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 2007. 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.

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 appearing elsewhere in this report.

General

We are a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol "APL". Our principal business objective is to generate cash for distribution to our unitholders. We are a leading provider of natural gas gathering services in the Anadarko, Arkoma 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, we are a leading provider of natural gas processing and treatment services in Oklahoma and Texas. We also provide interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. Our business is conducted in the midstream segment of the natural gas industry through two reportable segments: our Mid-Continent operations and our Appalachian operations.

Through our Mid-Continent operations, we own and operate:

• a FERC-regulated, 565-mile interstate pipeline system ("Ozark Gas Transmission") that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 400 MMcfd;

• eight active natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing and treating plants or Ozark Gas Transmission, as well as third party pipelines.

Through our Appalachian operations, we own and operate 1,600 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Through an omnibus agreement and other agreements between us and Atlas America, Inc., ("Atlas America" - NASDAQ: ATLS) and its affiliates, including Atlas Energy Resources, LLC and subsidiaries ("Atlas Energy"), a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin and a publicly-traded company (NYSE: ATN), we gather substantially all of the natural gas for our Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to our gathering systems wells it operates that are located within 2,500 feet of our gathering systems. We are also party to natural gas gathering agreements with Atlas America and Atlas Energy under which we receive gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas we transport.

Recent Events

In June 2008, we sold 5,750,000 common units in a public offering at a price to the public of $37.52, resulting in approximately $206.6 million of net proceeds. Also in June 2008, we sold 278,000 common units to Atlas Pipeline Holdings, L.P., the parent of our general partner (NYSE: AHD - "AHD"), and 1,112,000 common units to Atlas America, the parent of AHD's general partner, in a private placement at a net price of $36.02, resulting in approximately $50.1 million of net proceeds. In addition, we received approximately $5.4 million from our general partner to maintain its aggregate 2% general partner interest in us.

The net proceeds from the public and private placement offerings of our common units were utilized to fund the early termination of a majority of our crude oil derivative contracts that we entered into as proxy hedges for the prices we receive for the ethane and propane portion of our NGL equity volume. These hedges, which related to production periods ranging from the end of second quarter of 2008 through the fourth quarter of 2009, were put in place simultaneously with our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 (see "Recent Acquisition") and had become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. We estimate that we incurred a charge during the second quarter 2008 of approximately $10.6 million due to the decline in the price correlation of crude oil and

ethane and propane. We terminated these derivative contracts during June and July 2008 at an aggregate net cost of approximately $264.0 million. Our net loss for the nine months ended September 30, 2008 includes a $187.6 million cash derivative expense resulting from the aggregate net payments of $264.0 million to unwind a portion of these derivative contracts.

In June 2008, we issued $250.0 million of 10-year, 8.75% senior unsecured notes (the "8.75% Notes") in a private placement transaction. The sale of the 8.75% Senior Notes generated net proceeds of approximately $244.9 million, which was utilized to repay indebtedness under our senior secured term loan and revolving credit facility.

In June 2008, we obtained $80.0 million of increased commitments to our senior secured revolving credit facility, increasing our aggregate lender commitments to $380.0 million. In connection with this and the previously mentioned transactions, we also amended our senior secured credit facility to, among other things, exclude from the calculation of Consolidated EBITDA the costs associated with the termination of hedging agreements to the extent such costs are financed with or paid out of the net proceeds of an equity offering. In addition, consistent with several other recent energy master limited partnership agreements, our general partner's managing board and conflicts committee approved an amendment to our limited partnership agreement which will allow the cash expenditure to terminate derivative contracts to not reduce distributable cash flow.

Acquisitions

From the date of our initial public offering in January 2000 through June 2008, we have completed seven acquisitions at an aggregate cost of approximately $2.4 billion. Most recently, in July 2007, we acquired control of Anadarko Petroleum Corporation's ("Anadarko" - NYSE: APC) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the "Anadarko Assets"). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which we contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

We funded the purchase price, in part, from our private placement of $1.125 billion of our common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by Atlas Pipeline Holdings, the parent of our general partner. Our general partner, which holds all of our incentive distribution rights, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to us through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Our general partner also agreed that the resulting allocation of incentive distribution rights back to us would be after the general partner receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see "-Partnership Distributions"). We funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings under our senior secured revolving credit facility that matures in July 2013 (see "-Term Loan and Credit Facility").

