Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our December 31, 2008 Annual Report on Form 10-K as modified by our Current Report on Form 8-K as filed with the SEC on May 18, 2009 for the retrospective applications of changes to the generally accepted accounting principles for the presentation of non-controlling interest and the calculation of earnings per share. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors.

Overview

We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast and northeast regions of the United States, including the Marcellus Shale, and are the largest natural gas processor in the Appalachian region.

Significant financial and other highlights for the three months ended September 30, 2009 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

º •
º Total segment operating income before items not allocated to segments decreased approximately $20.7 million, or 20%, for the three months ended September 30, 2009 compared to the same period in 2008. The decrease is due primarily to significantly lower NGL and natural gas prices in 2009. The decrease related to commodity prices was partially offset by the following:

º •
º increased gathered and processed volumes in the Southwest segment due to the 2008 acquisition of the Stiles Ranch gathering system, the continued expansion of the Woodford gathering system including the start of operations for the Arkoma Connector Pipeline, and the expansion of the processing facilities in western Oklahoma and East Texas.

º •
º increased contracted volumes from a large producer and expansion of the processing facilities in the Northeast segment.

º •
º continued expansion of our Marcellus Shale operations in the Liberty segment which commenced in October 2008.

º •
º During the three months ended September 30, 2009, the prices of NGLs relative to the price of crude oil have been significantly below the historical averages. This has reduced the effectiveness of our hedging program and has adversely impacted our cash flows and results of operations.

º •
º In July 2009, we received the remaining $31.3 million in proceeds from the sale of a 50% equity interest in MarkWest Pioneer.

º •
º In July 2009, we received an additional $50.0 million of contributions to MarkWest Liberty Midstream from M&R.

º •
º In August 2009, we received net proceeds of $121.0 million from a public offering of approximately 6.03 million newly issued common units.

º •
º In September 2009, we sold the SMR for proceeds of approximately $73.1 million.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure) which is defined as revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss). These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our usage of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

The following is a reconciliation to income (loss) from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

                                               Three months ended       Nine months ended
                                                 September 30,            September 30,
                                               2009         2008        2009        2008
Revenue                                      $ 207,933   $  303,560   $ 576,300   $ 866,760
Purchased product costs                         91,086      171,539     274,052     479,747

   Net operating margin                        116,847      132,021     302,248     387,013
Facility expenses                               30,165       28,213      93,945      75,641
Total derivative (income) loss                    (595 )   (193,489 )   105,249      85,905
Selling, general and administrative
expenses                                        15,477       15,331      46,265      54,406
Depreciation                                    25,264       17,510      69,621      48,533
Amortization of intangible assets               10,193       10,732      30,638      28,050
Other operating expenses                           689           38       1,579         106
Impairment of long-lived assets                      -            -       5,855       5,009

   Income (loss) from operations             $  35,654   $  253,686   $ (50,904 ) $  89,363

We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. We provide services under the following different types of arrangements:

º •
º Fee-based arrangements: Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments or fixed demand charges. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced.

º •
º Percent-of-proceeds arrangements: Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. The percentage of volumes that we retain can be either fixed or variable. Generally, under these types of arrangements our revenues and gross margins increase as natural gas, condensate and NGL prices increase, and our revenues and net operating margins decrease as natural gas, condensate and NGL prices decrease. Due to current market and financial conditions, we have seen decreases in natural gas, condensate and NGL prices, and it is uncertain if prices will remain at these lower levels in the future.

º •
º Percent-of-index arrangements: Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to
(1) and (3) above, the net operating margins we realize under the arrangements decrease in periods of low natural gas prices because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.

º •
º Keep-whole arrangements: Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require us to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio. Accordingly, under these arrangements our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.

º •
º Settlement margin: Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent that we operate our gathering systems more or less efficiently than specified per contract allowance, we will retain the benefit or loss for our own account.

The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common, and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix will influence our long-term financial results.

The following table is prepared as if we did not have an active commodity risk management program in place. For further discussion of how we have reduced the downside volatility to the portion of our net operating margin that is not fee-based, see Note 6 of the accompanying Notes to the Condensed Consolidated Financial Statements. For the nine months ended September 30, 2009, we

calculated the following approximate percentages of our revenue and net operating margin from the following types of contracts:

            Fee-Based     Percent-of-Proceeds(1)     Percent-of-Index(2)     Keep-Whole(3)    Total
Revenue             22 %                       37 %                     7 %              34 %    100 %
Net
operating
margin              41 %                       27 %                     3 %              29 %    100 %


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   º (1)

º (2)
º Includes settlement margin and other types of arrangements tied to natural gas prices.

