Atlas Pipeline Partners, L.P. Reports Third Quarter 2008 Results

PHILADELPHIA--(BUSINESS WIRE)--Atlas Pipeline Partners, L.P. (NYSE:APL) (“APL” or the “Partnership”) today reported financial results for the third quarter 2008.

The results of the third quarter 2008 include:

• Adjusted EBITDA⁽¹⁾, a non-GAAP measure, of $79.8 million, representing an increase of $13.4 million or 20% when compared with $66.4 million for the prior year third quarter. The quarter-over-quarter results were favorably impacted by higher aggregate processing and natural gas liquids (“NGL”) volumes on its systems and higher commodity 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 $56.7 million, an increase of $11.0 million or 24%, when compared to the prior year third quarter. The Partnership declared a quarterly cash distribution for the third quarter 2008 of $0.96 per common limited partner unit. This distribution represented an increase of $0.05 per unit, or 5%, when compared to the prior year third quarter. The Partnership’s distribution coverage ratio for the third quarter 2008 was 1.1x;
• Adjusted net income, a non-GAAP measure, of $35.4 million for the third quarter 2008, an increase of $9.2 million or 35%, when compared to the prior year third quarter. Due to the non-cash and non-recurring derivative gains and losses recognized in the current quarter as described below, on a GAAP basis the Partnership recognized net income of $198.6 million for the third quarter 2008 compared with a net loss of $24.5 million for the prior year third quarter;
• System-wide volumes of 1,324.8 million cubic feet per day (“MMcfd”) for the third quarter 2008 compared to volumes of approximately 1,166.4 MMcfd for the prior year third quarter, an increase of approximately 13.6%;

The Partnership’s financial results for the third quarter 2008 include a $71.5 million cash derivative expense resulting from the completion of the early termination of approximately 85% of its 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. The Partnership funded this transaction through its June 24, 2008 sale of 7,140,000 common units for aggregate net proceeds of approximately $262.1 million, including a capital contribution of approximately $5.4 million from its general partner to maintain its aggregate 2% general partner interest in the Partnership. 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 $71.5 million cash derivative expense recognized during the third quarter 2008 resulted from July 2008 net payments of $93.6 million to terminate the remaining portion of these derivative contracts. The attached hedge schedule reflects the current hedge position of the Partnership, adjusted for the crude oil derivative contracts that were terminated in June and July 2008. 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.

APL further announces that it is evaluating the potential combination of the Partnership and Atlas Pipeline Holdings, L.P., which owns our General Partner, and other potential strategic alternatives for the Partnership. APL is exploring deleveraging through the sale of all or portions of individual pipeline and/or processing assets. UBS Investment Bank has been engaged as an independent financial advisor to assist in the review of these and other strategic alternatives. Furthermore, the company is currently in discussions internally and with its affiliates. The Partnership provides no assurance that the evaluation of these options will result in any specific transaction.

Mid-Continent Segment Results

• Mid-Continent segment total revenue increased $176.6 million, or approximately 73%, compared with the prior year third quarter to $418.2 million for the third quarter 2008, excluding the effect of non-cash derivative expenses and the non-recurring cash derivative early termination expense. This increase principally reflects a full quarter’s contribution from the Chaney Dell and Midkiff/Benedum systems and higher volumes and commodity prices on its Velma and Elk City/Sweetwater systems.
• The NOARK Ozark Gas Transmission (“OGT”) system’s throughput volume increased 120.1 MMcfd, or 37%, compared with the prior year third quarter to 445.7 MMcfd for the third 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 increased to 243.4 MMcfd for the third quarter 2008, an increase of 12.3 MMcfd or 5% when compared with the prior year third quarter. However, the system’s efficiency rose significantly when compared with the prior year third quarter as average NGL production increased 1,704 barrels per day (“bpd”) for the third quarter 2008, or approximately 17%, when compared with the prior year comparable period. The Partnership connected 17 new wells to the Elk City/Sweetwater system during the third quarter 2008.
• The Velma system’s average natural gas processed volume decreased 1.1 MMcfd, or approximately 2%, when compared with the prior year third quarter to 60.9 MMcfd for the third quarter 2008. However, the system’s efficiency rose significantly when compared with the prior year third quarter as average NGL production increased 380 bpd for the third quarter 2008, or approximately 6%, when compared with the prior year comparable period. The Partnership connected 8 new wells to its Velma system during the third quarter 2008.
• The Chaney Dell system’s average natural gas processed volume decreased 15.5 MMcfd, or approximately 6%, when compared with the prior year third quarter to 234.5 MMcfd for the third quarter 2008. In addition, NGL production volumes increased 1,450 bpd to 14,128 bpd, or 11% when compared to the prior year third quarter. The Partnership connected 75 new wells to its Chaney Dell system during the third quarter 2008.
• The Midkiff/Benedum system’s average natural gas processed volume decreased 7.6 MMcfd, or approximately 5%, when compared with the prior year third quarter to 136.7 MMcfd for the third quarter 2008. NGL production volumes also decreased 1,782 bpd to 18,920 bpd, or 9% when compared to the prior year third quarter. The Partnership connected 32 new wells to its Midkiff/Benedum system during the third quarter 2008.

