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 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 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. 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.

As of September 30, 2009, through our Mid-Continent operations, we own and operate:

• 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

• 8,750 miles of active natural gas gathering systems located in Oklahoma, 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 third party pipelines.

As of September 30, 2009, our Appalachia operations are conducted principally through our 49% ownership interest in Laurel Mountain Midstream, LLC ("Laurel Mountain"), 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. We also own 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 AHD and 1,112,000 of our common limited partnership units, representing a 2.2% ownership interest in us, at September 30, 2009.

Recent Events

On July 13, 2009, we sold a natural gas processing facility and a one-third undivided interest in other associated assets located in

our 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 us for its proportionate share of the operating expenses. We will continue to operate the facility. We used the proceeds from this transaction to reduce outstanding borrowings under our senior secured credit facility. We 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, our agreement with Pioneer Natural Resources Company ("Pioneer"), whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Mid-Continent's Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2 under Item 1, "Financial Statements").

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.

Our 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 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. 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.

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 $0.80 per gallon, $5.61 per mmbtu and $72.03 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin 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. 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:



                                           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 we have a 49% ownership interest, beginning on May 31, 2009.

Financial Presentation

On May 4, 2009, we completed the sale of our 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 the Chaney Dell system of $78.3 million, the Midkiff/Benedum system of $47.2 million, the Elk City/Sweetwater system of $45.3 million and the 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. We enter into derivative instruments 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 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 the Appalachia system and a $1.5 million decrease from the Chaney Dell system. The decrease from the Appalachia system was due to our contribution of the system to Laurel Mountain, a joint venture in which we have a 49% ownership interest, in May 2009, after which we have recognized our 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 our ownership interest in the net income of Laurel Mountain, a joint venture in which we own 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 our sale of the natural gas processing facility (see "-Recent Events"), partially offset by a $1.0 million adjustment to the gain on the sale of the 51% ownership interest in our Appalachia natural gas gathering system to Laurel Mountain.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a gain of $4.1 million for the three months ended September 30, 2009, which represents an unfavorable movement of $149.8 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 non-cash mark-to-market adjustments on derivatives and a $5.2 million unfavorable movement related to 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 the early termination of a portion of our derivative contracts (see Note 12 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 the early termination of a portion of our 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 we 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. We enter into derivative instruments 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 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 the 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 our contribution of the Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, increased $11.5 million to $8.8 million for the three months ended September 30, 2009 compared with income of $2.7 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 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 our 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 our expansion capital expenditures incurred subsequent to September 30, 2008.

Interest expense increased to $28.3 million for the three months ended September 30, 2009 as compared with $22.1 million for the comparable prior year period. This $6.2 million increase was primarily due to a $4.2 million increase in interest expense associated with outstanding borrowings on our revolving credit facility, (see "-Term Loan and Revolving Credit Facility"), $1.2 million of lower interest capitalized as a component of capital expenditures and a $1.0 million increase in interest expense associated with our senior secured term loan.

Income from discontinued operations, which consists of amounts associated with the NOARK gas gathering and interstate pipeline system we sold in May 2009, was $6.5 million for the three months ended September 30, 2008.

Income attributable to non-controlling interests was a net income reduction of $1.0 million for the three months ended September 30, 2009 compared with $2.6 million for the comparable prior year period. This decrease was primarily due to lower net income for the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. The income attributable to non-controlling interests represents Anadarko's 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

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

Revenue. Natural gas and liquids revenue was $526.5 million for the nine months ended September 30, 2009, a decrease of $660.2 million from $1,186.7 million for the comparable prior year period. The decrease was primarily attributable to decreases in production revenue from the Chaney Dell system of $246.4 million, the Midkiff/Benedum system of $175.1 million, the Elk City/Sweetwater system of $127.6 million and the Velma system of $108.4 million, which were all impacted by lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume averaged 73.4 MMcfd on the Velma system for the nine months ended September 30, 2009, an increase of 20.3% from the comparable prior year period. The Midkiff/Benedum system had average processed natural gas volume of 149.5 MMcfd for the nine months ended September 30, 2009, an increase of 8.2% from the comparable prior year period. Processed natural gas volume on the Elk City/Sweetwater system averaged 223.4 MMcfd for the nine months ended September 30, 2009, a decrease of 5.5% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was an average of 11,361 bpd, an increase of 4.5% from the comparable prior year period, representing an increase in plant production efficiency. Processed natural gas volume on the Chaney Dell system averaged 216.4 MMcfd for the nine months ended September 30, 2009, a decrease of 12.2% compared to 246.4 MMcfd for the comparable prior year period. However, the Chaney Dell system's NGL production volume increased 2.1% from the comparable prior year period to 13,574 bpd for the nine months ended September 30, 2009, representing an increase in plant production efficiency. We enter into derivative instruments 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 Item 3, "Quantitative and Qualitative Discussion About Market Risk".

Transportation, compression and other fee revenue decreased to $29.5 million for the nine months ended September 30, 2009 compared with $49.3 million for the comparable prior year period. This $19.8 million decrease was primarily due to a $14.6 million decrease from the Appalachia system and a $4.6 million decrease from the Chaney Dell system. The decrease from the Appalachia

system was due to our contribution of the system to Laurel Mountain, a joint venture in which we have a 49% ownership interest, in May 2009, after which we have recognized our 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 $2.1 million for the nine months ended September 30, 2009 represents our ownership interest in the net income of Laurel Mountain, a joint venture in which we own a 49% interest, for the period from formation on May 31, 2009 through September 30, 2009.

Gain on asset sales of $111.4 million for the nine months ended September 30, 2009 represents the gain recognized on our sale of a 51% ownership interest in our Appalachia natural gas gathering system of $108.9 million and the $2.5 million gain recognized on our sale of the natural gas processing facility (see "-Recent Events").

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a loss of $6.4 million for the nine months ended September 30, 2009, which represents a favorable movement of $240.7 million from the comparable prior year period loss of $247.1 million. This favorable movement was due primarily to the absence in the current year period of $186.1 million of net cash derivative expense related to the early termination of a portion of our derivative contracts, (see Note 12 to the consolidated financial statements in Item 1, "Financial Statements"), a $74.6 million favorable movement in non-cash derivative gains related to the early termination of a portion of our derivative contracts, and a $28.3 million favorable movement related to cash settlements on non-qualified derivatives, partially offset by an unfavorable movement of $43.0 million in non-cash mark-to-market adjustments on derivatives. We enter into derivative instruments 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 Item 3, "Quantitative and Qualitative Discussion About Market Risk".

Costs and Expenses. Natural gas and liquids cost of goods sold of $409.4 million . . .