Atlas Pipeline Partners 8-K Reports Third Quarter 2011 Results

Exhibit 99.1

Contact: Matthew Skelly VP – Investor Relations 1845 Walnut Street Philadelphia, PA 19103 (877) 280-2857 (215) 561-5692 (facsimile)

ATLAS PIPELINE PARTNERS, L.P.

REPORTS THIRD QUARTER 2011 RESULTS

• Distributable Cash Flow for third quarter 2011 was $37.3 million, an increase of 25% over previous quarter

• Announced distribution of $0.54 per common limited partner unit, a 15% increase over previous quarter

• Adjusted EBITDA for third quarter 2011 was $49.7 million, an increase of 14% over previous quarter

• Third quarter 2011 processed gas volume was 567 MMCFD, a 21% year-over-year quarterly increase

• Risk management program expanded to increase margin protection through 2013

• WestTX expansion online; Velma and WestOK expansion coming in on-time and within budget

Philadelphia, PA, October 31, 2011 – Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL”, “Atlas Pipeline”, or the “Partnership”)today reported adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), of $49.7 million for the third quarter of 2011 as volumes and natural gas liquids (“NGL”) prices increased across all systems. Processed natural gas volumes totaled 567 million cubic feet per day, a 21% increase compared to the same period last year, and the weighted average NGL price was $1.27/gallon for the quarter, a 41% increase year-over-year. For the third quarter of 2011, Distributable Cash Flow was $37.3 million, or $0.70 per average common limited partner unit. Net income from continuing operations was $50.3 million for the third quarter of 2011 compared with net loss of $17.5 million for the prior year third quarter.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures within the tables at the end of this news release. The Partnership believes these measures provide a more accurate comparison of the operating results for the periods presented.

On October 26, 2011, the Partnership declared a distribution for the third quarter of 2011 of $0.54 per common limited partner unit to holders of record on November 7, 2011, and payable on November 14, 2011. This represents a sequential quarterly growth rate of 14.9% over the second quarter of 2011. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.21x for the third quarter of 2011.

“We are pleased to report another successful quarter of results for the Partnership. With continued strong activity in the areas we operate, we have raised the distribution another 15% to $0.54 a unit, the second straight quarter of double-digit percentage quarterly distribution growth. This also represents over 50% distribution growth over the past year. Operationally, our focus going forward is to execute the announced organic growth plans that we have discussed previously. Those expansions are coming in on time and within budget with the re-start of the Midkiff skid at West Texas now back in service and Velma and WestOK on track for a mid-2012 in-service date. Our team is going to work hard over the next couple of quarters to get these facilities installed to better serve our customers. As activities continue to pick up in our footprint, we will continue to capitalize on opportunities that arise and look to add even more value to our unit holders. Thank you for your continued support,” stated Eugene N. Dubay, Chief Executive Officer of the Partnership.

*    *    *

1

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $250.6 million as of September 30, 2011. Total debt outstanding was $426.0 million at September 30, 2011, compared to $566.0 million at December 31, 2010, a decrease of $140.0 million. Based upon total debt outstanding at September 30, 2011, total leverage was 2.5x and debt to capital was 25%, inclusive of down-payments on the purchase of two new cryogenic processing facilities and the strategic investment of a 20% interest in the West Texas LPG Pipeline Limited Partnership. The Partnership has incurred approximately half of the $400 million planned capital expenditure program announced earlier this year, including $85 million for the purchase of West Texas LPG; the WestTX re-commissioning of its 60 MMCFD Midkiff plant and down payments towards the WestOK and Velma expansions.

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2012 and 2013. As of October 28, 2011, the Partnership has natural gas, natural gas liquids and condensate protection in place for the remainder of 2011 for approximately 73% of associated margin value (exclusive of ethane), as well as coverage for 2012 and 2013 on approximately 76% and 42%, respectively, of associated margin value (exclusive of ethane). Counterparties to the Partnership’s risk management activities consist of investment grade commercial banks that are lenders under the Partnership’s credit facility, or affiliates of such banks. A table summarizing our risk management portfolio is included in this release.

*    *    *

Operating Results

Gross margin from operations was $71.2 million for the third quarter 2011, compared to $50.3 million for the same period last year. Gross margin includes natural gas and liquids revenues and transportation, compression and other fees, less purchased product costs and non-cash gains (or losses). The increase in gross margin was primarily due to increased NGL prices and volumes. Volumes on the Velma system increased due to production added on the Madill to Velma gathering system associated with activity in the Woodford Shale. The increase in volumes on the Partnership’s WestOK system is related to our expansion into Kansas and increased producer activity in Oklahoma and Kansas, particularly in the Mississippian formations. Volume increases on the WestTX system are a result of additional development for oil drilling in the Permian Basin.

