ATLAS PIPELINE PARTNERS, L.P.

1550 Coraopolis Heights Road

Moon Township, PA 15108

July 22, 2010

H. Christopher Owings

Securities and Exchange Commission

Division of Corporation Finance

100 F. Street, NE

Washington, D.C. 20549-3010

Re: Atlas Pipeline Partners, L.P.

Form 10-K for the Fiscal Year Ended December 21, 2009

Filed March 5, 2010

Current Report of Form 8-K

Filed January 8, 2010

File No. 001-14988

Dear Mr. Owings:

On behalf of Atlas Pipeline Partners, L.P. (the “Company”), this letter responds to the staff’s letter of comment, dated July 8, 2010, with respect to the above-referenced filings. For your convenience, we first restate your comments in italics and then provide the Company’s response.

Form 10-K for the Fiscal Year Ended December 31, 2009

General

1. Our review encompassed Atlas Pipeline Holdings, L.P. and Atlas Pipeline Partners, L.P. In the interests of reducing the number of comments, we have not addressed each registrant with a separate comment. Page references relate to the Form 10-K of Atlas Pipeline Partners, L.P. To the extent a comment is applicable to more than one registrant, please address the issue separately.

No response necessary.

Selected Financial Data, page 42

2. We note your calculation of EBITDA includes adjustments for impairment charges. As such, the non-GAAP measure should not be characterized as EBITDA. When you include an adjustment that is not included in the definition of EBITDA as set forth in Item 10(e) of Regulation S-K, please

revise the title of the non-GAAP measure to clearly identify the measure being used and all adjustments. For additional guidance, please refer to the Division’s Non-GAAP Financial Measures Compliance and Disclosure Interpretation Question and Answer 103.01, available on our website at http://sec.gov/divisions/corpfin/guidance/nongaapinterp.htm.

The Company notes that the inclusion of impairment charges should not be included in EBITDA as set forth in Item 10(e) of Regulation S-K. In future filings, the Company will remove all impairment charges from EBITDA and will include them only in Adjusted EBITDA with the required reconciliation of net income to EBITDA and Adjusted EBITDA. This will include the reclassification of this item for all prior periods. See the proposed disclosure below in our response to comment 3.

3. You disclose that your Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation under your credit facility. Please expand your disclosure to state the items that comprise the difference between Adjusted EBITDA and Consolidated EBITDA as defined in your credit agreement referred to in Note 12.

The Company advises the staff that the differences between Adjusted EBITDA and Consolidated EBITDA as defined in the Company’s credit facility, if any, have been non-cash items specifically excluded under the Consolidated EBITDA definition. The Company will expand its disclosure to state any differences between Adjusted EBITDA and Consolidated EBITDA.

The Company proposes to include disclosure substantially similar to the following in Selected Financial Data to address comments 2 and 3 (reclassifications marked by “>” and bolded):

EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, and impairment charges, and other cash items such as the non-recurring cash derivative early termination expense (see “Item 8: Financial Statements and Supplementary Data —Note 12). EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing EBITDA and Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation below is similar to the Consolidated EBITDA (see “Item 8: Financial Statements and Supplementary Data —Note 14) calculation under our credit facility, with the exception that Adjusted EBITDA includes proceeds received from our joint venture note receivable, the unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition, and other non-cash items specifically excluded under our credit facility.

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Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost of capital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles or as indicators of our operating performance or liquidity. The following table reconciles net income (loss) to EBITDA and EBITDA to Adjusted EBITDA (in thousands):

