Atlas Pipeline Partners 8-K Reports Fourth Quarter and Full Year 2010 Results

Exhibit 99.1

Contact:	Matthew Skelly Vice President
	Investor Relations
	1845 Walnut Street
	Philadelphia, PA 19103
	(215) 832-4120
	(215) 561-5692 (facsimile)

ATLAS PIPELINE PARTNERS, L.P.

REPORTS FOURTH QUARTER AND FULL YEAR 2010 RESULTS

Philadelphia, PA, February 22, 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”), a non-GAAP measure, of $42.9 million in the fourth quarter of 2010, a decrease of 3%, as compared to $44.3 million in the fourth quarter of 2009. Adjusted EBITDA for the fourth quarter of 2009 includes $9.7 million related to Elk City, which was sold in September 2010. Excluding Elk City’s contribution to 2009 fourth quarter results, Adjusted EBITDA increased 24% versus same period last year. Excluding the historical impact of Elk City, Adjusted EBITDA was higher for the quarter and full year 2010 compared to last year’s fourth quarter and 2009 full year primarily due to higher realized natural gas liquids (“NGL”) and condensate prices as well as approximately 12% gathered volume growth across the existing business. Net loss was $10.6 million for the fourth quarter of 2010 compared with a net loss of $35.1 million for the prior year fourth quarter.

For the full year 2010, Adjusted EBITDA was $209.8 million, an increase of 20% over full year 2009 Adjusted EBITDA of $174.8 million. Net income was $280.4 million for the full year 2010, versus net income of $62.7 million for the prior year. Adjusted EBITDA excludes gains and losses from asset sales outside the ordinary course of business, option premium expense and non-cash items that impact net income. The Partnership believes this measure provides a more accurate comparison of the operating results for the periods presented.

Distributable Cash Flow, a non-GAAP measure, was $25.2 million for the fourth quarter, a 175% increase compared to the fourth quarter of 2009 Distributable Cash Flow of $9.2 million. For the full year 2010, Distributable Cash Flow was $106.8 million, an increase of 166% over the full year 2009 Distributable Cash Flow of $40.1 million. The increase was attributed to Adjusted EBITDA discussed above and lower cash interest expense for the fourth quarter and full year of 2010 offset by increased maintenance capital expenditures. Distributable Cash Flow per average common limited partner unit for the quarter was $0.47 and for full year 2010 it was $2.01.

On January 25, 2011, the Partnership declared a distribution for the fourth quarter of 2010 of $0.37 per common limited partner unit to holders of record on February 7, 2011, and payable on February 14, 2011. This distribution represents Distributable Cash Flow coverage of 1.3x for the fourth quarter of 2010. A reconciliation of non-GAAP measures, including Adjusted EBITDA and Distributable Cash Flow, is provided within the financial tables of this release.

On February 17, 2011, the Partnership completed the sale of its 49% interest in Laurel Mountain Midstream, LLC (Laurel Mountain) to Atlas Energy Resources, LLC, a wholly owned subsidiary of Atlas Energy, Inc., for $403 million, excluding post-closing adjustments. Laurel Mountain owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in the northeastern United States. At the time of the sale, the Partnership’s general partner was an indirect subsidiary of Atlas Energy, Inc.

“We are pleased to report a strong finish to 2010. Our successful quarter was categorized by overall volume growth across our business coupled with a better pricing environment for our liquids and condensate products. Additionally, we have executed on activities that are going to materially contribute to our unitholder’s distributions in 2011. First, we have added to our risk management book securing over 70% of our margin for 2011 at attractive commodity price levels. Secondly, last Friday we announced the closing of our sale of the Partnership’s interest in our Laurel Mountain joint venture for $403 million to Atlas Energy, which has since become part of Chevron. Lastly, the proceeds will create additional liquidity and flexibility to a balance sheet that is already one of the strongest in the industry. This flexibility is going to allow the Partnership to utilize its balance sheet and add to an already increasing cash flow stream for our investors; as there is significant opportunity to grow cash flow from strategic assets. The resulting accretion should increase distributions to a level that are considerably higher than currently realized. As we look back on 2010, it was clearly a transformational year for Atlas Pipeline and we intend to keep the momentum going for 2011. We thank all of our stakeholders for their support.” stated Eugene Dubay, Chief Executive Officer of the Partnership.

