associated with condensate)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		117,000		121,500		121,500		84,000		84,000
	Average Price(2)		$64.15		$64.30		$65.57		$63.79		$65.09
Crude Oil Call Options Sold (associated with condensate)
			4Q 2009		1Q 2010		2Q 2010		3Q 2010		4Q 2010
	Volumes (barrels)		76,500		85,500		85,500		31,500		31,500
	Average Price(2)		$84.96		$83.92		$83.96		$99.33		$99.35

(1)		MMBTU represents million British Thermal Units
(2)		Average price for options is based upon average strike price adjusted by the premium paid or received.
(3)		Calls were purchased for 2010 to offset positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

Atlas Pipeline Partners, L.P.
Brian J. Begley
Vice President, Investor Relations
215-546-5005
215-553-8455 (fax)