WestTX System

The WestTX system’s average natural gas processed volume was 198.1 million cubic feet per day (“MMCFD”) for the third quarter 2011 compared with 171.0 MMCFD for the prior year comparable quarter, an increase of 15.8% and NGL production of 27,387 barrels per day (“BPD”), a decrease of 4.1% compared with prior year quarter. Increased volumes are primarily due to increased production from producers in the Spraberry and Wolfberry Trends. The Partnership expects volumes on this system to continue to increase as producers continue to aggressively pursue their drilling plans over the coming years. As a result of this increased producer activity, the Partnership has re-commissioned its 60 MMCFD Midkiff plant, which increases processing capacity on the WestTX system to 255 MMCFD, an increase of 31% in processing capacity. The expansion came online in early October as incremental liquids takeaway capacity was secured and the Partnership expects volumes to fill up the expansion over the coming year.

WestOK System

The WestOK system had average natural gas processed volume of 263.7 MMCFD, a 24.6% increase, and NGL production of 13,392 BPD, a 15.8% increase, for the third quarter 2011 from the prior year comparable period. The Partnership completed an expansion of its WestOK system into Kansas during June 2010 and experienced an increase in processed gas volumes due to this project, as well as increased production from other producers on the system. The WestOK system is currently operating in excess of capacity with certain volumes being off-loaded to third-parties for processing or by-passing the processing facilities. The Partnership expects volumes to continue to increase as volumes from producers in Oklahoma, along with others in Kansas, continue to add to the system via development in the oil rich Mississippian Limestone formation. The Partnership has purchased and is currently working to install a new 200 MMCFD cryogenic plant and an expansion of the gathering system in order to meet the drilling plans of its existing producers. This expansion would result in total processing capacity of 428 MMCFD, for an increase of 88%. The expansion is expected to be completed in mid-2012.

Velma System

The Velma system’s average natural gas processed volume was 104.9 MMCFD for the third quarter 2011, an increase of 24.5% compared with the comparable quarter in the prior year. The increase is primarily due to additional production gathered on the Madill to Velma pipeline system from continued producer activity in the liquids-rich portion of the Woodford Shale. Gathered volumes were up 21.4 MMCFD, or 23.7% compared to the same quarter last year. Average NGL production increased to 12,198 BPD for the third quarter 2011, up approximately 19.2% compared to 10,231 BPD for the prior year third quarter, due to the increased processed volumes. The Partnership plans to expand the Velma system by adding a 60 MMCFD cryogenic plant, thereby increasing processing capacity to 160 MMCFD, an increase of 60%, as producers look to take advantage of high NGL content gas in the Woodford shale.

2

West Texas LPG Pipeline

On May 11, 2011, the Partnership completed the acquisition of a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. WTLPG owns a 2,295 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corp. (NYSE: CVX). The Partnership received $784 thousand in distributions during the third quarter of 2011 from this investment, representing its share of cash flow for the approximately 50 days it owned its share of the asset during the second quarter, which is included in its Distributable Cash Flow for the current period.

*    *    *

Corporate and Other

Net of deferred financing costs, interest expense decreased to $4.9 million for the third quarter 2011, down 77.3% as compared with $21.5 million for the third quarter 2010. This decrease was primarily due to reduction in debt outstanding during the period from the proceeds of the Elk City and Laurel Mountain sales, offset by the current organic expansion program.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s third quarter 2011 results on Tuesday, November 1, 2011 at 10:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 1:00 pm ET on Tuesday, November 1, 2011. To access the replay, dial 1-888-286-8010 and enter conference code 37877093.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates five active gas processing plants as well as approximately 8,600 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master 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 5.75 million common limited partner units of APL. Additionally, ATLS owns an interest in over 8,500 producing natural gas and oil wells, representing over 185 Bcfe of net proved developed reserves. For more information, please visit Atlas Energy’s website at http://www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.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. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity prices and 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.

