Atlas Pipeline Partners 8-K Reports Fourth Quarter and Record

Exhibit 99.1

ATLAS PIPELINE PARTNERS, L.P.

REPORTS FOURTH QUARTER AND RECORD

FULL-YEAR 2006 RESULTS

PARTNERSHIP REPORTS RECORD FULL-YEAR REVENUES AND EARNINGS;

ANNOUNCES EXPANSION PROJECTS IN MID-CONTINENT REGION

Philadelphia, PA, February 26, 2007 – Atlas Pipeline Partners, L.P. (NYSE: APL – the “Partnership”)today reported record earnings before interest, income taxes, depreciation and amortization (“EBITDA”), a non-GAAP measure, of $80.0 million for the full year 2006, compared with $53.1 million in 2005, an increase of $26.9 million, or 51%, from the prior year. Net income for the full year 2006 was $33.7 million, an increase of 31% over the prior year. Revenues rose to a record level of $464.7 million, an increase of $93.2 million, or 25%, compared with the prior year. The Partnership also achieved record system wide volumes of approximately 705.0 million cubic feet per day (“MMcfd”) for the fourth quarter 2006 compared with 639.5 MMcfd for the prior year quarter, an increase of 10%.

EBITDA for the fourth quarter 2006 was $20.2 million compared with $21.3 million for the prior year fourth quarter, a decrease of $1.1 million. Net income for the fourth quarter 2006 was $7.5 million, or $0.22 per diluted common limited partner unit, compared with $10.9 million for the fourth quarter 2005, or $0.69 per diluted common limited partner unit. Fourth quarter results were adversely affected by unfavorable movements in commodity prices during the quarter partially offset by increased volumes, a third party’s delay in installing the natural gas liquids transportation pipeline from the new Sweetwater processing facility resulting in minimal contributions to the quarter from Sweetwater, and a one-time charge of $1.1 million for employee expense relating to our parent company’s shift from a September 30 fiscal year to a calendar year financial reporting period.

The Partnership has paid a quarterly cash distribution for the fourth quarter 2006 of $0.86 per common limited partner unit. This brings distributions declared per common limited partner unit for the year ended December 31, 2006 to $3.40, an increase of $0.24, or 8%, from the prior year.

Due to the continued growth in transmission and gathering volumes, the Partnership has begun efforts on several organic growth projects to strengthen its asset base in the Mid-Continent region. First, the Partnership will commence construction of an additional 60 MMcfd expansion of its 120 MMcfd Sweetwater processing facility. Concurrent with this expansion, the Partnership will significantly expand its gas gathering system in western Oklahoma and the Texas Panhandle. The Partnership expects the expansion of the processing facility and gathering systems to be substantially completed by the first half of 2008. Additionally, the Partnership will increase compression and loop certain existing pipelines on its NOARK interstate pipeline system (“NOARK”), the combination of which will increase throughput capacity to approximately 450 MMcfd. This expansion will consist of 6,000 horsepower of mainline compression and 15 miles of looped 12 inch high pressure pipeline. The targeted completion timeframe is early 2008. The Partnership also continues to pursue the expansion and extension of the NOARK pipeline, as previously disclosed, and will pursue this project aggressively.

Finally, in reviewing its financial results for the year ended December 31, 2006, the Partnership determined that previously reported net income for the third quarter of 2006 and nine months ended September 30, 2006 should be increased by $2.3 million. This increase was due to the recognition of a gain with respect to certain financial hedge instruments under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This adjustment has been reflected within the financial information presented. The Partnership will file an amendment to its Form 10-Q for September 30, 2006 to reflect this adjustment prior to the filing of its Form 10-K for December 31, 2006.

Segment Analysis

Mid-Continent

The Mid-Continent segment recognized total revenue of $109.2 million for the fourth quarter 2006, a decrease of $19.1 million from the fourth quarter 2005. This decrease was principally attributable to a decrease in commodity prices. For the Elk City/Sweetwater system, which includes volumetric data from the recently constructed Sweetwater gas plant, gross natural gas gathered volume for the fourth quarter 2006 averaged 295.2 MMcfd, an 11% increase from the fourth quarter 2005. The Elk City/Sweetwater system connected 10 new wells to its gathering system during the fourth quarter 2006 and 64 new wells for the year ended December 31, 2006. For the NOARK system, average Ozark Gas Transmission throughput volume was 288.9 MMcfd during the fourth quarter 2006, a 13% increase from the fourth quarter 2005. The Velma system’s processed natural gas volume averaged 55.9 MMcfd for the fourth quarter 2006, a slight decrease of 1% from the prior year quarter of 56.5 MMcfd. The Velma system connected 7 new wells to its gas gathering system during the fourth quarter 2006 and 60 new wells for the year ended December 31, 2006. Also, the Partnership recorded a one-time $2.9 million gain from an insurance claim settlement related to fire damage sustained during 2006 at a Velma compressor station.

