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 the year ended December 31, 2011. 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 and with our Annual Report on Form 10-K for the year ended December 31, 2011.

Overview

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol "APL." We are a leading provider of natural gas gathering and processing services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwestern region of the United States.

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Gathering and Processing; and Pipeline Transportation.

The Gathering and Processing segment consists of (1) the WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins; (2) the natural gas gathering assets located in Tennessee; and (3) the revenues and gain on sale related to our former 49% interest in Laurel Mountain. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and gathering and processing of natural gas.

Our Gathering and Processing operations, own, have interests in and operate seven natural gas processing plants with aggregate capacity of approximately 610 MMCFD, which are connected to approximately 9,000 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas. In addition, we own and operate approximately 100 miles of active natural gas gathering systems located in Tennessee. Our gathering systems gather gas from wells and central delivery points and deliver to natural gas processing plants, as well as third-party pipelines.

Our Pipeline Transportation operations consist of a 20% interest in West Texas LPG Pipeline Limited Partnership ("WTLPG"), which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation ("Chevron" -NYSE: CVX), which owns the remaining 80% interest.

Recent Events

In February 2012, we acquired a gas gathering system and related assets, within our WestOK system, for an initial net purchase price of $19.0 million. We agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. In connection with this acquisition, we received assignment of gas purchase agreements for gas currently gathered on the acquired system. We accounted for the acquisition as a business combination.

On May 31, 2012, we entered into an amendment to the revolving credit facility agreement, which among other changes: (1) increased the revolving credit facility from $450.0 million to $600.0 million; (2) extended the maturity date from December 22, 2015 to May 31, 2017; (3) reduced the Applicable Margin used to determine interest rates by 0.50%; (4) revised the negative covenants to
(i) permit investments in joint ventures equal to the greater of 20% of Consolidated Net Tangible Assets (as defined in the Credit Agreement) or $340 million, provided the Partnership meets certain requirements, and (ii) increased the general investment basket to 5% of Consolidated Net Tangible Assets;
(5) revised the definition of "Consolidated EBITDA" to provide for the inclusion of the first twelve months of projected revenues for identified capital expansion projects, upon completion of the projects; and (6) provided for the option of additional revolving credit commitments of up to $200.0 million.

In June 2012, we completed construction of, and started processing through, a 60 MMCFD cryogenic facility at the Velma gas plant, increasing capacity at Velma to 160 MMCFD. This expansion supports our long-term fee-based agreement with XTO Energy, Inc., a subsidiary of ExxonMobil, to provide natural gas gathering and processing services for up to an incremental 60 MMCFD from the Woodford Shale.

In June 2012, we acquired a gas gathering system and related assets in the Barnett Shale play in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system consists of 19 miles of gathering pipeline that is used to facilitate gathering some of the newly acquired production for our affiliate, Atlas Resources Partners, L.P. ("ARP"). We accounted for the acquisition as a business combination.

How We Evaluate Our Operations

Our principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Our profitability is a function of the difference between the revenues we receive and the costs associated with conducting our operations, including the cost of natural gas and NGLs we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Variables that affect our profitability are:

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

• the price of the natural gas we gather and process and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

• the contract terms with each producer; and

• the efficiency of our gathering systems and processing plants.

Revenue consists of the sale of natural gas and NGLs and the fees earned from our 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 and NGLs off delivery points on our systems. Under other agreements, we gather natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. (See "Item
1. Notes to Consolidated Financial Statements (Unaudited) -Note 2-Revenue Recognition" for further discussion of contractual revenue arrangements).

Our management uses a variety of financial measures and operational measurements other than our GAAP financial statements to analyze our performance. These include: (1) volumes, (2) operating expenses and (3) the following non-GAAP measures - gross margin, adjusted EBITDA and distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

Volumes. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production. Our performance at our plants is also significantly impacted by the quality of the natural gas we process, the NGL content of the natural gas and the plant's recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations.

Operating Expenses. Plant operating and transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, ad valorem taxes and other overhead costs.

Gross Margins. We define gross margin as natural gas and liquids sales plus transportation, compression and other fees less purchased product costs, subject to certain non-cash adjustments. Product costs include the cost of natural gas and NGLs we purchase from third parties. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories.

Gross margin is a non-GAAP measure. The GAAP measure most directly comparable to gross margin is net income. Gross margin is not an alternative to GAAP net income and has important limitations as an analytical tool. Investors should not consider gross margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of gross margin may not be comparable to gross margin measures of other companies, thereby diminishing its utility.

EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA

other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as non-recurring cash derivative early termination expense. The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation utilized within our financial covenants under our credit facility, with the exception that Adjusted EBITDA includes certain non-cash items specifically excluded under our credit facility and excludes the capital expansion add back included in Consolidated EBITDA as defined in the credit facility (see "-Revolving Credit Facility").