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Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $277.0 million as of December 31, 2010, up $232.1 million from December 31, 2009. The Partnership intends to immediately reduce the amount outstanding on the revolving credit facility to a zero balance, making the full $350 million available, less outstanding letters of credit. Total debt outstanding was reduced to $566.0 million at December 31, 2010, from $1,254.2 million at December 31, 2009, a decrease of $688.2 million. The following table summarizes the Partnership’s total liquidity and debt balance at December 31, 2010 along with the impact of the sale of Laurel Mountain. The Partnership will immediately use a portion of the proceeds to repay existing indebtedness under our revolving credit facility, with the remaining proceeds in cash and cash equivalents (in thousands):

					Pro Forma
	December 31, 2010				December 31, 2010
Impact of Laurel Mountain Sale	Balance		Impact		Balance
Cash and cash equivalents	$	164	$	343,486	$	343,650
Investment in joint venture		153,358		(153,358)		–
Current portion of long-term debt		210		–		210
Revolving credit facility		70,000		(70,000)		–
8.125% Senior notes – due 2015		272,181		–		272,181
8.750% Senior notes – due 2018		223,050		–		223,050
Other		533		–		533
Total debt	$	565,974	$	(70,000)	$	495,974
Liquidity (defined above)	$	276,947	$	413,486	$	690,433
Net debt (Total debt less cash equiv.)	$	565,810			$	152,324

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Capital Deployment and Balance Sheet Opportunities

The closing of the Laurel Mountain transaction will give the Partnership substantial flexibility as it relates to its capital structure and operational expansion projects going forward. The Partnership has reviewed its debt structure and as a result, intends to pay down the outstanding balance on its revolving credit facility and to retire some of its Senior Notes pursuant to the terms of the indentures. The Partnership expects to experience interest savings of approximately $24 million annually which, as a positive direct impact to Distributable Cash Flow, would result in a DCF per unit increase of $0.45 annually or $0.11 per quarter, a 23% increase over the fourth quarter of 2010. Additionally, the Partnership is currently evaluating meaningful organic expansion opportunities at all three of its systems as expansion will be required to serve the Partnership’s producing customers as they expand their drilling programs behind the Partnership’s systems in 2011.

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Risk Management

The Partnership continues to enhance its risk management portfolio. As of February 21, 2011, the Partnership has natural gas, natural gas liquids and condensate hedges in place for the remainder of 2011, including hedges in place for approximately 72% of associated margin value for 2011. In addition to this coverage, some protection has also recently been added for 2012. Counterparties to the Partnership’s risk management activities consist primarily 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.

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Operating Results

Gross margin from continuing operations was $60.5 million for the fourth quarter 2010 and $210.6 million for the full year 2010, compared to $51.2 million and $163.7 million for the prior year periods, respectively. 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 commodity prices, along with increased volumes on the Midkiff/Benedum and Velma systems. Year-over-year volume increases on Midkiff/Benedum are a direct result of the completion of the Partnership’s Consolidator Plant to support additional development drilling in the Permian Basin. Volumes on the Velma system increased due to production added on the new Madill to Velma gathering system. Volumes on our Chaney Dell system have increased 9.9% since the first quarter of 2010, primarily related to our expansion into Kansas and increased producer activity in the area.

Midkiff/Benedum

The Midkiff/Benedum system’s average natural gas processed volume was 169.4 million cubic feet per day (“Mmcfd”) and 163.5 Mmcfd for the fourth quarter and full year 2010, respectively, compared with 150.1 Mmcfd and 149.7 Mmcfd for the prior year comparable quarter and prior year, respectively. Average gross NGL production volumes increased to 27,110 barrels per day (“bpd”) and 26,678 bpd for the fourth quarter and full year 2010, respectively, up 23.1% and 25.5% when compared to the fourth quarter and full prior year, respectively. Increased volumes are primarily due to the completion of the new Consolidator Plant, which processes gas in the growing Spraberry and Wolfberry Trends. The plant offers increased capacity and higher ethane and propane recoveries over the legacy facility. The Partnership expects volumes on this system to continue to increase as its partner, Pioneer Natural Resources Company (NYSE: PXD), continues to pursue its drilling plan for 2011 and beyond. The Partnership is also seeing significant growth in natural gas volumes from other producers in the Spraberry and Wolfberry Trends, including COG Operating, LLC, and Endeavor Energy Resources, LP.