The Mid-Continent segment recognized total revenue of $433.8 million for the year ended December 31, 2006, an increase of $87.1 million from the prior year. This increase was principally attributable to a full year of revenue contribution from the acquisitions of the NOARK and Elk City systems. For the Elk City/Sweetwater system, gross natural gas gathered volume for calendar year 2006 averaged 277.1 MMcfd, an 11% increase from the prior year. For the NOARK system, average Ozark Gas Transmission throughput volume was 249.6 MMcfd for calendar year 2006. These favorable variances for the year were partially offset by a decrease in Velma system revenue due to a decrease in commodity prices and lower processed volume. Velma’s processed natural gas volume averaged 58.1 MMcfd for calendar year 2006, a decrease of 7% from the prior year amount of 62.5 MMcfd. The decrease in Velma system processed volume between periods was principally due to the expiration of a short-term low-margin gathering and processing agreement. The impact of Velma’s processed volume decline on total revenue was partially offset by an increase in the recovery percentage of natural gas liquids at the Velma plant compared with the prior year.

Appalachia

Total revenue for the Appalachia system was $7.6 million for the fourth quarter 2006, a 5% decrease from $8.0 million for the fourth quarter 2005, due principally to a decrease in realized natural gas prices between periods, partially offset by higher throughput volume. Throughput volume increased to 63.1 MMcfd for the fourth quarter 2006 compared with 56.4 MMcfd for the fourth quarter 2005 due to new wells connected to the Appalachia gathering system. Average transportation rate per thousand cubic feet (“mcf”) was $1.30 for the fourth quarter 2006, a 15% decrease from $1.53 per mcf for the prior year fourth quarter. During the fourth quarter 2006, 190 new wells were connected to the Appalachia gathering system compared with 91 wells connected during the comparable prior year quarter. Overall, 711 new wells were connected to the Appalachia gathering system for the year ended December 31, 2006 as compared with 451 wells connected for the prior year. Appalachia segment profit was $4.4 million for the fourth quarter 2006, or 29% of total segment operating profit for the period, compared with $5.6 million, or 33% of total segment operating profit for the prior year fourth quarter.

Total revenue for the Appalachia system increased to $30.9 million for the year ended December 31, 2006, a 24% increase from $24.8 million for the prior year, due principally to higher throughput volume and an increase in realized natural gas prices between periods. Throughput volume increased to 61.9 MMcfd for calendar year 2006 compared with 55.2 MMcfd for calendar year 2005 due to new wells connected to the Appalachia gathering system. Average transportation rate per mcf was $1.34 for 2006, an 11% increase from $1.21 per mcf for the prior year.

Corporate and Other

General and administrative expense, including amounts reimbursed to affiliates, increased $2.1 million to $6.6 million for the fourth quarter 2006 from $4.5 million for the fourth quarter 2005. This increase was primarily related to a one-time charge of $1.1 million for employee expense relating to our parent company’s shift from a September 30 fiscal year to a calendar year financial reporting period, an increase in non-cash compensation expense related to vesting of phantom and common unit awards and higher costs associated with managing the Partnership, including management of the NOARK acquisition. Depreciation and amortization increased $0.9 million to $6.3 million for the fourth quarter 2006 due primarily to the depreciation and amortization related to the NOARK assets acquired during 2005 and 2006 and the current year expansion capital expenditures.

Interest expense increased to $6.4 million for the fourth quarter 2006, an increase of $0.7 million from the prior year fourth quarter. This increase was primarily related to interest associated with the Partnership’s May 2006 issuance of $35.0 million principal amount of 10-year senior unsecured notes and a full quarter of interest expense for the Partnership’s $250.0 million principal amount of senior unsecured notes, which were issued in December 2005, partially offset by a decrease in interest associated with borrowings under the credit facility. At December 31, 2006, the Partnership had $324.1 million of total debt, including the $285.0 million of senior unsecured notes and $38.0 million of outstanding borrowings under its $225.0 million credit facility.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s fourth quarter results on Tuesday morning, February 27, 2007 at 9:00 am EDT by going to the home page of the Partnership’s website atwww.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 11:00 am EDT on Tuesday, February 27, 2007 until 11:59 pm on Tuesday, March 27, 2007. To access the replay, dial 1-888-286-8010 and enter conference code 34068310.