In connection with this acquisition, we reached an agreement with Pioneer Natural Resources Company ("Pioneer" - NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. We will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options.

Contractual Revenue Arrangements

Our principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect our revenue are:

• the volumes of natural gas we gather, transport and process which, in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

• the transportation and processing fees we receive which, in turn, depend upon the price of the natural gas and NGLs we transport and process, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

In our Appalachian region, substantially all of the natural gas we transport is for Atlas Energy under percentage-of-proceeds ("POP") contracts, as described below, in which we earn a fee equal to a percentage, generally 16%, of the gross sales price for natural gas subject, in most cases, to a minimum of $0.35 to $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since our inception in January 2000, our Appalachian system transportation fee has exceeded this minimum generally. The balance of the Appalachian system natural gas we transport is for third-party operators generally under fixed-fee contracts.

Our Mid-Continent segment revenue consists of the fees earned from our transmission, gathering and processing operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems, and then sell the natural gas, or produced NGLs, if any, off of delivery points on our systems. Under other agreements, we transport natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with our FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with our gathering and processing operations, we enter into the following types of contractual relationships with our producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. Our revenue is a function of the volume of natural gas that we gather and process and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for us to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs we gather and process, with the remainder being remitted to the producer. In this situation, we and the producer are directly dependent on the volume of the commodity and its value; we own a percentage of that commodity and are directly subject to its market value.

Keep-Whole Contracts. These contracts require us, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, we bear 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 we 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 our keep-whole contracts is minimized.

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.

We face competition for natural gas transportation and in obtaining natural gas supplies for our 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 our competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and keep-whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas and NGLs. We believe 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, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe 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. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We are 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 our 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 our assets and operations from such price risks. We do not realize the full impact of commodity price changes because some of our 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 we process and sell, based on estimated unhedged market prices of $0.78, $6.77 and $65.00 for NGLs, natural gas and condensate, respectively, would result in a change to our gross margin for the twelve-month period ending September 30, 2009 of approximately $18.4 million.

Currently, there is an unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and raising additional capital, and an increase in the volatility of our common units. While we have no plans to access debt or equity in the capital markets, should we 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 our
reportable segments for the periods indicated:



                                                           Three Months Ended     Nine Months Ended
                                                             September 30,          September 30,
                                                            2008        2007       2008       2007
Operating data(1):
Appalachia:
Average throughput volume - mcfd                             91,829     71,876     84,007     66,888
Mid-Continent:
Velma system:
Gathered gas volume - mcfd                                   64,386     63,757     64,103     62,531
Processed gas volume - mcfd                                  60,902     61,968     60,972     60,555
Residue gas volume - mcfd                                    48,300     49,502     48,158     47,487
NGL volume - bpd                                              6,595      6,215      6,758      6,386
Condensate volume - bpd                                         308        254        286        222
Elk City/Sweetwater system:
Gathered gas volume - mcfd                                  279,145    299,450    292,307    298,724
Processed gas volume - mcfd                                 243,409    231,152    236,520    224,521
Residue gas volume - mcfd                                   219,945    211,368    213,668    206,011
NGL volume - bpd                                             11,486      9,782     10,874      9,351
Condensate volume - bpd                                         251        143        299        228
Chaney Dell system(2):
Gathered gas volume - mcfd                                  300,467    255,649    278,906    255,649
Processed gas volume - mcfd                                 234,529    249,982    246,365    249,982
Residue gas volume - mcfd                                   250,994    222,508    238,264    222,508
NGL volume - bpd                                             14,128     12,678     13,299     12,678
Condensate volume - bpd                                         759        564        774        564
Midkiff/Benedum system(2):
Gathered gas volume - mcfd                                  143,224    150,061    145,300    150,061
Processed gas volume - mcfd                                 136,656    144,280    138,178    144,280
Residue gas volume - mcfd                                    84,372     93,859     92,352     93,859
NGL volume - bpd                                             18,920     20,702     20,029     20,702
Condensate volume - bpd                                       1,573      1,754      1,288      1,754
NOARK system:
Average Ozark Gas Transmission throughput volume - mcfd     445,708    325,652    412,634    311,562

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

(2) The Chaney Dell and Midkiff/Benedum systems were acquired on July 27, 2007.