Chaney Dell

The Chaney Dell system had average NGL production of 14,204 bpd, which represents a 9.6% increase for the fourth quarter 2010 from the prior year comparable period, and 12,395 bpd, which represents a 7.6% reduction for the full year 2010 from 2009. The Partnership completed the Woolsey expansion of its Chaney Dell system into Kansas during June 2010, on-time and on-budget, and experienced an increase in processed gas volumes due to this project, as well as increased production from other producers on the system, including Chesapeake Energy Marketing, Inc. and Sandridge Exploration and Production, LLC. The Partnership expects volumes to continue to increase in 2011 as volumes from Kansas continue to be added to the system.

Velma

The Velma system’s average natural gas processed volume was 87.7 Mmcfd and 78.6 Mmcfd for the fourth quarter and full year 2010, respectively, an increase of approximately 15.9% and 6.3% compared with the comparable quarter and full year in the prior year, respectively. The increase is primarily due to new production gathered on the Madill to Velma pipeline system. Gathered volumes were up 16.6 Mmcfd, or 21.4% compared to the same quarter last year, and up 8.1 Mmcfd, or 10.6% compared to prior year. Average NGL production increased to 10,608 bpd and 9,218 bpd, for the fourth quarter and full year 2010, respectively, up approximately 25.5% and 12.0 %, compared to 8,450 bpd and 8,232 bpd for the prior year fourth quarter and prior year due to the increased processed volumes.

Appalachia

Volumes on the Laurel Mountain system averaged 124.3 Mmcfd and 109.5 Mmcfd during the fourth quarter 2010 and full year 2010, respectively, up 26.6% and 12.9% compared to the fourth quarter 2009 and full year 2009, respectively.

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Corporate and Other

General and administrative expense, net of non-cash compensation, decreased 14.8% to $9.8 million for the fourth quarter 2010, and decreased 16.5% to $30.5 million for the full year 2010 compared with $11.5 million and $36.6 million for the prior year fourth quarter and prior year, respectively. The decrease is attributable to continued focus in costs and efficiencies reflective of our operating strategy.

Net of deferred financing costs, interest expense decreased to $11.7 million and $81.1 million for the fourth quarter 2010 and full year 2010, respectively, down 55.4% and 15.3%, as compared with $26.3 million and $95.8 million for the fourth quarter 2009 and full year 2009, respectively. This decrease was primarily due to a $688.2 million reduction in debt outstanding since December 31, 2009.

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Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s fourth quarter and full year 2010 results on Tuesday, February 22, 2011 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website atwww.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 12:00 pm ET on Tuesday, February 22, 2011. To access the replay, dial 1-888-286-8010 and enter conference code 45687751.

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. For more information, visit the Partnership’s website at www.atlaspipeline.com or contactIR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: AHD), formerly Atlas Pipeline Holdings, L.P., is a master limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P. (NYSE: APL), 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, AHD 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 our website athttp://www.atlasenergy.com, or contact Investor Relations atInvestorRelations@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 process 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.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary⁽¹⁾

(unaudited; in thousands)

	Three Months Ended December 31,					Year Ended December 31,
	2010		2009(2)			2010		2009(2)
Revenue:
Natural gas and liquids	$	248,070	$	201,528		$	890,048	$	636,231
Transportation, processing and other fees(3)		11,149		9,277			41,093		59,075
Other income (loss), net		(6,129)		(8,769)			4,447		(22,701)
Total revenue and other income (loss), net		253,090		202,036			935,588		672,605
Costs and expenses:
Natural gas and liquids		198,720		159,072			720,215		527,730
Plant operating		12,178		12,501			48,670		45,566
Transportation and compression		340		401			1,061		6,657
General and administrative(4)(5)		9,807		11,507			30,537		36,578
General and administrative – non-cash unit-based compensation(4)		693		205			3,484		702
Depreciation and amortization		19,250		20,117			74,897		75,684
Goodwill and other asset impairment		–		10,325			–		10,325
Interest		13,188		27,843			91,632		103,787
Total costs and expenses		254,176		241,971			970,496		807,029
Equity income in joint venture		783		1,903			4,920		4,043
Gain (loss) on asset sale and other		(10,729)		–			(10,729)		108,947
Income from continuing operations		(11,032)		(38,032)			(40,717)		(21,434)
Discontinued operations:
Gain on sale of discontinued operations		610		–			312,102		53,571
Earnings from discontinued operations		(139)		2,907			9,053		30,577
Income from discontinued operations		471		2,907			321,155		84,148
Net income		(10,561)		(35,125)			280,438		62,714
Income attributable to non-controlling interests		(1,400)		(1,101)			(4,738)		(3,176)
Preferred unit dividends		(540)		–			(780)		(900)
Net income (loss) attributable to common limited partners and the general partner	$	(12,501)	$	(36,226)	��	$	274,920	$	58,638

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

(2) Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.