RECONCILIATION OF EBITDA AND ADJUSTED EBITDA

	Years Ended December 31,
	2009			2008			2007			2006			2005
Net income (loss)	$	62,714		$	(604,698	)	$	(140,369	)	$	33,783		$	26,835
Adjustments:
Effect of prior period items		—			—			—			1,090			(1,090	)
(Income) loss attributable to non-controlling interests from continuing operations		(3,176	)		22,781			(3,940	)		—			—
Interest expense		103,629			85,991			62,592			23,698			13,448
Interest rate swap expense in other income (loss), net		443			—			—			—			—
Depreciation and amortization		92,434			82,841			43,903			16,759			12,976
> Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition		—			—			10,423			—			—
(Income) loss attributable to non-controlling interests from discontinued operations		—			—			—			(118	)		(1,083	)
NOARK depreciation and amortization		2,773			7,283			7,079			6,235			978
> NOARK interest expense		29			(1,148	)		(1,066	)		874			727
EBITDA	$	258,846		$	(406,950	)	$	(21,378	)	$	82,321		$	52,791
Adjustments:
Equity income in joint venture		(4,043	)		—			—			—			—
Distributions from joint venture		4,310			—			—			—			—
Long-lived asset impairment loss		10,325			—			—			—			—
Goodwill impairment loss, net of associated non-controlling interest		—			646,189			—			—			—
NOARK asset impairment		—			21,648			—			—			—
Non-cash portion of gain on asset sale		(78,053	)		—			—			—			—
Non-cash (gain) loss on derivatives		51,342			(115,767	)		169,424			(2,316	)		(954	)
Non-recurring cash derivative early termination expense		5,000			197,641			—			—			—
Non-cash compensation (income) expense		701			(34,010	)		36,306			6,315			4,672
Non-cash line fill loss (gain)		(3,899	)		7,797			(2,270	)		820			—
Other non-cash items		—			—			1,414			—			—
Adjusted EBITDA	$	244,529		$	316,548		$	183,496		$	87,140		$	56,509

Note 3 – Investment in Joint Venture, page 95

4. We note you recognized a gain of $108.9 million on the sale of your 51% ownership interest in Laurel Mountain where you retained the remaining 49% ownership interest. Please revise to disclose the valuation technique used to measure the fair value of the 49% interest retained. Refer to FASB ASC 810-10-50.

3

The gain of $54.2 million associated with the revaluation of the Company’s 49% interest retained was determined based on the value received for the 51% interest sold. The Company proposes the following disclosure to be included in future filings (changes bolded):

On May 31, 2009, the Partnership and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates the Partnership’s Appalachia natural gas gathering system, excluding the Partnership’s northeastern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which the Partnership received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. The Partnership contributed the Appalachia natural gas gathering system and retained a 49% ownership interest in Laurel Mountain. The Partnership is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams obtained the remaining 51% ownership interest in Laurel Mountain.

Upon completion of the transaction, the Partnership recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheet at fair value. During the year ended December 31, 2009, the Partnership recognized a gain on sale of $108.9 million, including $54.2 million associated with the revaluation of the Partnership’s investment in Laurel Mountain to fair value. The revaluation of the retained investment was determined based upon the value received for the 51% contributed to the Laurel Mountain joint venture.

5. Please advise us of your basis for classifying the equity in earnings in your joint venture as revenue. Refer to Rule 5-03(b)12 of Regulation S-X.

Rule 5-03(b)12 of Regulation S-X requires “Equity in Earnings of Unconsolidated Subsidiaries and 50 Percent or Less Owned Persons” to be reported as a separate line item in the income statement. The Company will adjust its Consolidated Statements of Operations in future filings to reclassify “Equity income in joint venture” from “Revenue” to a separate line item below “Total costs and expenses” and to continue to include it in “Income (loss) from continuing operations.” The Company proposes to include the following presentation in future filings (reclassifications marked by “>” and bolded):

Revenue:

Natural gas and liquids

Transportation, compression, processing and other fees– affiliates

Transportation, compression, processing and other fees– third parties

>

Other income (loss), net

Total revenue and other income (loss), net

Costs and expenses:

Natural gas and liquids

Plant operating

Transportation and compression

General and administrative

Compensation reimbursement – affiliates

Depreciation and amortization

Interest

Total costs and expenses

Equity income in joint venture

Gain on asset sale

Income (loss) from continuing operations

Discontinued operations:

Gain on sale of discontinued operations

Income from discontinued operations

Income from discontinued operations

Net income (loss)

Income attributable to non-controlling interests

Preferred unit dividends

Net income (loss) attributable to common limited partners and the general partner

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6. Please advise us of the accounting literature or predominate practice that supports classification of the gain on asset sale of $111.4 million as revenue.