º (3)
º Includes settlement margin, condensate sales and other types of arrangements tied to both NGL and natural gas prices.

While the percentages in the table above accurately reflect the percentages by contract type, we manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis. When the partial offset of our natural gas positions is considered, the calculated percentages for the net operating margin in the table above for percent-of-proceeds, percent-of-index and keep-whole contracts change to 43%, 0% and 16%, respectively.

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment is particularly impacted by seasonality. In the Appalachia area, we store a portion of the propane that is produced in the summer to be sold in the winter months. As a result of our seasonality, we generally expect the sales volumes in our Northeast segment to be higher in the first quarter and fourth quarter.

Results of Operations

We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We capture information in this MD&A by segment. The segment information appearing in Note 19 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting.

º •
º East Texas. Our East Texas system consists of natural gas gathering pipelines, centralized compressor stations, a natural gas processing facility and an NGL pipeline. The East Texas system is located in Panola, Harrison and Rusk Counties and services the Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations, which collectively form one of the largest natural gas producing regions in the United States. For natural gas that is processed in this segment, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we transport volumes for a fee.

º •
º Oklahoma. We own the Foss Lake natural gas gathering system and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas

wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant. We also own and operate a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants and our Grimes gathering system that is located in Roger Mills and Beckham Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. In July 2008, we acquired a subsidiary of PetroQuest Energy, L.L.C. ("PetroQuest") that owns natural gas gathering assets located primarily in Pittsburg County in southeast Oklahoma as part of our expansion of the Woodford gathering system.

On May 1, 2009, we entered into a joint venture with ArcLight in which ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile interstate pipeline that provides approximately 638,000 Dth/d of Woodford Shale takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline. A complete discussion of the formation of and accounting treatment for MarkWest Pioneer appears in Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements.

º •
º Other Southwest. We own a number of natural gas gathering systems in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico.

º •
º Appalachia. We are the largest processor of natural gas in the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb and Kermit natural gas processing plants, an NGL pipeline, the Siloam NGL fractionation plant and two caverns for storing propane.

º •
º Michigan. We own and operate a crude oil pipeline in Michigan as well as a natural gas gathering system in Manistee County, Michigan.

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º MarkWest Liberty Gas Gathering, L.L.C. and MarkWest Liberty Midstream & Resources, L.L.C. We operate natural gas gathering systems and processing facilities located primarily in western Pennsylvania and northern West Virginia. Prior to February 27, 2009, we owned a 100% interest in these assets through MarkWest Liberty Gas Gathering, L.L.C., a wholly-owned subsidiary. On February 27, 2009, we contributed these assets to a newly-formed entity, MarkWest Liberty Midstream, and sold a 40% interest in MarkWest Liberty Midstream to M&R. Effective November 1, 2009, we and M&R executed the Amended Liberty Agreement that will increase M&R's ownership interest to 49% by January 1, 2011. A complete discussion of the formation of and accounting treatment for MarkWest Liberty Midstream appears in Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements. MarkWest Liberty Midstream currently operates a mechanical refrigeration plant with a design capacity of 60 MMcf/d and a cryogenic processing facility with a design capacity of 30 MMcf/d that was

placed into service in the second quarter of 2009. We plan on adding a second cryogenic facility with a capacity of 120 MMcf/d by late 2009 or early 2010.

º •
º Javelina. We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, that treats and processes off-gas from six local refineries.

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by identifiable segment, for the nine months ended September 30, 2009:

Southwest Northeast Liberty Gulf Coast Total Revenue 59 % 29 % 5 % 7 % 100 % Net operating margin 63 % 16 % 8 % 13 % 100 %

Equity investments in unconsolidated affiliates

Starfish. We own a 50% non-operating membership interest in Starfish, a joint venture with Enbridge Offshore Pipelines, L.L.C. that is accounted for using the equity method. The financial results of Starfish are included in Earnings (loss) from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in our segment results. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All of these assets are located in the Gulf of Mexico or southwestern Louisiana.