(3) Includes affiliate revenues related to transportation and processing provided to Atlas Energy Resources, LLC.

(4) 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-K, includes approximately $2.2 million associated with the conversion of equity-indexed cash bonus units into phantom units during the year ended December 31, 2010. This conversion resulted in a reduction of general and administrative costs and an increase to general and administrative – non cash unit based compensation during the year ended December 31, 2010.

(5) Includes compensation reimbursement to affiliates.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)

	Three Months Ended December 31,				Year Ended December 31,
	2010		2009(1)		2010		2009(1)
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	(0.24)	$	(0.76)	$	(0.85)	$	(0.52)
Discontinued operations		0.01		0.06		5.92		1.71
	$	(0.23)	$	(0.70)	$	5.07	$	1.19
Diluted:
Continuing operations	$	(0.24)	$	(0.76)	$	(0.85)	$	(0.52)
Discontinued operations Diluted		0.01		0.06		5.92		1.71
	$	(0.23)	$	(0.70)	$	5.07	$	1.19
Weighted average common limited partner units outstanding:
Basic		53,317		50,511		53,166		48,299
Diluted		53,317		50,511		53,166		48,299
Summary Cash Flow Data
Cash provided by (used in) operating activities	$	5,142	$	4,371	$	106,427	$	55,853
Cash provided by (used in) investing activities		(35,135)		(17,665)		594,753		241,123
Cash provided by (used in) financing activities		29,991		9,054		(702,037)		(297,400)
Capital Expenditure Data:
Maintenance capital expenditures	$	4,443	$	2,018	$	10,921	$	3,750
Expansion capital expenditures		10,115		10,774		35,715		106,524
Cash contributions to Laurel Mountain JV		19,600		1,680		26,514		1,680
Total	$	34,158	$	14,472	$	73,150	$	111,954

(1) Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

ASSETS	December 31, 2010		December 31, 2009(1)
Current assets:
Cash and cash equivalents	$	164	$	1,021
Other current assets		114,877		94,377
Current assets of discontinued operations		–		22,746
Total current assets		115,041		118,144
Property, plant and equipment, net		1,341,002		1,327,704
Intangible assets, net		126,379		149,481
Investment in joint venture		153,358		132,990
Long-term portion of derivative asset		–		361
Other assets, net		29,068		30,253
Long-term assets of discontinued operations		–		379,030
	$	1,764,848	$	2,137,963
LIABILITIES AND EQUITY
Current liabilities	$	151,606	$	148,729
Long-term portion of derivative liability		5,608		11,126
Long-term debt, less current portion		565,764		1,254,183
Other long-term liability		223		398
Commitments and contingencies
Total Partners’ capital		1,074,184		754,452
Non-controlling interest		(32,537)		(30,925)
Total Equity		1,041,647		723,527
	$	1,764,848	$	2,137,963

(1) Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

	Three Months Ended December 31,				Year Ended December 31,
	2010		2009(1)		2010		2009(1)
Reconciliation of net income (loss) to other non-GAAP measures(2):
Net income (loss)	$	(10,561)	$	(35,125)	$	280,438	$	62,714
Income attributable to non-controlling interests		(1,400)		(1,101)		(4,738)		(3,176)
Depreciation and amortization		19,250		20,117		74,897		75,684
Interest expense(3)		13,188		28,286		92,236		104,230
Depreciation, amortization and interest of discontinued operations		–		4,720		12,069		19,394
EBITDA		20,477		16,897		454,902		258,846
Adjust for cash flow from investment in joint venture		2,007		751		6,146		267
Non-cash (gain) loss on derivatives		5,996		11,227		(10,166)		74,644
Early termination cash derivative expense(4)		–		–		22,401		2,260
Premium expense on derivative instruments		3,592		3,474		21,123		9,693
(Gain) loss on asset sales and other		10,119		–		(301,373)		(162,518)
Goodwill and other asset impairment		–		10,325		–		10,325
Other non-cash (gains) losses(5)		661		(357)		3,138		(3,198)
Discontinued operations adjustments(6)		–		2,027		13,628		(15,511)
Adjusted EBITDA		42,852		44,344		209,799		174,808
Interest expense, net of ineffective interest rate swaps(3)		(13,188)		(28,286)		(92,236)		(104,230)
Amortization of deferred financing costs		1,457		1,567		10,545		8,016
Preferred unit dividends		(540)		–		(780)		(900)
Maintenance capital expenditures		(4,443)		(2,018)		(10,921)		(3,750)
Premiums paid for derivative instruments		(656)		(5,240)		(8,428)		(30,478)
Discontinued operations adjustments(7)		(273)		(1,208)		(1,216)		(3,396)
Distributable Cash Flow	$	25,209	$	9,159	$	106,763	$	40,070