The Company notes that FASB ASC 225-20-45-16 states: “A material event or transaction that is unusual in nature or occurs infrequently but not both, and therefore does not meet both criteria for classification as an extraordinary item, shall be reported as a separate component of income from continuing operations.” Accordingly, the Company will adjust its Consolidated Statements of Operations in future periods to reclassify “Gain on asset sale” from “Revenue” to a separate line item below “Total costs and expenses” and to continue to include it in “Income (loss) from continuing operations.” The Company proposes to include the following presentation in future filings (reclassifications marked by “>” and bolded):

Revenue:

Natural gas and liquids

Transportation, compression, processing and other fees– affiliates

Transportation, compression, processing and other fees– third parties

>

Other income (loss), net

Total revenue and other income (loss), net

Costs and expenses:

Natural gas and liquids

Plant operating

Transportation and compression

General and administrative

Compensation reimbursement – affiliates

Depreciation and amortization

Interest

Total costs and expenses

Equity income in joint venture

Gain on asset sale

Income (loss) from continuing operations

Discontinued operations:

Gain on sale of discontinued operations

Income from discontinued operations

Income from discontinued operations

Net income (loss)

Income attributable to non-controlling interests

Preferred unit dividends

Net income (loss) attributable to common limited partners and the general partner

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Note 12- Derivative Instruments, page 104

7. We note you discontinued hedge accounting for crude oil derivative instruments in December 2007 and on July 1, 2008 you discontinued hedge accounting for your existing commodity derivatives which were qualified as hedges for accounting purposes. Beginning May 29, 2009 you also discontinued hedge accounting for your interest rate derivatives which were qualified as hedges. With a view towards transparency please tell us and expand your disclosure to provide an overview discussion of your reasons for discontinuing hedge accounting either here or in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

With respect to the crude oil derivative instruments covering forecasted condensate production for 2008 and other future periods for which the Company discontinued hedge accounting during December 2007, the Company advises the staff that the crude oil derivative instruments were dedesignated from the forecasted condensate production due to a reduction in forecasted condensate production, resulting in a portion of the forecasted transactions being no longer expected to occur. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur should be removed from other comprehensive income and recognized within the statements of operations. The dedesignation of hedge accounting for these instruments with respect to the Company’s condensate production resulted in a $12.6 million non-cash derivative loss recognized within “Other income (loss), net” in its Consolidated Statements of Operations, and a corresponding decrease in “Accumulated other comprehensive loss” in “Partners’ Capital” in its Consolidated Balance Sheet for the year ended December 31, 2007. Because these transactions occurred in the Company’s 2007 fiscal year, the Company does not anticipate that it will provide disclosure about them in future filings.

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With respect to all of its commodity derivatives as to which the Company discontinued hedge accounting on July 1, 2008, the Company advises the staff that, during 2008, certain crude oil derivative instruments designated as hedges for forecasted NGL production had significant ineffective portions of gain/losses due to the unusual fluctuation of crude oil prices during that time period. Though the hedges continued to qualify for hedge accounting based upon the correlation of prices calculated through regression analysis, the significant ineffectiveness of the hedges along with the Company’s expectation that future degradation of the correlation would cause the hedges to no longer qualify for hedge accounting caused the Company to prudently move to discontinue hedge accounting for all of its commodity-based derivative contracts, including effective natural gas derivative contracts, for consistency in application. The Company proposes to include the following disclosure in future filings (changes bolded):

On July 1, 2008, the Partnership discontinued hedge accounting for certain existing qualified crude oil derivatives utilized to hedge forecasted NGL production due to significant ineffectiveness. The Partnership also discontinued hedge accounting for all of its other qualified commodity derivatives for consistency in reporting of all commodity-based derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in its consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within Partners’ Capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss), net in its consolidated statements of operations as they occur.

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With respect to the interest rate derivatives for which the Company discontinued hedge accounting beginning May 29, 2009, the Company advises the staff that, on May 29, 2009, it entered into an amendment to its credit facility agreement which, among other changes, set a floor for the adjusted LIBOR interest rate of 2.0% per annum, as disclosed in its Note 14 to its Consolidated Financial Statements in the Form 10-K. Due to the change in the related forecasted transactions, the Company discontinued hedge accounting for its interest rate derivatives. The Company proposes to include the following disclosure in future filings (changes bolded):

At December 31, 2009, the Partnership had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, the Partnership will pay weighted average interest rates of 3.0%, plus the applicable margin as defined under the terms of its credit facility (see Note 14), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreements were in effect as of December 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. On May 29, 2009, the Partnership entered into an amendment to its credit facility agreement which, among other changes, set a floor for the adjusted LIBOR interest rate (see Note 14). Beginning May 29, 2009, due to the change in the related forecasted transaction that caused it to no longer correlate to the derivative instrument, the Partnership discontinued hedge accounting for its interest rate derivatives which previously were qualified as hedges. As such, subsequent changes in the fair value of these derivatives will be recognized immediately within other income (loss), net in its consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized in accumulated other comprehensive loss within Partners’ Capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged interest rates affect earnings. For non-qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss), net in its consolidated statements of operations as they occur.