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as indicators of our operating performance or liquidity. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. We define distributable cash flow as net income plus depreciation and amortization; amortization of deferred financing costs included in interest expense; and non-cash gain (losses) on derivative contracts, less income attributable to non-controlling interests, preferred unit dividends, maintenance capital expenditures, gain (losses) on asset sales and other non-cash gain (losses).

Distributable cash flow is a significant performance metric used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can compute the ratio of distributable cash flow per unit to the declared cash distribution per unit to determine the rate at which the distributable cash flow covers the distribution. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income or GAAP cash flows from operating activities. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measurements used by management to their most directly comparable GAAP measures for the three and six months ended June 30, 2012 and 2011 (in thousands):

                         RECONCILIATION OF GROSS MARGIN



                                              Three Months Ended               Six Months Ended
                                                   June 30,                        June 30,
                                             2012            2011           2012             2011

Net income                                 $  74,851       $  8,819       $  81,322       $  250,393
Derivative (gain) loss, net(1)               (67,847 )       (6,837 )       (55,812 )         14,808
Other income, net(1)                          (2,588 )       (2,745 )        (5,003 )         (5,534 )
Operating expenses(2)                         14,812         13,532          28,957           26,490
General and administrative expense(3)         10,445          8,655          20,390           17,672
Other costs                                     (161 )          575            (195 )            575
Depreciation and amortization                 21,712         19,123          42,554           38,028
Interest                                       9,269          6,145          17,977           18,590
Equity income in joint ventures               (1,917 )         (687 )        (2,813 )         (1,149 )
(Gain) loss on asset sale(4)                      -             273              -          (255,593 )
Loss on early extinguishment of debt              -          19,574              -            19,574
Non-cash linefill (gain) loss(5)               2,223          1,357           2,495              243


Gross margin                               $  60,799       $ 67,784       $ 129,872       $  124,097

     RECONCILIATION OF EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW



                                              Three Months Ended                Six Months Ended
                                                   June 30,                         June 30,
                                             2012            2011            2012             2011

Net income                                 $  74,851       $   8,819       $  81,322       $  250,393
Income attributable to non-controlling
interests(6)                                  (1,061 )        (1,545 )        (2,597 )         (2,732 )
Interest expense                               9,269           6,145          17,977           18,590
Depreciation and amortization                 21,712          19,123          42,554           38,028


EBITDA                                       104,771          32,542         139,256          304,279
Equity income in joint ventures               (1,917 )          (687 )        (2,813 )         (1,149 )
Distributions from joint ventures              1,800              -            3,600            1,764
(Gain) loss on asset sale                         -              273              -          (255,593 )
Loss on early extinguishment of debt              -           19,574              -            19,574
Non-cash (gain) loss on derivatives          (64,741 )       (13,788 )       (54,045 )          4,572
Premium expense on derivative
instruments                                    3,984           3,710           7,736            6,715
Non-cash compensation                          2,940             502           3,918            1,679
Non-cash line fill (gain) loss(5)              2,223           1,357           2,495              243


Adjusted EBITDA                               49,060          43,483         100,147           82,084
Interest expense                              (9,269 )        (6,145 )       (17,977 )        (18,590 )
Amortization of deferred finance costs         1,130           1,034           2,295            2,301
Preferred dividend obligation                     -             (149 )            -              (389 )
Proceeds remaining from asset sale(7)             -               -               -             5,850
Premium expense on derivative
instruments                                   (3,984 )        (3,710 )        (7,736 )         (6,715 )
Other costs                                     (161 )           575            (195 )            575
Maintenance capital                           (4,000 )        (5,211 )        (8,510 )         (8,471 )


Distributable Cash Flow                    $  32,776       $  29,877       $  68,024       $   56,645

(1) Adjusted to separately present derivative gain (losses) instead of combining these amounts in other income, net.

(2) Operating expenses include plant operating expenses; and transportation and compression expenses.

(3) General and administrative includes compensation reimbursement to affiliates.

(4) Represents the gain on sale of Laurel Mountain and an adjustment to the gain on sale of our Elk City system.

(5) Represents the non-cash impact of commodity price movements on pipeline linefill.

(6) Represents Anadarko's non-controlling interest in the operating results of the WestOK and WestTX systems.

(7) Net proceeds remaining from the sale of Laurel Mountain after repayment of the amount outstanding on our revolving credit facility, redemption of our 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018.

