Forward-Looking Statements

When used in this Form 10-Q, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption "Risk Factors", in our annual report on Form 10-K for 2008. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report.

Overview

We are a publicly-traded Delaware limited partnership (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC ("Atlas Pipeline GP"), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. ("APL" - NYSE: APL). APL is a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian regions. Our cash generating assets currently consist solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, their general partner, which owns at September 30, 2009:

• a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

• all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL's acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see "-Atlas Pipeline Partners, L.P."), we, the holder of all the incentive distribution rights in APL, agreed to allocate up to $3.75 million of our incentive distribution rights per quarter back to APL (the "IDR Adjustment Agreement"). We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive the initial $7.0 million per quarter of incentive distribution rights.

• 5,754,253 common units of APL, representing approximately 11.4% of the outstanding common units of APL, or a 11.2% limited partner interest in APL; and

• 15,000 $1,000 par value 12.0% cumulative preferred limited partner units.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Our ownership of APL's incentive distribution rights entitles us to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle us, subject to the IDR Adjustment Agreement, to receive the following:

• 13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter;

• 23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and

• 48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter.

These amounts are partially offset by our agreement to allocate up to $3.75 million of incentive distributions per quarter back to APL. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive the initial $7.0 million per quarter of incentive distribution (see "-APL's Partnership Distributions").

We pay to our unitholders, on a quarterly basis, distributions equal to the cash we received from APL, less certain reserves for expenses and other uses of cash, including:

• our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

• capital contributions to maintain or increase our ownership interest in APL; and

• reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

We did not declare a cash distribution for the quarters ended September 30, 2009, June 30, 2009 or March 31, 2009. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes, prohibited us from paying any cash distributions on our equity while the credit facility is in effect (see "-Our Credit Facility").

Atlas Pipeline Partners, L.P.

APL is a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol "APL". APL's principal business objective is to generate cash for distribution to its unitholders. APL is a leading provider of natural gas gathering services in the Anadarko and Permian Basins and the Golden Trend in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. APL's business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

As of September 30, 2009, through its Mid-Continent operations, APL owns and operates:

• eight active natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

As of September 30, 2009, APL's Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain Midstream, LLC ("Laurel Mountain" - see "Recent Events"), a joint venture which owns and operates a 1,770 mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. APL also owns a 65 mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy, Inc. and its subsidiaries ("Atlas Energy"), a publicly-traded company (NASDAQ:
ATLS) which owns a 64.4% ownership interest in us and 1,112,000 of APL's common limited partnership units, representing a 2.2% ownership interest, at September 30, 2009.

Financial Presentation

We currently have no separate operating activities apart from those conducted by APL, and our cash flows consist of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a component of equity on our consolidated balance sheet. Throughout this section, when we refer to "our" consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL's financial results, adjusted for non-controlling partners' interest in APL's net income (loss).

Recent Events

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on our consolidated statements of operations.

Subsequent Events

On November 2, 2009, APL's agreement with Pioneer Natural Resources Company ("Pioneer"), whereby Pioneer had an option to purchase up to an additional 22.0% interest in APL's Mid-Continent's Midkiff/Benedum system, expired without Pioneer exercising its option (see - "Principles of Consolidation and Non-Controlling Interest" under Note 2).

On October 13, 2009, we repaid an additional $4.0 million of our outstanding credit facility borrowings in accordance with the credit facility amendment (see
- "Atlas Pipeline Holdings Credit Facility" under Note 13). The $4.0 million was advanced by Atlas Energy under its guaranty of our credit facility debt (see - "Atlas Pipeline Holdings Subordinate Loan with Atlas Energy" under Note 13).

Contractual Revenue Arrangements

APL's principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect its revenue are:

• the volumes of natural gas APL gathers, transports and processes which, in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

APL's Mid-Continent segment revenue consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with APL's gathering and processing operations, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL's revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the "processing margin risk") that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL's keep-whole contracts is minimized.