Appalachia Segment Results

• Total revenue for the Appalachia segment increased $4.4 million, or approximately 48%, when compared with the prior year third quarter to $13.5 million for the third quarter 2008, due principally to higher throughput volume generated primarily through new wells connected to the Partnership’s gathering system, the acquisition of the McKean processing plant and gathering system in central Pennsylvania in August 2007, and the acquisition of the Volunteer gathering system in northeastern Tennessee in February 2008. The increase in total revenue for the Appalachia segment was also due to an increase in the average transportation rate between periods.
• Throughput volume increased to a record 91.8 MMcfd for the third quarter 2008, an increase of 20.0 MMcfd or 28%, when compared with the prior year third 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 McKean and Volunteer gathering systems. The Volunteer gathering system serves several counties northwest of Knoxville, Tennessee, an area of active drilling and production including that of Atlas Energy. In conjunction with the acquisition of this gathering system and other activities in the region, the Partnership has announced that it intends to construct two new processing facilities that will service natural gas produced in this northeastern Tennessee area.
• During the third quarter 2008, 214 new wells were connected to the Appalachia gathering system compared with 189 new wells for the prior year third quarter.

Corporate and Other

• General and administrative expense, including amounts reimbursed to affiliates, decreased $39.6 million to income of $1.8 million for the third quarter 2008 when compared with expense of $37.8 million for the prior year third quarter. This decrease was primarily related to a $44.5 million decrease in non-cash compensation expense, partially offset by higher costs of managing the Partnership’s operations, including the Chaney Dell and Midkiff/Benedum systems acquired in late July 2007 and acquisition and capital raising activities. The decrease in non-cash compensation expense was principally attributable to a $13.3 million 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 and is based upon the financial performance of certain acquired assets. The mark-to-market gain was the result of a decrease in the Partnership’s common unit market price at September 30, 2008 when compared with the June 30, 2008 price, which is utilized in the estimate of the non-cash compensation expense for these awards. Non-cash compensation expense of $31.8 million for the three months ended September 30, 2007 included $31.2 million recognized in connection with these common unit awards as a result of the effect the Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards.
• Depreciation and amortization increased $6.4 million when compared with the prior year third quarter to $22.6 million for the third quarter 2008 due primarily to a full quarter’s depreciation associated with the Chaney Dell and Midkiff/Benedum assets, which were acquired by the Partnership in late July 2007, and the Partnership’s expansion capital expenditures incurred subsequent to the third quarter 2007.
• Interest expense decreased $2.2 million to $21.8 million for third quarter 2008 when compared with the prior year third quarter due primarily to a $4.6 million decrease in amortization expense related to deferred financing costs and a $3.3 million decrease in interest expense associated with the term loan issued in connection with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems, partially offset by a $5.5 million increase in interest expense related to the Partnership’s additional senior notes issued during June 2008. In June 2008, the Partnership issued $250.0 million of 10-year 8.75% senior unsecured notes in a private placement transaction, of which it utilized $122.8 million to repay a portion of the indebtedness under its senior secured term loan. Interest expense for the three months ended September 30, 2007 included $5.0 million of accelerated amortization associated with the replacement of the Partnership’s previous credit facility with a new credit facility in July 2007.

At September 30, 2008, the Partnership had $1,426.5 million of total debt, including $707.2 million outstanding on its term loan that matures in 2014, $544.3 million of senior unsecured notes that mature in 2015 and 2018, and $175.0 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.

⁽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 third quarter 2008 results on Wednesday, November 5, 2008 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 pm ET on Wednesday, November 5, 2008. To access the replay, dial 1-888-286-8010 and enter conference code 88966328.