Atlas Pipeline Partners, L.P. is active in the transmission, gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, Arkansas, northern Texas and the Texas panhandle, the Partnership owns and operates approximately 1,900 miles of active intrastate gas gathering pipeline and a 565-mile interstate natural gas pipeline. The Partnership also operates three gas processing plants and a treating facility in Velma, Elk City, Sweetwater and Prentiss, Oklahoma where natural gas liquids and impurities are removed. In Appalachia, it owns and operates approximately 1,600 miles of natural gas gathering pipelines in western Pennsylvania, western New York and eastern Ohio. For more information, visit our website atwww.atlaspipelinepartners.com or contactbbegley@atlaspipelinepartners.com.

Atlas Pipeline Holdings, L.P. (NYSE: AHD)is the parent company of Atlas Pipeline Partners, L.P.’s general partner and owner of 1,641,026 limited partner units of Atlas Pipeline Partners, L.P. For more information, please contact investor relations atbbegley@atlasamerica.com.

Atlas America, Inc.,(NASDAQ: ATLS)owns an 80% common unit interest and all of the Class A and management incentive interests in Atlas Energy Resources, LLC. Atlas America also owns an 83% interest in Atlas Pipeline Holdings, L.P.

Statements made in this release include forward-looking statements, which involve substantial risks and uncertainties. The Partnership’s actual results, performance or achievements could differ materially from those expressed or implied in this release as a result of certain factors, including competition within the energy industry, climactic conditions and the price of gas in the Appalachian and Mid-Continent areas, actual versus projected volumetric production from wells connected to the Partnership’s gas gathering pipeline system, and the cost of supplies and services in the energy industry.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary

(in thousands, except per unit amounts)

INCOME STATEMENT	Three Months Ended December 31,					Year Ended December 31,
	2006(1)			2005		2006(1)			2005
Revenue:
Natural gas and liquids	$	96,388		$	122,029	$	397,082		$	340,297
Transportation and compression – affiliates		7,530			7,899		30,189			24,346
Transportation and compression – third parties		9,853			5,909		30,735			5,963
Interest income and other		3,064			542		6,686			894
Total revenue and other income		116,835			136,379		464,692			371,500
Costs and expenses:
Natural gas and liquids		81,722			103,602		334,299			288,180
Plant operating		4,716			3,315		15,722			10,557
Transportation and compression		3,609			1,884		12,013			4,053
General and administrative		6,290			4,062		18,990			11,825
Compensation reimbursement – affiliates		336			418		2,319			1,783
Depreciation and amortization		6,309			5,459		22,994			13,954
Interest		6,381			5,697		24,572			14,175
Minority interest in NOARK		—			1,083		118			1,083
Other		—			—		—			138
Total costs and expenses		109,363			125,520		431,027			345,748
Net income		7,472			10,859		33,665			25,752
Preferred unit imputed dividend cost		(636	)		—		(1,898	)		—
Net income attributable to common limited partners and the general partner	$	6,836		$	10,859	$	31,767		$	25,752
Allocation of net income attributable to common limited partners and the general partner:
Common limited partners’ interest	$	2,894		$	7,352	$	16,558		$	16,355
General partner’s interest		3,942			3,507		15,209			9,397
Net income attributable to common limited partners and the general partner	$	6,836		$	10,859	$	31,767		$	25,752
Net income attributable to common limited partners per unit:
Basic	$	0.22		$	0.70	$	1.29		$	1.86
Diluted	$	0.22		$	0.69	$	1.27		$	1.84
Weighted average common limited partner units outstanding:
Basic		13,080			10,535		12,884			8,808
Diluted		13,284			10,638		13,053			8,872
Capital Expenditure data:
Maintenance capital expenditures	$	1,728		$	812	$	4,649		$	1,922
Expansion capital expenditures		20,360			17,167		79,182			50,576
Total	$	22,088		$	17,979	$	83,831		$	52,498
	December 31,
Balance Sheet data (at period end):	2006			2005
Cash and cash equivalents	$	1,795		$	34,237
Total assets		786,884			742,726
Total debt		324,083			298,625
Total partners’ capital		379,134			329,510