Revenue in APL's Appalachia segment is principally recognized at the time the natural gas is transported through its gathering systems.

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

APL faces competition for natural gas transportation and in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of high-quality customer relationships. Many of APL's competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We

believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL's POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which APL believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. We closely monitor the risks associated with commodity price changes on APL's future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of APL's assets and operations from such price risks. APL does not realize the full impact of commodity price changes because some of its sales volumes were previously hedged at prices different than actual market prices. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells, based on estimated unhedged market prices of $0.80 per gallon, $5.61 per mmbtu and $72.03 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ending September 30, 2010 by approximately $24.3 million.

Currently, there is an unprecedented level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL's borrowing capabilities and APL's raising additional capital, and an increase in the volatility of the price of our and APL's common units. While we and APL have no definitive plans to access the capital markets, should we and APL decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Results of Operations

The following table illustrates selected volumetric information related to APL's
reportable segments for the periods indicated:



                                           Three Months Ended     Nine Months Ended
                                             September 30,          September 30,
                                            2009        2008       2009       2008
    Operating data(1):
    Appalachia:
    Average throughput volume - mcfd(2)     105,989     91,829    104,009     84,007
    Mid-Continent:
    Velma system:
    Gathered gas volume - mcfd               81,562     64,386     75,919     64,103
    Processed gas volume - mcfd              78,714     60,902     73,351     60,972
    Residue gas volume - mcfd                62,219     48,300     57,959     48,158
    NGL volume - bpd                          8,922      6,595      8,158      6,758
    Condensate volume - bpd                     389        308        383        286
    Elk City/Sweetwater system:
    Gathered gas volume - mcfd              211,287    279,145    228,630    292,307
    Processed gas volume - mcfd             200,182    243,409    223,438    236,520
    Residue gas volume - mcfd               181,011    219,945    203,034    213,668
    NGL volume - bpd                         10,792     11,486     11,361     10,874
    Condensate volume - bpd                     260        251        374        299
    Chaney Dell system:
    Gathered gas volume - mcfd              268,723    300,467    282,756    278,906
    Processed gas volume - mcfd             202,516    234,529    216,407    246,365
    Residue gas volume - mcfd               218,420    250,994    238,167    238,264
    NGL volume - bpd                         13,376     14,128     13,574     13,299
    Condensate volume - bpd                     750        759        861        774
    Midkiff/Benedum system:
    Gathered gas volume - mcfd              166,423    143,224    160,631    145,300
    Processed gas volume - mcfd             152,314    136,656    149,516    138,178
    Residue gas volume - mcfd               104,895     84,372    103,078     92,352
    NGL volume - bpd                         19,926     18,920     21,006     20,029
    Condensate volume - bpd                   1,942      1,573      1,426      1,288

(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, a joint venture in which APL has a 49% ownership interest, beginning on May 31, 2009.

Financial Presentation

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system. As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenue. Natural gas and liquids revenue was $194.4 million for the three months ended September 30, 2009, a decrease of $202.3 million from $396.7 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL's Chaney Dell system of $78.3 million, APL's Midkiff/Benedum system of $47.2 million, APL's Elk City/Sweetwater system of $45.3 million and APL's Velma system of $30.3 million, which were all impacted by lower average commodity prices in comparison to the prior year comparable period. The Velma system had average processed natural gas volume of
78.7 MMcfd for the three months ended September 30, 2009, an increase of 29.2% from the comparable prior year period. The Midkiff/Benedum system had average processed natural gas volume of 152.3 MMcfd for the three months ended September 30, 2009, an increase of 11.5% compared to the comparable prior year period. Processed natural gas volume on the Chaney Dell system averaged 202.5 MMcfd for the three months ended September 30, 2009, a decrease of 13.6% compared to the comparable prior year period. Processed natural gas volume on the Elk City/Sweetwater system averaged 200.2 MMcfd for the three months ended September 30, 2009, a decrease of 17.8% from the comparable prior year period. APL enters into derivative instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, "Quantitative and Qualitative Discussion About Market Risk".