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 the Partnership’s website at www.atlaspipelinepartners.com or contact bbegley@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 at bbegley@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 at www.atlasamerica.com, or contact Investor Relations at bbegley@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,
STATEMENTS OF OPERATIONS		2008				2007				2008				2007
Revenue:
Natural gas and liquids		$	404,182			$	229,891			$	1,209,587			$	436,859
Transportation, compression, and other fees – affiliates			11,916				8,495				32,496				24,673
Transportation, compression, and other fees – third parties			12,153				12,948				39,724				33,374
Other income (loss), net			153,875				(9,034	)			(247,140	)			(39,654	)
Total revenue and other income (loss), net			582,126				242,300				1,034,667				455,252
Costs and expenses:
Natural gas and liquids			316,917				174,727				943,561				349,639
Plant operating			16,652				9,108				46,418				18,153
Transportation and compression			4,768				3,555				12,881				9,877
General and administrative			(2,946	)			36,424				10,055				48,735
Compensation reimbursement – affiliates			1,175				1,392				3,694				2,820
Depreciation and amortization			22,550				16,176				74,571				29,381
Interest			21,846				24,040				61,612				38,126
Minority interest			2,591				1,376				7,793				1,376
Total costs and expenses			383,553				266,798				1,160,585				498,107
Net income (loss)			198,573				(24,498	)			(125,918	)			(42,855	)
Preferred unit dividend effect			−				−				−				(3,756	)
Preferred unit dividends			(650	)			−				(1,437	)			−
Preferred unit imputed dividend cost			−				(624	)			(505	)			(1,858	)
Net income (loss) attributable to common limited partners and the general partner		$	197,923			$	(25,122	)		$	(127,860	)		$	(48,469	)
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest		$	117,203			$	(28,242	)		$	(216,960	)		$	(58,854	)
General partner’s interest			80,720				3,120				89,100				10,385
Net income (loss) attributable to common limited partners and the general partner		$	197,923			$	(25,122	)		$	(127,860	)		$	(48,469	)
Net income (loss) attributable to common limited partners per unit:
Basic		$	2.55			$	(0.90	)		$	(5.25	)		$	(3.05	)
Diluted		$	2.43			$	(0.90	)		$	(5.25	)		$	(3.05	)
Weighted average common limited partner units outstanding:
Basic			45,937				31,449				41,360				19,270
Diluted			48,187				31,449				41,360				19,270
Capital expenditure data:
Maintenance capital expenditures		$	1,711			$	2,328			$	5,375			$	3,800
Expansion capital expenditures			87,413				32,216				241,019				72,628
Total		$	89,124			$	34,544			$	246,394			$	76,428

		September 30,			December 31,
Balance Sheet Data (at period end):		2008			2007
Cash and cash equivalents		$	43,813		$	11,980
Total assets			3,056,762			2,877,614
Total debt			1,426,498			1,229,426
Total partners’ capital			1,204,911			1,273,960