⁽¹⁾ Previously reported net income for the third quarter of 2006 and nine months ended September 30, 2006 has been increased by $2.3 million. This adjustment has been reflected within the financial information presented. The Partnership will file an amendment to its Form 10-Q for September 30, 2006 to reflect this adjustment prior to the filing of its Form 10-K for December 31, 2006.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Segment Information

(in thousands)

	Three Months Ended December 31,						Year Ended December 31,
	2006(1)			2005			2006(1)			2005
Mid-Continent
Revenue:
Natural gas and liquids	$	96,388		$	122,029		$	397,082		$	340,297
Transportation and compression		9,836			5,880			30,653			5,880
Interest income and other		2,980			436			6,078			513
Total revenue and other income		109,204			128,345			433,813			346,690
Costs and expenses:
Natural gas and liquids		81,722			103,602			334,299			288,180
Plant operating		4,716			3,315			15,722			10,557
Transportation and compression		2,273			952			7,067			952
General and administrative		4,788			3,068			13,776			7,375
Minority interest in NOARK		—			1,083			118			1,083
Depreciation and amortization		5,288			4,710			19,322			11,307
Total costs and expenses		98,787			116,730			390,304			319,454
Segment profit	$	10,417		$	11,615		$	43,509		$	27,236
Appalachia
Revenue:
Transportation and compression – affiliates	$	7,530		$	7,899		$	30,189		$	24,346
Transportation and compression – third parties		17			29			82			83
Interest income and other		84			106			608			381
Total revenue and other income		7,631			8,034			30,879			24,810
Costs and expenses:
Transportation and compression		1,336			932			4,946			3,101
General and administrative		919			707			3,767			3,117
Depreciation and amortization		1,021			749			3,672			2,647
Total costs and expenses		3,276			2,388			12,385			8,865
Segment profit	$	4,355		$	5,646		$	18,494		$	15,945
Reconciliation of segment profit to net income
Segment profit:
Mid-Continent	$	10,417		$	11,615		$	43,509		$	27,236
Appalachia		4,355			5,646			18,494			15,945
Total segment profit		14,772			17,261			62,003			43,181
Corporate general and administrative expenses		(919	)		(705	)		(3,766	)		(3,116	)
Interest expense		(6,381	)		(5,697	)		(24,572	)		(14,175	)
Other		—			—			—			(138	)
Net income	$	7,472		$	10,859		$	33,665		$	25,752

⁽¹⁾ Previously reported net income for the third quarter of 2006 and nine months ended September 30, 2006 has been increased by $2.3 million. This adjustment has been reflected within the financial information presented. The Partnership will file an amendment to its Form 10-Q for September 30, 2006 to reflect this adjustment prior to the filing of its Form 10-K for December 31, 2006.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

(in thousands)

	Three Months Ended December 31,						Year Ended December 31,
	2006(1)			2005			2006(1)			2005
Reconciliation of net income to adjusted net income:
Net income	$	7,472		$	10,859		$	33,665		$	25,752
Effect of prior period items(2)		—			(902	)		1,090			(1,090	)
Adjusted net income	$	7,472		$	9,957		$	34,755		$	24,662
Reconciliation of net income to non-GAAP measures(3):
Net income	$	7,472		$	10,859		$	33,665		$	25,752
Depreciation and amortization		6,309			5,459			22,994			13,954
Minority interest share of depreciation and amortization and interest expense for NOARK		—			(735	)		(1,200	)		(735	)
Interest expense		6,381			5,697			24,572			14,175
EBITDA		20,162			21,280			80,031			53,146
Effect of prior period items(2)		—			(902	)		1,090			(1,090	)
Adjusted EBITDA		20,162			20,378			81,121			52,056
Interest expense		(6,381	)		(5,697	)		(24,572	)		(14,175	)
Minority interest share of interest expense for NOARK		—			490			938			490
Non-cash compensation expense		2,190			1,863			6,315			4,672
Amortization of deferred financing costs (included within interest expense)		545			399			2,298			2,140
Maintenance capital expenditures		(1,728	)		(812	)		(4,649	)		(1,922	)
Distributable cash flow	$	14,788		$	16,621		$	61,451		$	43,261

(1) In reviewing its financial results for the year ended December 31, 2006, the Partnership determined that previously reported net income for the third quarter of 2006 and nine months ended September 30, 2006 should be increased by $2.3 million. This increase was due to the recognition of a gain with respect to certain financial hedge instruments under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This adjustment has been reflected within the financial information presented. The Partnership will file an amendment to its Form 10-Q for September 30, 2006 to reflect this adjustment prior to the filing of its Form 10-K for December 31, 2006.