(1) Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems and modifications to the Partnership’s credit facility Consolidated EBITDA definition and covenant calculations.

(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) 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 years ended December 31, 2010 and 2009, the Partnership made net payments of $33.7 million and $5.0 million, respectively, related to the early termination of derivative contracts, including $11.3 million and $2.7 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) Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; and (ii) interest expense.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights⁽¹⁾

	Three Months Ended December 31,						Year Ended December 31,
	2010			2009			2010			2009
Pricing
Mid-Continent Weighted Average NGL sales ($/gallon):
Conway hub		$	1.00		$	0.95		$	0.92		$	0.68
Mt. Belvieu hub			1.11			1.01			1.03			0.77
Unhedged natural gas sales ($/Mcf):
Velma			4.10			4.06			4.14			3.24
Chaney Dell			4.07			4.14			4.13			3.25
Midkiff/Benedum			4.09			4.03			4.10			3.35
Weighted Average			4.08			4.09			4.12			3.28
Unhedged NGL sales ($/gallon):
Velma			1.01			0.93			0.90			0.69
Chaney Dell			1.06			0.94			0.94			0.69
Midkiff/Benedum			1.14			1.06			1.02			0.83
Weighted Average			1.08			0.98			0.97			0.73
Unhedged Condensate sales ($/barrel):
Velma			88.29			74.73			78.28			59.80
Chaney Dell			80.17			72.57			72.67			55.07
Midkiff/Benedum			83.59			75.53			75.57			60.35
Weighted Average			83.44			74.28			75.08			58.21
Volumes:(1)
Appalachia
Laurel Mountain system:
Average throughput volume – mcfd(2)			124,307			98,163			109,480			96,975
Tennessee system
Average throughput volume – mcfd			8,660			9,378			8,740			7,907
Mid-Continent
Velma:
Gathered gas volume – mcfd			94,389			77,741			84,455			76,378
Processed gas volume – mcfd			87,732			75,687			78,606			73,940
Residue gas volume – mcfd			71,792			59,510			64,138			58,350
NGL volume – bpd			10,608			8,450			9,218			8,232
Condensate volume – bpd			431			360			416			377
Chaney Dell:
Gathered gas volume – mcfd			244,033			234,936			228,684			270,703
Processed gas volume – mcfd			230,717			212,309			214,695			215,374
Residue gas volume – mcfd			207,758			198,866			193,200			228,261
NGL volume – bpd			14,204			12,958			12,395			13,418
Condensate volume – bpd			735			712			697			824
Midkiff/Benedum(2):
Gathered gas volume – mcfd			184,418			156,412			178,111			159,568
Processed gas volume – mcfd			169,413			150,071			163,475			149,656
Residue gas volume – mcfd			109,659			97,961			105,982			101,788
NGL volume – bpd			27,110			22,017			26,678			21,261
Condensate volume – bpd			1,100			788			1,289			1,265

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

(2) Includes 100% of the throughput volume of Laurel Mountain and Midkiff/Benedum.

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions through December 31, 2012

(as of February 21, 2011 )

Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2012, which encompass APL’s price risk management position in its entirety.

