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.

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 500 MMcfd;

• 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

• 9,100 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 1,835 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 December 2008, we sold 10,000 newly-created 12% cumulative convertible Class B preferred units of limited partner interest (the "Class B Preferred Units") to AHD for cash consideration of $1,000 per Class B Preferred Unit pursuant to a purchase agreement. AHD has the right, before March 30, 2009, to purchase an additional 10,000 Class B Preferred Units on the same terms. We used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. The Class B Preferred Units will receive distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for our common units. See "-Convertible Preferred Units - Class B Preferred Units").

In December 2008, we repurchased approximately $60.0 million in face amount of our senior unsecured notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of our 8.125% senior unsecured notes and approximately $27.0 million in face amount of our 8.75% senior unsecured notes. All of the senior unsecured notes repurchased have been retired and are not available for re-issue.

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 AHD and 1,112,000 common units to Atlas America, Inc. (NASDAQ: ATLS - "ATLS"), 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 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 derivative contracts, 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 "-Significant Acquisitions"). 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. Our net income for the year ended December 31, 2008 includes a net $197.6 million cash derivative expense resulting from the aggregate net payments of $274.0 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% Senior 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 derivative instruments 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.

Subsequent Event

On January 27, 2009, we and Sunlight Capital, the holder of outstanding Class A Preferred Units, agreed to amend certain terms of our existing preferred unit agreement. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price adjustment from $43.00 to $22.00, enabling the Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of our common units, and
(d) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, we issued Sunlight Capital $15.0 million of our 8.125% senior unsecured notes due 2015 to redeem 10,000 Class A Preferred Units. We also agreed that we will redeem an additional 10,000 Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight does not exercise its conversion right on or before June 2, 2009, we will redeem the then-remaining 10,000 Class A Preferred Units for cash or one-half for cash and one-half for our common limited partner units on July 1, 2009.

Significant Acquisitions

From the date of our initial public offering in January 2000 through December 2008, we have completed seven acquisitions at an aggregate cost of approximately $2.4 billion, including, 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"). At the date of acquisition, the Chaney Dell system included 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system included 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 (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"). 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").

In connection with this acquisition, we reached an agreement with Pioneer Natural Resources Company, 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 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 22.0% interest if fully exercised. We will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

• In May 2006, we acquired the remaining 25% ownership interest in NOARK from Southwestern Energy Company ("Southwestern") for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller's interest in working capital at the date of acquisition of $3.5 million. In October 2005, we acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK's principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

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 $0.76 per gallon, $6.50 per mmbtu and $55.00 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending December 31, 2009 by approximately $25.3 million.

Currently, there is an unprecedented level of 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 the price of our common units. While we have no definitive plans to access 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:

                                                              Years Ended December 31,
                                                              2008      2007      2006
Operating data(1):
Appalachia:
Average throughput volumes (mcfd)                             87,299    68,715    61,892
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)                                    63,196    62,497    60,682
Processed gas volume (mcfd)                                   60,147    60,549    58,132
Residue gas volume (mcfd)                                     47,497    47,234    45,466
NGL volume (bpd)                                               6,689     6,451     6,423
Condensate volume (bpd)                                          280       225       193
Elk City/Sweetwater system:
Gathered gas volume (mcfd)                                   280,860   298,200   277,063
Processed gas volume (mcfd)                                  232,664   225,783   154,047
Residue gas volume (mcfd)                                    210,399   206,721   140,969
NGL volume (bpd)                                              10,487     9,409     6,400
Condensate volume (bpd)                                          332       212       140
Chaney Dell system(2):
Gathered gas volume (mcfd)                                   276,715   259,270        -
Processed gas volume (mcfd)                                  245,592   253,523        -
Residue gas volume (mcfd)                                    239,498   221,066        -
NGL volume (bpd)                                              13,263    12,900        -
Condensate volume (bpd)                                          791       572        -
Midkiff/Benedum system(2):
Gathered gas volume (mcfd)                                   144,081   147,240        -
Processed gas volume (mcfd)                                  135,496   141,568        -
Residue gas volume (mcfd)                                     92,019    94,281        -
NGL volume (bpd)                                              19,538    20,618        -
Condensate volume (bpd)                                        1,142     1,346        -
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)      442,464   326,651   249,581

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

(2) Volumetric data for the Chaney Dell and Midkiff/Benedum systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of acquisition, through December 31, 2007.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenue. Natural gas and liquids revenue was $1,370.0 million for the year ended December 31, 2008, an increase of $608.9 million from $761.1 million for the prior year. The increase was primarily attributable to an increase in revenue contribution from the Chaney Dell and Midkiff/Benedum systems, which we acquired in July 2007, of $512.8 million, and an increase from the Velma and Elk City/Sweetwater systems of $26.6 million and $61.8 million, respectively, due primarily to higher average commodity prices over the full year and an increase in volumes. Processed natural gas volume on the Chaney Dell system was 245.6 MMcfd for the year ended December 31, 2008, a decrease of 3.1% compared to 253.5 MMcfd for the period from its July 2007 acquisition to December 31, 2007. The Midkiff/Benedum system had processed natural gas volume of 135.5 MMcfd for the year ended December 31, 2008, a decrease of 4.3% compared to 141.6 MMcfd for the period from its July 2007 acquisition to December 31, 2007 due to the adverse effects of a hurricane which struck the surrounding area in September 2008. Processed natural gas volume averaged 60.1 MMcfd on the Velma system for the year ended December 31, 2008, a decrease of 0.7% from the comparable prior year. However, the Velma system increased its NGL production volume by 3.7% when compared to the prior year to 6,689 bpd for the year ended December 31, 2008, representing an increase in production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 232.7 MMcfd for the year ended December 31, 2008, an

increase of 3.0% from the prior year. NGL production volume for the Elk City/Sweetwater system was 10,487 bpd, an increase of 11.5% from the prior year, as production efficiency of the processing plants has increased. We enter into derivative instruments solely 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 8, "Financial Statements and Supplementary Data".

Transportation, compression and other fee revenue increased to $99.7 million for the year ended December 31, 2008 compared with $81.8 million for the prior year. This $17.9 million increase was primarily due to an $11.0 million increase from the Appalachia system due to higher throughput volume and a higher average transportation rate, $5.4 million of a full year's contributions from the Chaney Dell and Midkiff/Benedum systems, and an increase of $1.7 million associated with the Elk City/Sweetwater system. The Appalachia system's average throughput volume was 87.3 MMcfd for the year ended December 31, 2008 as compared with 68.7 MMcfd for the prior year, an increase of 18.6 MMcfd or 27.0%. 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 442.5 MMcfd for the year ended December 31, 2008, an increase of 35.5% from the prior year due to an increase in throughput capacity to 400.0 MMcfd during the third quarter 2007 and an increase to 500.0 MMcfd during the fourth quarter 2008 and higher customer demand.

Other income (loss) net, including the impact of certain gains and losses recognized on derivatives, was a loss of $55.5 million for the year ended December 31, 2008, which represents a favorable movement of $118.6 million from the prior year loss of $174.1 million. This favorable movement was due primarily to a $356.8 million favorable movement in non-cash mark-to-market adjustments on derivatives, partially offset by a net cash loss of $200.0 million and a non-cash derivative loss of $39.2 million related to the early termination of a . . .