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Segment Information
(in thousands)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2008				2007				2008				2007
Mid-Continent
Revenue:
Natural gas and liquids		$	403,064			$	229,511			$	1,206,386			$	436,479
Transportation, compression, and other fees			11,769				12,793				38,772				33,183
Other income (loss), net			153,802				(9,133	)			(247,413	)			(39,918	)
Total revenue and other income (loss), net			568,635				233,171				997,745				429,744
Costs and expenses:
Natural gas and liquids			316,365				174,471				942,022				349,383
Plant operating			16,652				9,108				46,418				18,153
Transportation and compression			1,885				1,943				5,039				5,443
General and administrative			(4,494	)			34,806				5,013				43,506
Depreciation and amortization			20,873				14,992				69,968				26,007
Minority interest			2,591				1,376				7,793				1,376
Total costs and expenses			353,872				236,696				1,076,253				443,868
Segment income (loss)		$	214,763			$	(3,525	)		$	(78,508	)		$	(14,124	)
Appalachia
Revenue:
Natural gas and liquids		$	1,118			$	380			$	3,201			$	380
Transportation, compression, and other fees – affiliates			11,916				8,494				32,496				24,673
Transportation, compression, and other fees – third parties			384				156				952				191
Other income			73				99				273				264
Total revenue and other income			13,491				9,129				36,922				25,508
Costs and expenses:
Natural gas and liquids			552				256				1,539				256
Transportation and compression			2,883				1,612				7,842				4,434
General and administrative			1,361				1,505				4,368				4,025
Depreciation and amortization			1,677				1,184				4,603				3,374
Total costs and expenses			6,473				4,557				18,352				12,089
Segment income		$	7,018			$	4,572			$	18,570			$	13,419
Reconciliation of segment income (loss) to net income (loss):
Segment income (loss):
Mid-Continent		$	214,763			$	(3,525	)		$	(78,508	)		$	(14,124	)
Appalachia			7,018				4,572				18,570				13,419
Total segment income (loss)			221,781				1,047				(59,938	)			(705	)
Corporate general and administrative expense			(1,362	)			(1,505	)			(4,368	)			(4,024	)
Interest expense			(21,846	)			(24,040	)			(61,612	)			(38,126	)
Net income (loss)		$	198,573			$	(24,498	)		$	(125,918	)		$	(42,855	)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
(in thousands)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2008				2007				2008				2007
Reconciliation of total revenue and other income (loss), net to adjusted total revenue and other income (loss), net(1):
Total revenue and other income (loss), net		$	582,126			$	242,300			$	1,034,667			$	455,252
Non-cash derivative expense (income)			(221,984	)			8,430				36,019				39,256
Non-recurring cash derivative early termination expense(2)			71,516				−				187,641				−
Non-recurring crude oil to natural gas liquids price correlation impact(3)			−				−				10,653				−
Adjusted total revenue and other income (loss), net		$	431,658			$	250,730			$	1,268,980			$	494,508
Reconciliation of net income (loss) to adjusted net income(1):
Net income (loss)		$	198,573			$	(24,498	)		$	(125,918	)		$	(42,855	)
Non-cash derivative expense (income)			(221,984	)			8,430				36,019				39,256
Non-recurring cash derivative early termination expense(2)			71,516				−				187,641				−
Non-recurring crude oil to natural gas liquids price correlation impact(3)			−				−				10,653				−
Unrecognized economic impact of Anadarko acquisition(4)			−				10,423				−				10,423
Non-cash compensation expense (income)			(12,673	)			31,834				(14,273	)			36,110
Adjusted net income		$	35,432			$	26,189			$	94,122			$	42,934
Preferred unit dividend effect			−				−				−				(3,756	)
Preferred unit dividends			(650	)			−				(1,437	)			−
Preferred unit imputed dividend cost			−				(624	)			(505	)			(1,858	)
Adjusted net income attributable to common limited partners and the general partner		$	34,782			$	25,565			$	92,180			$	37,320
Allocation of adjusted net income attributable to common limited partners and the general partner:
Common limited partners’ interest		$	26,010			$	21,426			$	71,749			$	26,935
General partner’s interest			8,772				4,139				20,431				10,385
Adjusted net income attributable to common limited partners and the general partner		$	34,782			$	25,565			$	92,180			$	37,320
Adjusted net income attributable to common limited partners per unit:
Basic		$	0.57			$	0.68			$	1.73			$	1.40
Diluted		$	0.54			$	0.67			$	1.65			$	1.37
Weighted average common limited partner units outstanding:
Basic			45,937				31,449				41,360				19,270
Diluted			48,187				32,068				43,413				19,649
Reconciliation of net loss to other non-GAAP measures(1):
Net income (loss)		$	198,573			$	(24,498	)		$	(125,918	)		$	(42,855	)
Depreciation and amortization			22,550				16,176				74,571				29,381
Interest expense			21,846				24,040				61,612				38,126
EBITDA			242,969				15,718				10,265				24,652
Non-cash derivative expense (income)			(221,984	)			8,430				36,019				39,256
Non-recurring cash derivative early termination expense(2)			71,516				−				187,641				−
Non-recurring crude oil to natural gas liquids price correlation impact(3)			−				−				10,653				−
Unrecognized economic impact of Anadarko acquisition(4)			−				10,423				−				10,423
Non-cash compensation expense (income)			(12,673	)			31,834				(14,273	)			36,110
Adjusted EBITDA			79,828				66,405				230,305				110,441
Interest expense			(21,846	)			(24,040	)			(61,612	)			(38,126	)
Amortization of deferred financing costs			1,042				5,622				3,650				6,690
Preferred unit dividends			(650	)			−				(1,437	)			−
Maintenance capital expenditures			(1,711	)			(2,328	)			(5,375	)			(3,800	)
Distributable cash flow(5)		$	56,663			$	45,659			$	165,531			$	75,205