3

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary⁽¹⁾

(unaudited; in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenue:
Natural gas and liquids	$	341,498		$	220,478		$	937,975		$	641,978
Transportation, processing and other fees(2)		11,691			9,951			31,536			29,944
Other income (loss), net		26,591			(4,311	)		17,317			10,576
Total revenue and other income (loss), net		379,780			226,118			986,828			682,498
Costs and expenses:
Natural gas and liquids		282,391			178,920			774,859			521,495
Plant operating		14,085			12,552			40,240			36,492
Transportation and compression		268			300			603			721
General and administrative(3)		8,321			6,814			24,314			20,730
General and administrative – non-cash unit-based compensation(3)		828			764			2,507			2,791
Other		8			—			583			—
Depreciation and amortization		19,471			18,566			57,499			55,647
Interest		5,935			23,087			24,525			74,085
Total costs and expenses		331,307			241,003			925,130			711,961
Equity income in joint ventures		1,785			1,787			2,934			4,137
Gain on asset sale		—			—			255,674			—
Loss on early extinguishment of debt		—			(4,359	)		(19,574	)		(4,359	)
Income (loss) from continuing operations		50,258			(17,457	)		300,732			(29,685	)
Discontinued operations:
Gain (loss) on sale of discontinued operations		—			311,492			(81	)		311,492
Earnings (loss) from discontinued operations		—			(5,565	)		—			9,192
Income (loss) from discontinued operations		—			305,927			(81	)		320,684
Net income		50,258			288,470			300,651			290,999
Income attributable to non-controlling interests		(1,760	)		(1,076	)		(4,492	)		(3,338	)
Preferred unit dividends		—			(240	)		(389	)		(240	)
Net income attributable to common limited partners and the General Partner	$	48,498		$	287,154		$	295,770		$	287,421

(1) Based on the GAAP statements of operations to be included in Form 10-Q, with additional detail of certain items included.

(2) Includes affiliate revenues related to transportation and processing provided to Atlas Energy, L.P.

(3) Non-cash costs associated with unit-based compensation, which have been reflected in the general and administrative costs and expenses, the category associated with the direct personnel cash costs in the GAAP statements of operations to be included in Form 10-Q. General and administrative also includes any compensation reimbursement to affiliates.

4

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	0.87		$	(0.34	)	$	5.37		$	(0.61	)
Discontinued operations		—			5.63			—			5.92
	$	0.87		$	5.29		$	5.37		$	5.31
Weighted average common limited partner units (basic)		53,588			53,277			53,494			53,115
Diluted:
Continuing operations	$	0.87		$	(0.34	)	$	5.37		$	(0.61	)
Discontinued operations		—			5.63			—			5.92
	$	0.87		$	5.29		$	5.37		$	5.31
Weighted average common limited partner units (diluted)		54,012			53,277			53,923			53,115
Summary Cash Flow Data:
Cash provided by operating activities	$	28,748		$	44,159		$	80,658		$	101,285
Cash provided by (used in) investing activities		(56,568	)		659,265			165,994			629,888
Cash provided by (used in) financing activities		27,821			(703,418	)		(246,649	)		(732,028	)
Capital Expenditure Data:
Maintenance capital expenditures	$	4,980		$	2,595		$	13,451		$	6,478
Expansion capital expenditures		51,195			8,745			134,693			25,600
Investments in Joint Ventures		—			1,300			97,250			6,914
Total	$	56,175		$	12,640		$	245,394		$	38,992

5

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)

	September 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	167		$	164
Other current assets		154,174			114,877
Total current assets		154,341			115,041
Property, plant and equipment, net		1,481,441			1,341,002
Intangible assets, net		109,052			126,379
Investment in joint venture		86,688			153,358
Other assets, net		48,791			29,068
	$	1,880,313		$	1,764,848
LIABILITIES AND EQUITY
Current liabilities	$	185,941		$	151,606
Long-term debt, less current portion		423,927			565,764
Other long-term liability		127			5,831
Commitments and contingencies
Total partners’ capital		1,300,183			1,074,184
Non-controlling interest		(29,865	)		(32,537	)
Total equity		1,270,318			1,041,647
	$	1,880,313		$	1,764,848