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Revenue. Natural gas and liquids revenue was $404.2 million for the three months ended September 30, 2008, an increase of $174.3 million from $229.9 million for the three months ended September 30, 2007. The increase was primarily attributable to higher revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which we acquired in late July 2007, of $115.9 million and an increase of $17.4 million and $37.9 million from the Velma and Elk City/Sweetwater systems, respectively, due principally to higher commodity prices and an increase in volumes. Processed natural gas volume on the Chaney Dell system was 234.5 MMcfd for the three months ended September 30, 2008, while the Midkiff/Benedum system had processed natural gas volume of 136.7 MMcfd for the same period. Processed natural gas volume averaged 60.9 MMcfd on the Velma system for the three months ended September 30, 2008, a decrease of 1.7% from the comparable prior year period. However, the Velma system increased its NGL production volume by 6.1% when compared to the prior year comparable quarter to 6,595 bpd for the three months ended September 30, 2008, representing an increase in production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 243.4 MMcfd for the three months ended September 30, 2008, an increase of 5.3% from the comparable prior year period. NGL production volume for the Elk City/Sweetwater system was 11,486 bpd, an increase of 17.4% from the prior year

comparable period, as production efficiency of the processing plants has increased. We enter into derivative instruments principally to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected cash flows attributable to changes in market prices. See further discussion of the derivatives under Note 9 under Item 1, "Financial Statements".

Transportation, compression and other fee revenue increased to $24.1 million for the three months ended September 30, 2008 compared with $21.4 million for the prior year comparable period. This $2.7 million increase was primarily due to higher throughput volume on our Appalachia system and an increase in the average transportation rate. The Appalachia system's average throughput volume was 91.8 MMcfd for the three months ended September 30, 2008 as compared with 71.9 MMcfd for the three months ended September 30, 2007, an increase of 27.8%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to our gathering system, the acquisition of the McKean processing plant and gathering system in central Pennsylvania for $6.1 million in August 2007, and the acquisition of the Vinland processing plant and gathering system in northeastern Tennessee for $9.1 million in February 2008. For the NOARK system, average Ozark Gas Transmission volume was 445.7 MMcfd for the three months ended September 30, 2008, an increase of 36.9% from the prior year comparable period, due to an increase in throughput capacity to
400.0 MMcfd near the completion of the third quarter 2007 and higher customer demand.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was income of $153.9 million for the three months ended September 30, 2008, a favorable movement of $162.9 million from the prior year comparable period. This favorable movement was primarily due to a $243.4 million favorable movement in non-cash mark-to-market adjustments, partially offset by a $70.3 million net cash derivative expense related to the early termination of a portion of our crude oil derivative contracts (see "Recent Events") and an unfavorable movement of $17.4 million related to non-qualified derivative cash settlements. The $243.4 million favorable movement in non-cash mark-to-market adjustments was due principally 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 we have for production volumes in future periods. Average forward crude oil market prices, which are the basis for adjusting the fair value of our crude oil derivative contracts, at September 30, 2008 were $102.50 per barrel, a decrease of $37.76 from average forward crude oil market prices at June 30, 2008 of $140.26 per barrel. We enter into derivative instruments principally to hedge our 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 Note 9 under Item 1, "Financial Statements".

Costs and Expenses. Natural gas and liquids cost of goods sold of $316.9 million and plant operating expenses of $16.7 million for the three months ended September 30, 2008 represent increases of $142.2 million and $7.6 million, respectively, from the comparable prior year amounts due primarily to a full quarter's contribution from the Chaney Dell and Midkiff/Benedum systems, which were acquired in late July 2007, higher overall commodity prices and an increase in production volume on the Velma and Elk City/Sweetwater systems. Transportation and compression expenses increased $1.2 million to $4.8 million for the three months ended September 30, 2008 due principally to an increase in Appalachia system operating and maintenance costs as a result of increased capacity, additional well connections and operating costs of the McKean processing plant and gathering system acquired in August 2007 and the Vinland processing plant and gathering system acquired in February 2008.

General and administrative expense (income), including amounts reimbursed to affiliates, decreased $39.6 million to income of $1.8 million for the three months ended September 30, 2008 compared with expense of $37.8 million for the prior year comparable period. This decrease was primarily related to a $44.5 . . .