Centrahoma. We own a 40% non-operating membership interest in Centrahoma, a joint venture with Antero Midstream Resources Corporation that is accounted for using the equity method. The financial results of Centrahoma are included in Earnings (loss) from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in our segment results. Centrahoma owns certain processing plants in the Arkoma Basin. We have signed agreements to dedicate our processing rights in certain acreage in the Woodford Shale to Centrahoma through March 1, 2018.

Three months ended September 30, 2009, compared to three months ended September 30, 2008

Items below Income (loss) from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The

tables below present information about operating income for the reported segments for the three months ended September 30, 2009 and 2008.

                                   Southwest

                                              Three months ended
                                                September 30,
                                               2009        2008      $ Change    % Change
                                                      (in thousands)
Revenue                                      $ 123,792   $ 192,675   $ (68,883 )       (36 )%
Operating expenses:
     Purchased product costs                    53,425     120,208     (66,783 )       (56 )%
     Facility expenses                          17,893      16,670       1,223           7 %

Total operating expenses before items not
allocated to segments                           71,318     136,878     (65,560 )       (48 )%
Portion of operating income attributable
to non-controlling interests                       980           -         980         N/A

Operating income before items not
allocated to segments                        $  51,494   $  55,797   $  (4,303 )        (8 )%

Revenue. Revenue decreased primarily due to lower commodity prices. Revenue from NGL, natural gas and condensate sales decreased across the segment by $72.9 million. The change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas also contributed to the decline in revenue. The effect of the decrease in commodity prices on NGL sales was partially offset by increased volumes processed at our East Texas facilities and increased volumes processed at the Arapaho facilities associated with the Stiles Ranch gathering system that began operations in the fourth quarter of 2008. The revenue declines associated with lower commodity prices were also partially offset by a $4.7 million increase in gathering, treating, and transportation fee revenue due to the continued expansion of our operations in the Woodford, including the start of the Arkoma Connector Pipeline operations.

Purchased Product Costs. NGL and natural gas purchases decreased due primarily to lower commodity prices as well as the contract change with a significant producer in the Other Southwest areas.

Facility Expenses. Facility expenses increased due primarily to the expansion of our western Oklahoma gathering and processing operations related to the development of Stiles Ranch, and increased repairs and maintenance resulting from the completed non-recurring environmental remediation costs in East Texas.

Portion of Operating Income Attributable to Non-controlling Interests. Portion of operating income attributable to non-controlling interest represents our partners' share in the net operating income of MarkWest Pioneer and Wirth Gathering Partnership.

Operating results for the three months ended September, 30, 2008 were adversely impacted by business interruptions caused by Hurricane Ike. Management estimated that the financial impact of these business interruptions was a $2.6 million reduction of operating income. Excluding the impact of Hurricane Ike, operating income decreased $6.9 million, or 12%, during the three months ended September 30, 2009 compared to the same period in 2008.

                                   Northeast

                                              Three months ended
                                                September 30,
                                               2009         2008     $ Change    % Change
                                                      (in thousands)
Revenue                                      $   55,554   $ 82,418   $ (26,864 )       (33 )%
Operating expenses:
    Purchased product costs                      34,506     51,331     (16,825 )       (33 )%
    Facility expenses                             4,832      6,172      (1,340 )       (22 )%

Total operating expenses before items not
allocated to segments                            39,338     57,503     (18,165 )       (32 )%

Operating income before items not
allocated to segments                        $   16,216   $ 24,915   $  (8,699 )       (35 )%

Revenue. Revenue decreased due primarily to lower commodity prices realized on NGL sales from the Appalachia region. The decrease in revenue from lower commodity prices was partially offset by increased volumes which resulted from upgrades to our processing facilities in this area, and increased volumes from a producer in the Appalachia region.

Purchased Product Costs. Purchased product costs decreased due to lower prices for the natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area. The effect of the lower prices was partially offset by the increase in volumes.

Facility Expenses. Facility expenses decreased due primarily to ceasing our natural gas gathering and processing operations in Western Michigan during the third quarter of 2009.

                                    Liberty

                                               Three months ended
                                                 September 30,
                                                 2009          2008    $ Change    % Change
                                                       (in thousands)
Revenue                                      $      12,790      $  -    $ 12,790     N/A
Operating expenses:
     Purchased product costs                         3,155         -       3,155     N/A
     Facility expenses                               3,435         -       3,435     N/A
. . .