Transportation, compression and other fee revenue decreased to $5.1 million for the three months ended September 30, 2009 compared with $18.0 million for the comparable prior year period. This $12.9 million decrease was primarily due to a $10.8 million decrease from APL's Appalachia system and a $1.5 million decrease from APL's Chaney Dell system. The decrease from the Appalachia system was due to APL's contribution of the system to Laurel Mountain, a joint venture in which APL has a 49% ownership interest, in May 2009, after which we have recognized APL's ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations. The decrease from the Chaney Dell system was due to lower fee-based volumes.

Equity income of $1.4 million for the three months ended September 30, 2009 represents APL's ownership interest in the net income of Laurel Mountain, a joint venture in which APL owns a 49% interest.

Gain on asset sales of $1.5 million for the three months ended September 30, 2009 represents a $2.5 million gain recognized on APL's sale of the natural gas processing facility, partially offset by a $1.0 million adjustment to the gain on APL's sale of the 51% ownership interest in its Appalachia natural gas gathering system to Laurel Mountain.

Other income (loss), net, including the impact of certain gains and losses recognized on APL's derivatives, was a gain of $4.0 million for the three months ended September 30, 2009, which represents an unfavorable movement of $149.9 million from $153.9 million of income for the prior year comparable period. This unfavorable movement was due primarily to a $223.0 million unfavorable movement in APL's non-cash mark-to-market adjustments on derivatives and a $5.2 million unfavorable movement related to APL's cash settlements on non-qualified derivatives, partially offset by the absence in the current year period of $70.3 million of net cash derivative expense related to APL's early termination of a portion of its derivative contracts (see Note 11 to the consolidated financial statements in Item 1, "Financial Statements") and a favorable movement of $9.0 million for non-cash derivative gains related to APL's early termination of a portion of its derivative contracts. The $223.0 million unfavorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $235.0 million gain during the three months ended September 30, 2008, which was due to a decrease in forward crude oil market prices from June 30, 2008 to September 30, 2008 and their favorable mark-to-market impact on certain non-qualified derivative contracts APL had for production volumes in future periods. Average forward crude oil prices, which were the basis for adjusting the fair value of our crude oil derivative contracts, at September 30, 2008, were $102.64 per barrel, a decrease of $37.48 per barrel from average forward crude oil market prices at June 30, 2008 of $140.12 per barrel. APL enters into derivative instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, "Quantitative and Qualitative Discussion About Market Risk".

Costs and Expenses. Natural gas and liquids cost of goods sold of $145.0 million for the three months ended September 30, 2009 represented a decrease of $169.3 million from the prior year comparable period due primarily to a decrease in average commodity prices in comparison to the prior year comparable period. Plant operating expenses of $14.8 million for the three months ended September 30, 2009 represented a decrease of $1.2 million from the prior year comparable period due primarily to a $1.5 million decrease associated with APL's Chaney Dell system resulting from lower operating and maintenance costs. Transportation and compression expenses decreased to $0.1 million for the three months ended September 30, 2009 compared with $2.9 million for the prior year comparable period due to APL's contribution of its Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, increased $11.3 million to $9.5 million for the three months ended September 30, 2009 compared with income of $1.8 million for the prior year comparable period. The increase was primarily due to a $13.3 million mark-to-market gain recognized during the three months ended September 30, 2008 for certain APL common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in APL's common unit market price at September 30, 2008 when compared with the June 30, 2008 price, which was utilized in the estimate of the non-cash compensation expense for these awards.

Depreciation and amortization increased to $21.9 million for the three months ended September 30, 2009 compared with $20.7 million for the three months ended September 30, 2008 due primarily to APL's expansion capital expenditures incurred subsequent to September 30, 2008.

Interest expense increased to $29.3 million for the three months ended September 30, 2009 as compared with $22.6 million for the comparable prior year period. This $6.7 million increase was primarily due to a $4.2 million increase . . .