Current Report on Form 8-K filed January 8, 2010

8. We reviewed your Current Report on Form 8-K filed with us on January 8, 2010, that reported the amendment of your warrant agreement to reduce temporarily the per warrant cash exercise price from $6.35 to $6.00 for the period from January 8, 2010 through January 12, 2010. Please provide us with your analysis explaining why the temporary reduction in the exercise price of the warrants was not an issuer tender offer subject to Exchange Act Rule 13e-4 and Regulation 14E. See, e.g., Heritage Entertainment, Inc. (May 11, 1987).

8

The Company believes that the reduction in warrant exercise price did not constitute an issuer tender offer, based upon the following facts:

• There were only four holders of the warrants, each of which was a highly sophisticated institutional investor (and two of which were advised by the same investment advisor).

• The number of common units for which the warrants were exercisable was approximately 5% of the Company’s then outstanding common units.

• The transaction was heavily negotiated between the Company and the investors before entering into the warrant amendment.

• There was no “pressure” to enter into the warrant amendment, particularly since the investors could retain their existing warrants without change.

• Because of the very limited number of holders, there was no publicity or public solicitation.

• The warrant amendment was not contingent upon holders representing a minimum number of warrants agreeing to the amendment, nor was a maximum set: the Company was willing to execute an amendment with any or all holders.

• The negotiations leading to the warrant amendment had no expressed or implied time limit.

• Assuming (without necessarily agreeing) that a reduction in warrant exercise price is a “premium,” the reduction in exercise price was $0.35 (approximately 5.1%) and, the Company believes, not material. By contrast, the reduction in Heritage Entertainment, Inc. (May 11, 1987), cited in your comment, was approximately 16.7%.

Based upon the foregoing facts, the Company believes that none of the factors cited by the court in Wellman v. Dickinson, 475 F. Supp. 783 (S.D.N.Y. 1979), that would result in a transaction being deemed a tender offer was present in this transaction. The Company notes that other courts, under similar circumstances, have held that there was no tender offer involved. See Hanson Trust PLC v. SCM Corp., 774 F.2d 47 (2d. Cir. 1985) (five private purchases from institutional investors and one open market purchase for an aggregate of approximately 25% of the outstanding common stock did not constitute a tender offer); Stromfeld v. The Great Atlantic & Pacific Tea Co., 496 F. Supp. 1084 (S.D.N.Y. 1980) (privately negotiated acquisition of 42% of common stock from seven selling shareholders was not a tender offer); Pin v. Texaco, Inc., 793 F.2d 1448 (5^th Cir. 1986) (private purchases from a small group of highly sophisticated sellers did not constitute a tender offer);

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University Bank and Trust Company v. Gladstone, 574 F. Supp. 1006 (D. Mass. 1983) (solicitation of options to purchase stock constituting 22% of outstanding stock from 49 shareholders was not a tender offer); Kennecott Copper Corp. v. Curtiss-Wright Corp., 584 F.2d 1195 (2d. Cir. 1978) (offers to 12 institutional stockholders plus open market purchases was not a tender offer); and Brascan, Ltd. v. Edper Equities, Ltd., 477 F. Supp. 773 (S.D.N.Y. 1979) (solicitation of between 30 to 50 institutional investors and purchases from 12 other institutional investors was not a tender offer).

Accordingly, and particularly in view of the small number of highly sophisticated institutional investors involved and the heavily negotiated and non-public nature of the transaction, the Company concluded that the warrant amendment did not constitute a tender offer.

The Company hereby acknowledges that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

ATLAS PIPELINE PARTNERS, L.P.
By:	Atlas Pipeline Partners GP, LLC
By:	/s/ Robert W. Karlovich, III
Name:	Robert W. Karlovich, III
Title:	Chief Accounting Officer

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