Results of Operations

The following table illustrates selected pricing before the effect of
derivatives and volumetric information for the periods indicated:



                                              Three Months Ended June 30,                 Six Months Ended June 30,
                                                                      Percent                                    Percent
                                            2012          2011         Change          2012          2011         Change
Pricing:

Weighted Average Market Prices:
NGL price per gallon - Conway hub        $     0.70     $    1.16        (39.7 )%    $    0.82     $    1.12        (26.8 )%
NGL price per gallon - Mt. Belvieu hub         0.94          1.34        (29.9 )%         1.06          1.27        (16.5 )%

Natural gas sales ($/Mcf):
Velma                                          2.04          4.11        (50.4 )%         2.29          4.05        (43.5 )%
WestOK                                         2.09          4.14        (49.5 )%         2.30          4.05        (43.2 )%
WestTX                                         1.85          4.12        (55.1 )%         2.18          4.03        (45.9 )%
Weighted Average                               2.01          4.13        (51.3 )%         2.26          4.05        (44.2 )%

NGL sales ($/gallon):
Velma                                          0.71          1.16        (38.8 )%         0.82          1.10        (25.5 )%
WestOK                                         0.79          1.17        (32.5 )%         0.85          1.12        (24.1 )%
WestTX                                         0.88          1.36        (35.3 )%         1.03          1.28        (19.5 )%
Weighted Average                               0.80          1.25        (36.0 )%         0.92          1.18        (22.0 )%

Condensate sales ($/barrel):
Velma                                         93.69        101.57         (7.8 )%        98.52         96.51          2.1 %
WestOK                                        85.41         93.68         (8.8 )%        90.00         89.29          0.8 %
WestTX                                        86.17        100.42        (14.2 )%        91.11         96.66         (5.7 )%
Weighted Average                              87.00         98.23        (11.4 )%        91.95         93.79         (2.0 )%

Operating data:

Velma system:
Gathered gas volume (MCFD)                  136,553       102,159         33.7 %       132,888        96,418         37.8 %
Processed gas volume (MCFD)                 129,070        96,625         33.6 %       125,987        90,923         38.6 %
Residue gas volume (MCFD)                   106,424        78,381         35.8 %       103,380        74,072         39.6 %
NGL volume (BPD)                             14,220        11,367         25.1 %        13,931        10,722         29.9 %
Condensate volume (BPD)                         434           442         (1.8 )%          499           486          2.7 %
WestOK system:
Gathered gas volume (MCFD)                  336,377       260,250         29.3 %       315,787       252,257         25.2 %
Processed gas volume (MCFD)                 315,753       247,868         27.4 %       297,529       238,925         24.5 %
Residue gas volume (MCFD)                   291,225       230,605         26.3 %       271,582       214,711         26.5 %
NGL volume (BPD)                             14,379        13,204          8.9 %        14,220        13,397          6.1 %
Condensate volume (BPD)                       1,209           884         36.8 %         1,307           871         50.1 %
WestTX system(1):
Gathered gas volume (MCFD)                  267,395       204,515         30.7 %       256,867       195,268         31.5 %
Processed gas volume (MCFD)                 236,213       193,714         21.9 %       233,359       183,323         27.3 %
Residue gas volume (MCFD)                   164,593       133,012         23.7 %       162,308       124,512         30.4 %
NGL volume (BPD)                             32,755        29,147         12.4 %        32,928        28,316         16.3 %
Condensate volume (BPD)                       1,941         1,827          6.2 %         1,440         1,428          0.8 %
Tennessee system:
Average throughput volumes (MCFD)             8,348         7,675          8.8 %         8,286         7,876          5.2 %
WTLPG system(1):
Average NGL volumes (BPD)                   243,708       230,913          5.5 %       243,013       227,087          7.0 %

(1) Operating data for WestTX and WTLPG represent 100% of the operating activity for the respective systems.

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

The following table and discussion is a summary of our consolidated results of
operations for the three months ended June 30, 2012 and 2011 (in thousands):



                                                   Three Months Ended
                                                        June 30,                             Percent
                                                  2012          2011(1)       Variance        Change
Gross margin(2)
Natural gas and liquids sales                   $ 238,801      $ 330,168      $ (91,367 )       (27.7 )%
Transportation, processing and other fees          14,878         10,435          4,443          42.6 %
Less: non-cash line fill gain (loss)(3)            (2,223 )       (1,357 )         (866 )       (63.8 )%
Less: natural gas and liquids cost of sales       195,103        274,176        (79,073 )       (28.8 )%

Gross margin                                       60,799         67,784         (6,985 )       (10.3 )%

Expenses:
Operating expenses                                 14,651         14,107            544           3.9 %
General and administrative(4)                      10,445          8,655          1,790          20.7 %
Depreciation and amortization                      21,712         19,123          2,589          13.5 %
Interest expense                                    9,269          6,145          3,124          50.8 %

Total expenses                                     56,077         48,030          8,047          16.8 %

Other income items:
Derivative gain (loss), net(1)                     67,847          6,837         61,010         892.4 %
Other income, net(1)                                2,588          2,745           (157 )        (5.7 )%
Non-cash line fill gain (loss)(3)                  (2,223 )       (1,357 )         (866 )       (63.8 )%
. . .