6

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010(1)			2011			2010(1)
Reconciliation of net income to other non-GAAP measures(2):
Net income	$	50,258		$	288,470		$	300,651		$	290,999
Income attributable to non-controlling interests		(1,760	)		(1,076	)		(4,492	)		(3,338	)
Depreciation and amortization		19,471			18,566			57,499			55,647
Interest expense(1) (3)		5,935			23,087			24,525			74,689
Depreciation, amortization and interest of discontinued operations		—			3,490			—			12,069
EBITDA		73,904			332,537			378,183			430,066
Adjustment for cash flow from investment in joint ventures		(1,001	)		39			(386	)		4,139
Non-cash (gain) loss on derivatives		(27,049	)		6,088			(22,477	)		(16,162	)
Early termination cash derivative expense(4)		—			—			—			22,401
Premium expense on derivative instruments		2,599			3,714			9,314			17,531
Gain on asset sales and other		—			(311,492	)		(255,593	)		(311,492	)
Loss on early extinguishment of debt		—			4,359			19,574			4,359
Other non-cash (gains) losses(5)		1,250			(471	)		3,172			2,477
Discontinued operations adjustments(6)		—			13,604			—			13,629
Adjusted EBITDA		49,703			48,378			131,787			166,948
Interest expense(1)(3)		(5,935	)		(23,087	)		(24,525	)		(74,689	)
Amortization of deferred financing costs		1,053			1,547			3,354			4,729
Preferred unit dividends		—			(240	)		(389	)		(240	)
Premium expense on derivative instruments		(2,599	)		(3,714	)		(9,314	)		(17,531	)
Laurel Mountain proceeds remaining(7)		—			—			5,850			—
Other		8			—			583			—
Maintenance capital expenditures		(4,980	)		(2,595	)		(13,451	)		(6,478	)
Discontinued operations adjustments(8)		—			(1,593	)		—			(8,140	)
Distributable Cash Flow	$	37,250		$	18,696		$	93,895		$	64,599

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

(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. Adjusted EBITDA is also similar to the Consolidated EBITDA calculation that is utilized within the Partnership’s financial covenants under its credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of the Partnership’s Elk City/Sweetwater system; and (ii) other non-cash items specifically excluded under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.

(3) For the nine months ended September 30, 2010, includes the cost of interest rate swaps that were previously recognized in interest expense prior to becoming ineffective in June 2009. They were subsequently recorded in other income (loss), net in the Partnership’s income statement.

(4) During the nine months ended September 30, 2010, the Partnership made net payments of $33.7 million related to the early termination of derivative contracts, including $11.3 million related to Elk City derivatives included in discontinued operations adjustments. The Partnership’s credit facility definition of Consolidated EBITDA allows 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.

(5) Includes the non-cash impact of commodity price movements on pipeline linefill inventory and non-cash compensation.

(6) Discontinued operation adjustments for Adjusted EBITDA include (i) early termination cash derivative expense; (ii) premium expense on derivative instruments; and (iii) non-cash (gain) loss on derivatives.

(7) Net proceeds remaining from the sale of Laurel Mountain after the repayment of the amount outstanding on the Partnership’s revolving credit facility, redemption of its 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018.

(8) Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; (ii) interest expense and (iii) premiums expense on derivative instruments.