(1)		Adjusted net income, adjusted total revenue and other income (loss), net, 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 income (loss), net, 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, adjusted total revenue and other income (loss), net, 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, total revenue and other income (loss), net, 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 2nd quarter 2008 through the 4th 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 2nd quarter 2008 through the 4th 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)		The acquisition of the Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition's effective date was July 1, 2007. As such, the Partnership received 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.
(5)		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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Operating Highlights
		Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
Mid-Continent – Velma System
Natural Gas
Gross natural gas gathered – mcfd(1)		64,386		63,757		64,103		62,531
Gross natural gas processed – mcfd(1)		60,902		61,968		60,972		60,555
Gross residue natural gas – mcfd(1)		48,300		49,502		48,158		47,487
Natural Gas Liquids
Gross NGL sales – bpd(1)		6,595		6,215		6,758		6,386
Condensate
Gross condensate sales – bpd(1)		308		254		286		222
Mid-Continent – Elk City/Sweetwater System
Natural Gas
Gross natural gas gathered – mcfd(1)		279,145		299,450		292,307		298,724
Gross natural gas processed – mcfd(1)		243,409		231,152		236,520		224,521
Gross residue natural gas – mcfd(1)		219,945		211,368		213,668		206,011
Natural Gas Liquids
Gross NGL sales – bpd(1)		11,486		9,782		10,874		9,351
Condensate
Gross condensate sales – bpd(1)		251		143		299		228
Mid-Continent – Chaney Dell System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)		300,467		255,649		278,906		255,649
Gross natural gas processed – mcfd(1)		234,529		249,982		246,365		249,982
Gross residue natural gas – mcfd(1)		250,994		222,508		238,264		222,508
Natural Gas Liquids
Gross NGL sales – bpd(1)		14,128		12,678		13,299		12,678
Condensate
Gross condensate sales – bpd(1)		759		564		774		564
Mid-Continent – Midkiff/Benedum System(2)
Natural Gas
Gross natural gas gathered – mcfd(1)		143,224		150,061		145,300		150,061
Gross natural gas processed – mcfd(1)		136,656		144,280		138,178		144,280
Gross residue natural gas – mcfd(1)		84,372		93,859		92,352		93,859
Natural Gas Liquids
Gross NGL sales – bpd(1)		18,920		20,702		20,029		20,702
Condensate
Gross condensate sales – bpd(1)		1,573		1,754		1,288		1,754
Mid-Continent – NOARK system
Ozark Gas Transmission throughput – mcfd(1)		445,708		325,652		412,634		311,562
Appalachia
Throughput – mcfd(1)		91,829		71,876		84,007		66,888

(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.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Current Hedge Positions
(as of October 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		4,956,000		$ 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		536,400		29,972,124		$	70.16		Puts purchased
2008		84,000		7,479,360		$	127.55		Puts sold(1)
2008		126,000		11,219,040		$	140.00		Calls purchased(1)
2008		473,400		25,764,984		$	80.13		Calls sold
2009		1,584,000		85,038,534		$	80.00		Puts purchased
2009		304,200		27,085,968		$	126.05		Puts sold(1)
2009		304,200		27,085,968		$	143.00		Calls purchased(1)
2009		2,121,600		114,072,336		$	81.01		Calls sold
2010		3,127,500		202,370,490		$	81.09		Calls sold
2010		714,000		45,415,440		$	120.00		Calls purchased(1)
2011		606,000		32,578,560		$	95.56		Calls sold
2011		252,000		13,547,520		$	120.00		Calls purchased(1)
2012		450,000		24,192,000		$	97.10		Calls sold
2012		180,000		9,676,800		$	120.00		Calls purchased(1)

Natural Gas Sales – Fixed Price Swaps
Production Period Ended December 31,		Volumes		Average Fixed Price
		(mmbtu)(2)		(per mmbtu)(2)
2008		1,371,000		$	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		1,371,000		$	(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		3,167,000		$	8.931	(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		2,817,000		$	(1.108)
2009		15,564,000		$	(0.654)
2010		8,940,000		$	(0.600)
2011		2,160,000		$	(0.700)
2012		1,560,000		$	(0.610)

Ethane Put Options
Production Period Ended December 31,		Volume		Average Strike Price			Option Type
		(gallons)		(per gallon)
2008		7,560,000		$	0.79		Puts purchased
2009		16,254,000		$	0.69		Puts purchased

Propane Put Options
Production Period Ended December 31,		Volume		Average Strike Price			Option Type
		(gallons)		(per gallon)
2008		8,946,000		$	1.48		Puts purchased
2009		23,310,000		$	1.39		Puts purchased

Crude Oil Sales
Production Period Ended December 31,		Volumes		Average Fixed Price
		(barrels)		(per barrel)
2008		10,400		$	60.750
2009		33,000		$	62.700

Crude Oil Sales Options
Production Period Ended December 31,		Volumes		Average Strike Price			Option Type
		(barrels)		(per barrel)
2008		69,000		$	68.000		Puts purchased
2008		69,000		$	78.055		Calls sold
2009		168,000		$	90.000		Puts purchased
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 in 2008 and 2009 and calls purchased in 2008 through 2012 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 234,000 mmbtu of natural gas for the year ended December 31, 2008 at $18.00 per mmbtu.