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

(3) EBITDA and distributable cash flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of the Partnership believes that EBITDA and distributable cash flow provide additional information for evaluating the Partnership’s ability to make distributions to its unitholders and the general partner, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. EBITDA is also a financial measurement that, with certain negotiated adjustments, is utilized within the Partnership’s financial covenants under its credit facility. EBITDA and distributable cash flow are not measures of financial performance under GAAP and, accordingly, should not be considered as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Operating Highlights

	Three Months Ended December 31,				Year Ended December 31,
	2006		2005		2006		2005
Mid-Continent – Velma System
Natural Gas
Gross natural gas gathered – mcfd		57,835		61,093		60,682		67,075
Gross natural gas processed – mcfd		55,909		56,475		58,132		62,538
Gross residue natural gas – mcfd		43,758		46,160		45,466		50,880
Natural Gas Liquids
Gross NGL sales – bpd		6,087		6,141		6,423		6,643
Condensate
Gross condensate sales – bpd		143		219		193		256
Mid-Continent – Elk City/Sweetwater System
Natural Gas
Gross natural gas gathered – mcfd		295,181		266,280		277,063		250,717
Gross natural gas processed – mcfd		213,033		124,196		154,047		119,324
Gross residue natural gas – mcfd		198,263		113,935		140,969		109,553
Natural Gas Liquids
Gross NGL sales – bpd		7,539		5,277		6,400		5,303
Condensate
Gross condensate sales – bpd		184		137		140		127
Mid-Continent – NOARK System
Ozark Gas Transmission throughput – mcfd		288,897		255,777		249,581		255,777
Appalachia
Throughput – mcfd		63,134		56,391		61,892		55,204
Average transportation rate per mcf	$	1.30	$	1.53	$	1.34	$	1.21

Mcf – thousand cubic feet

Mcfd – thousand cubic feet per day

Bpd – barrels per day

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Mid-Continent Segment Hedge Positions

(as of February 26, 2007)

Natural Gas Liquids Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(gallons)	(per gallon)
2007	91,224,000	$	0.879
2008	33,012,000		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	693,600	38,744,000	$	60.00	Puts purchased
2008	693,600	38,744,000		84.00	Calls sold
2009	720,000	40,219,000		60.00	Puts purchased
2009	720,000	40,219,000		81.00	Calls sold

Natural Gas Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(MMBTU)(1)	(per MMBTU) (1)
2007	1,080,000	$	7.255
2008	240,000		7.270
2009	480,000		8.000

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(MMBTU)(1)	(per MMBTU)(1)
2007	1,080,000	$	(0.535	)
2008	240,000		(0.555	)
2009	480,000		(0.540	)

Natural Gas Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price
	(MMBTU)(1)	(per MMBTU)(1)
2007	6,960,000	$	9.115	(2)
2008	4,056,000		8.831	(3)
2009	2,880,000		8.343

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price
	(MMBTU)(1)	(per MMBTU)(1)
2007	6,960,000	$	(0.903	)
2008	4,056,000		(1.028	)
2009	2,880,000		(0.592	)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Current Mid-Continent Segment Hedge Positions

(as of February 26, 2007)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price
	(barrels)	(per barrel)
2007	77,900	$	56.175
2008	65,400		59.424
2009	33,000		62.700

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price	Option Type
	(barrels)	(per barrel)
2007	13,200	60.000	Puts purchased
2007	13,200	73.380	Calls sold
2008	43,800	60.000	Puts purchased
2008	43,800	79.545	Calls sold
2009	30,000	60.000	Puts purchased
2009	30,000	71.250	Calls sold

⁽¹⁾ MMBTU represents million British Thermal Units.

⁽²⁾ Includes the Partnership’s premium received from its sale of an option for it to sell 4,800,000 mmbtu of natural gas at an average price of $15.25 per mmbtu for the year ended December 31, 2007, partially offset by its premium paid from its purchase of an option to purchase 1,200,000 mmbtu of natural gas at $26.00 per mmbtu.

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