7

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights⁽¹⁾

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Percent Change			2011		2010		Percent Change
Pricing (unhedged):
Mid-Continent Weighted Average Prices:
NGL price per gallon – Conway hub	$	1.13	$	0.85		32.9	%	$	1.11	$	0.93		19.4	%
NGL price per gallon – Mt. Belvieu hub		1.36		0.95		43.2	%		1.30		1.04		25.0	%
Natural gas sales ($/MCF):
Velma		4.02		4.03		(0.2	)%		4.04		4.35		(7.1	)%
WestOK		4.04		4.01		0.7	%		4.05		4.35		(6.9	)%
WestTX		4.05		3.99		1.5	%		4.04		4.30		(6.0	)%
Weighted Average		4.04		4.01		0.7	%		4.04		4.33		(6.7	)%
NGL sales ($/Gallon):
Velma		1.16		0.80		45.0	%		1.12		0.87		28.7	%
WestOK		1.17		0.91		28.6	%		1.13		0.92		22.8	%
WestTX		1.42		0.94		51.1	%		1.32		1.00		32.0	%
Weighted Average		1.27		0.90		41.1	%		1.21		0.96		26.0	%
Condensate sales ($/Barrel):
Velma		88.54		74.92		18.2	%		94.39		76.19		23.9	%
WestOK		81.23		68.73		18.2	%		86.75		71.33		21.6	%
WestTX		87.68		74.82		17.2	%		92.77		74.06		25.3	%
Weighted Average		85.77		73.55		16.6	%		90.91		73.68		23.4	%
Volumes:
Velma system:
Gathered gas volume (MCFD)		111,777		90,377		23.7	%		101,593		81,107		25.3	%
Processed gas volume (MCFD)		104,930		84,255		24.5	%		95,643		75,531		26.6	%
Residue gas volume (MCFD)		87,099		68,713		26.8	%		78,462		61,559		27.5	%
Processed NGL volume (BPD)		12,198		10,231		19.2	%		11,219		8,749		28.2	%
Condensate volume (BPD)		346		369		(6.2	)%		439		410		7.1	%
WestOK system:
Gathered gas volume (MCFD)		277,794		225,395		23.2	%		260,863		223,511		16.7	%
Processed gas volume (MCFD)		263,654		211,533		24.6	%		247,259		197,197		25.4	%
Residue gas volume (MCFD)		242,744		187,024		29.8	%		224,158		177,245		26.5	%
Processed NGL volume (BPD)		13,392		11,561		15.8	%		13,395		11,785		13.7	%
Condensate volume (BPD)		786		599		31.2	%		842		661		27.4	%
WestTX system(2):
Gathered gas volume (MCFD)		224,412		188,960		18.8	%		205,089		175,985		16.5	%
Processed gas volume (MCFD)		198,068		170,988		15.8	%		188,292		161,474		16.6	%
Residue gas volume (MCFD)		136,594		109,167		25.1	%		128,584		104,742		22.8	%
Processed NGL volume (BPD)		27,387		28,557		(4.1	)%		28,003		26,533		5.5	%
Condensate volume (BPD)		2,257		1,867		20.9	%		1,707		1,353		26.2	%
West Texas LPG Partnership(3)
Average NGL volumes (BPD)		227,822		234,002		(2.6	)%		227,334		224,963		1.1	%
Consolidated Volumes:
Gathered gas volume (MCFD)		621,476		513,874		20.9	%		575,292		489,370		17.6	%
Processed gas volume (MCFD)		566,652		466,776		21.4	%		531,194		434,202		22.3	%
Residue gas volume (MCFD)		466,437		364,904		27.8	%		431,204		343,546		25.5	%
Processed NGL volume (BPD)		52,977		50,349		5.2	%		52,617		47,067		11.8	%
Condensate volume (BPD)		3,389		2,835		19.5	%		2,988		2,424		23.3	%

(1) “MCF” represents thousand cubic feet; “MCFD” represents thousand cubic feet per day; “BPD” represents barrels per day.

(2) Operating data for the WestTX system represents 100% of its operating activity.

(3) Volume data for the West Texas LPG Partnership represents 100% of its operating activity for the calendar year.

8

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of October 28, 2011)

Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2013. APL’s price risk management position in its entirety will be disclosed in the Partnership’s Form 10-Q.

SWAP CONTRACTS

NATURAL GAS HEDGES

Production Period	Purchased/Sold	Commodity	MMBTU		Avg. Fixed Price
4Q 2011	Sold	Natural Gas		1,200,000		4.91

NATURAL GAS LIQUIDS HEDGES

Production Period	Purchased/Sold	Commodity	Gallons		Avg. Fixed Price
4Q 2011	Sold	Ethane		2,142,000		0.73
4Q 2011	Sold	Propane		4,284,000		1.19
4Q 2011	Sold	Isobutane		504,000		1.63
4Q 2011	Sold	Normal Butane		1,386,000		1.59
4Q 2011	Sold	Natural Gasoline		3,276,000		2.04
1Q 2012	Sold	Ethane		2,898,000		0.74
1Q 2012	Sold	Propane		4,410,000		1.37
1Q 2012	Sold	Isobutane		504,000		1.97
1Q 2012	Sold	Normal Butane		1,386,000		1.93
1Q 2012	Sold	Natural Gasoline		1,008,000		2.42
2Q 2012	Sold	Propane		4,788,000		1.24
2Q 2012	Sold	Isobutane		630,000		1.60
2Q 2012	Sold	Normal Butane		1,260,000		1.72
2Q 2012	Sold	Natural Gasoline		1,008,000		2.40
3Q 2012	Sold	Propane		5,040,000		1.25
3Q 2012	Sold	Isobutane		756,000		1.57
3Q 2012	Sold	Normal Butane		1,260,000		1.71
3Q 2012	Sold	Natural Gasoline		1,008,000		2.39
4Q 2012	Sold	Propane		5,040,000		1.35
4Q 2012	Sold	Isobutane		756,000		1.58
4Q 2012	Sold	Normal Butane		1,386,000		1.71
4Q 2012	Sold	Natural Gasoline		1,134,000		2.39

9

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of October 28, 2011)