NATURAL GAS HEDGES

Swap Contracts

	Production Period	Purchased /Sold	Commodity	MMBTU		Avg. Fixed Price
	1Q 2011	Sold	Natural Gas		800,000		4.54
	1Q 2011	Sold	Natural Gas Basis		480,000		(0.73	)
	1Q 2011	Purchased	Natural Gas Basis		480,000		(0.76	)
	2Q 2011	Sold	Natural Gas		900,000		4.41
	2Q 2011	Sold	Natural Gas Basis		480,000		(0.73	)
	2Q 2011	Purchased	Natural Gas Basis		480,000		(0.76	)
	3Q 2011	Sold	Natural Gas		1,200,000		4.54
	3Q 2011	Sold	Natural Gas Basis		480,000		(0.73	)
	3Q 2011	Purchased	Natural Gas Basis		480,000		(0.76	)
	4Q 2011	Sold	Natural Gas		1,200,000		4.91
	4Q 2011	Sold	Natural Gas Basis		480,000		(0.73	)
	4Q 2011	Purchased	Natural Gas Basis		480,000		(0.76	)
NATURAL GAS LIQUIDS AND CONDENSATE HEDGES Swap Contracts - NGLS
	Production Period	Purchased /Sold	Commodity	Gallons		Avg. Fixed Price
	1Q 2011	Sold	Ethane		5,418,000		0.49
	1Q 2011	Sold	Propane		3,906,000		1.19
	2Q 2011	Sold	Ethane		5,040,000		0.50
	2Q 2011	Sold	Propane		4,284,000		1.11
	3Q 2011	Sold	Propane		4,284,000		1.16
	3Q 2011	Sold	Isobutane		504,000		1.61
	3Q 2011	Sold	Normal Butane		1,386,000		1.57
	3Q 2011	Sold	Natural Gasoline		3,276,000		2.04
	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
	2Q 2012	Sold	Propane		1,008,000		1.19
	3Q 2012	Sold	Propane		1,008,000		1.19
Swap Contracts - Crude
	Production Period	Purchased /Sold	Commodity	Barrels		Avg. Fixed Price
	1Q 2011	Sold	Crude		39,000	$	92.61
	2Q 2011	Sold	Crude		39,000		93.13
	3Q 2011	Sold	Crude		30,000		90.60
	4Q 2011	Sold	Crude		30,000		90.75
	1Q 2012	Sold	Crude		21,000		99.50
	2Q 2012	Sold	Crude		21,000		99.50
	3Q 2012	Sold	Crude		21,000		99.50
	4Q 2012	Sold	Crude		21,000		99.50

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Unaudited Current Commodity Risk Management Positions through December 31, 2012

(as of February 21, 2011 )

NATURAL GAS LIQUIDS AND CONDENSATE HEDGES

Option Contracts – NGLs

	Production Period	Purchased/Sold	Type		Commodity	Gallons		Avg. Strike Price
	2Q 2011	Purchased	Put		Propane		4,410,000		1.21
	3Q 2011	Purchased	Put	��	Propane		4,410,000		1.22
Option Contracts – Crude
	Production Period	Purchased/Sold	Type		Commodity	Barrels		Avg. Strike Price
	1Q 2011	Purchased	Put		Crude Oil		210,000		89.00
	1Q 2011	Sold	Call		Crude Oil		169,500		93.80
	1Q 2011	Purchased	Call		Crude Oil		63,000		123.47
	2Q 2011	Purchased	Put		Crude Oil		210,000		89.00
	2Q 2011	Sold	Call		Crude Oil		169,500		93.35
	2Q 2011	Purchased	Call		Crude Oil		63,000		125.20
	3Q 2011	Purchased	Put		Crude Oil		84,000		95.00
	3Q 2011	Sold	Call		Crude Oil		169,500		93.35
	3Q 2011	Purchased	Call		Crude Oil		63,000		125.20
	4Q 2011	Purchased	Put		Crude Oil		54,000		95.80
	4Q 2011	Sold	Call		Crude Oil		169,500		93.35
	4Q 2011	Purchased	Call		Crude Oil		63,000		125.20
	1Q 2012	Purchased	Call		Crude Oil		45,000		125.20
	1Q 2012	Sold	Call		Crude Oil		124,500		94.69
	2Q 2012	Purchased	Call		Crude Oil		45,000		125.20
	2Q 2012	Sold	Call		Crude Oil		124,500		94.69
	3Q 2012	Purchased	Call		Crude Oil		45,000		125.20
	3Q 2012	Sold	Call		Crude Oil		124,500		94.69
	4Q 2012	Purchased	Call		Crude Oil		45,000		125.20
	4Q 2012	Sold	Call		Crude Oil		124,500		94.69

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