CONDENSATE HEDGES

Production Period	Purchased/Sold	Commodity	Barrels		Avg. Fixed Price
4Q 2011	Sold	Crude		30,000		90.75
1Q 2012	Sold	Crude		81,000		95.02
2Q 2012	Sold	Crude		78,000		95.33
3Q 2012	Sold	Crude		69,000		96.65
4Q 2012	Sold	Crude		75,000		95.58
1Q 2013	Sold	Crude		21,000		90.05
2Q 2013	Sold	Crude		21,000		90.05
3Q 2013	Sold	Crude		21,000		90.05
4Q 2013	Sold	Crude		21,000		90.05

OPTION CONTRACTS

NGL OPTION CONTRACTS

Production Period	Purchased/Sold	Type	Commodity	Gallons		Avg. Strike Price
4Q 2011	Purchased	Put	Ethane		2,142,000		0.74
4Q 2011	Purchased	Put	Propane		5,040,000		1.38
1Q 2012	Purchased	Put	Ethane		1,890,000		0.70
1Q 2012	Purchased	Put	Propane		6,300,000		1.47
1Q 2012	Purchased	Put	Isobutane		756,000		1.75
1Q 2012	Purchased	Put	Natural Gasoline		2,898,000		2.36
2Q 2012	Purchased	Put	Propane		6,426,000		1.36
2Q 2012	Purchased	Put	Isobutane		756,000		1.60
2Q 2012	Purchased	Put	Normal Butane		1,134,000		1.56
2Q 2012	Purchased	Put	Natural Gasoline		2,898,000		2.05
3Q 2012	Purchased	Put	Propane		7,560,000		1.36
3Q 2012	Purchased	Put	Isobutane		1,008,000		1.57
3Q 2012	Purchased	Put	Normal Butane		1,890,000		1.54
3Q 2012	Purchased	Put	Natural Gasoline		3,780,000		2.00
4Q 2012	Purchased	Put	Propane		8,190,000		1.36
4Q 2012	Purchased	Put	Isobutane		1,134,000		1.58
4Q 2012	Purchased	Put	Normal Butane		2,142,000		1.56
4Q 2012	Purchased	Put	Natural Gasoline		4,032,000		2.00
1Q 2013	Purchased	Put	Isobutane		504,000		1.79
1Q 2013	Purchased	Put	Normal Butane		1,512,000		1.74
1Q 2013	Purchased	Put	Natural Gasoline		5,292,000		2.15
2Q 2013	Purchased	Put	Isobutane		630,000		1.72
2Q 2013	Purchased	Put	Normal Butane		1,638,000		1.66
2Q 2013	Purchased	Put	Natural Gasoline		5,796,000		2.10
3Q 2013	Purchased	Put	Isobutane		1,512,000		1.66
3Q 2013	Purchased	Put	Normal Butane		3,528,000		1.64
3Q 2013	Purchased	Put	Natural Gasoline		6,300,000		2.09
4Q 2013	Purchased	Put	Isobutane		1,512,000		1.66
4Q 2013	Purchased	Put	Normal Butane		3,780,000		1.66
4Q 2013	Purchased	Put	Natural Gasoline		6,552,000		2.09

10

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of October 28, 2011)

CRUDE OPTION CONTRACTS

Production Period	Purchased/Sold	Type	Commodity	Barrels		Avg. Strike Price
4Q 2011	Purchased	Put	Crude Oil		93,000		99.45
4Q 2011	Sold	Call	Crude Oil		169,500		93.35
4Q 2011	Purchased	Call	Crude Oil		63,000		125.20
1Q 2012	Purchased	Put	Crude Oil		63,000		106.00
1Q 2012	Sold	Call	Crude Oil		124,500		94.69
1Q 2012	Purchased	Call	Crude Oil		45,000		125.20
2Q 2012	Purchased	Put	Crude Oil		39,000		107.58
2Q 2012	Sold	Call	Crude Oil		124,500		94.69
2Q 2012	Purchased	Call	Crude Oil		45,000		125.20
3Q 2012	Purchased	Put	Crude Oil		39,000		106.56
3Q 2012	Sold	Call	Crude Oil		124,500		94.69
3Q 2012	Purchased	Call	Crude Oil		45,000		125.20
4Q 2012	Purchased	Put	Crude Oil		39,000		105.80
4Q 2012	Sold	Call	Crude Oil		124,500		94.69
4Q 2012	Purchased	Call	Crude Oil		45,000		125.20
1Q 2013	Purchased	Put	Crude Oil		66,000		100.10
2Q 2013	Purchased	Put	Crude Oil		69,000		100.10
3Q 2013	Purchased	Put	Crude Oil		72,000		100.10
4Q 2013	Purchased	Put	Crude Oil		75,000		100.10

11